Agenda Packet — Redding City Council, May 5, 2026 (part 2 of 4)

Hour1 + Hour2 + Hour3 + Hour4 + Hour5 + Hour6 + Hour23 + Hour24 = OffPeakPrice The series of equations for hourly spot prices are estimated with different parameters for each month to capture seasonal effects.

Weighting of Data
The default weighting of historic spot market data used for parameter estimation follows a linearly declining function. The default weighting system for market data provides an initial weight for the most recent input spot prices of 730 and 729 for the two-day-old prices. The weights decline daily under the same pattern for three years until they reach a value of 365. All historic quotes older than two years receive a value of 365. Thus, yesterday’ s quote receives twice the weight in the parameter estimation process as a value that is two years old. Users can adjust the default weighting formula to their own weighting function through the UI.

Reporting Requirement
SimEngine produces basis price simulations over the forecast horizon. The summary statistics can be viewed in the standard output reports, which focus on the mean, 5th, and 95th percentile simulation results.

Packet Pg. 300 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve SCHINSTOCK, BRIANAppendix D D-9
POWERSIMM PLANNER – SIMULATION TO CAPTURE MEANINGFUL

UNCERTAINTY
PowerSimm is a dispatch optimization and production cost tool. The tool is comprised of two major elements, the Sim Engine and Dispatch Optimization, that work together to systematically bridge the physical and financial dimensions of electricity provision. PowerSimm uses a simulation- based approach to perform decision analysis for portfolio risk management and considers the volatility in important variables such as load, fuel price, power price, weather, renewable generation, load and system constraints, and outages.

Figure D-6 PowerSimm' s Sim Engine captures " Meaningful Uncertainty" in weather, load, renewables, and prices
The simulation of uncertainty with respect to weather is becoming ever more critical because weather conditions can be thought of as a new vital parameter in California’ s emerging highrenewables system. To capture the changing market dynamics with renewables, PowerSimm simulates weather conditions to capture the effect on renewable output and its effect on energy price formation. This is part of the process of characterizing meaningful uncertainty by considering realistic paths of weather that, in turn, drives renewable production, market prices, and net utility loads.

PowerSimm is a stochastic construct model and each expansion plan simulation actually includes 100 or more simulations that allow all possible future states specified through ( appropriately correlated) model inputs and forecasts to be considered probabilistically. Figure D-7 demonstrates the value of PowerSimm’ s stochastic approach. The orange line represents the result of a single deterministic ( non- probabilistic) run that would have been calculated based on single values for model inputs such as load and market price. Conversely, using the probabilistic approach, PowerSimm models multiple possible outcomes stochastically, as represented by the blue bar plots in Figure D-7, and characterizes a full distribution of possible outcomes of portfolio cost. This enables the determination of the most likely cost ( black bar in the figure representing the mean results) associated with the input variables and forecasts. PowerSimm can make resource Packet Pg. 301 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve SCHINSTOCK, BRIANAppendix D D-10
decisions based not only on the mean of the distribution, but also by risk considerations informed by the 5th and 95th percentiles. Therefore, the model can solve for the optimal resource portfolio that strikes the best balance between cost and risk.

Using the probabilistic approach, the modeling results for a single run produce a range of possible outcomes for variables subject to uncertainty and for which a probability profile is entered. This means that multiple, single variable sensitivity runs need not be performed to understand the impact of uncertainty in one or more variables. For the simulations, a single cost result was generated for each of the Scenarios evaluated, and no additional sensitivity analyses were performed as is typically done in deterministic modeling approaches.

Figure D-7 The Value of Stochastic Analysis in Resource Planning Using Risk Premium for Resource Decision Making
PowerSimm also identifies the risk associated with each energy portfolio option, quantifying this as the “risk premium.” Since different energy portfolios have different simulated cost distributions, the risk premium will be larger for wider cost distributions, or riskier portfolios, and smaller for narrower cost distributions, or less risky portfolios. Ascend then adds the risk premium variable to the expected value to put all energy portfolio options on the same playing field. The factors that drive risk in total portfolio cost include fuel price risk, carbon price risk, and other influential inputs that face uncertainty.

The risk premium is defined as the probability- weighted average of costs above the median, and this concept is illustrated below in Figure D-8:

Packet Pg. 302 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve SCHINSTOCK, BRIANAppendix D D-11
Figure D-8 Risk Premium is an Economic Concept Measuring how Prone a Portfolio is to Higher than Expected Costs
PowerSimm planner monetizes risk through applying an actuarial option approach where the value of risk (the risk premium) is calculated as the integral of the cost distribution from the mean to the upper tail of costs, reflecting the downside risk to ratepayers. The underlying cost distribution follows from production cost modeling determined through input simulations of market fuel prices and weather-> load->renewables. These underlying simulations are developed to satisfy a long set of validation criteria to ensure “ meaningful” uncertainty is reflected in the final distribution of costs.

Packet Pg. 303 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve SCHINSTOCK, BRIANAppendix E E-1
Appendix E. RPS Compliance and Enforcement Document
Procedure No:

RPS- 001
Version:
3 Approval
Date:
06/05/18 RPS Policies &
Effective Date: June 5, 2018 Procedures
Document Owner: Nick Zettel

REDDING ELECTRIC UTILITY
Resources Division
RPS-001 Renewables Portfolio
Standard Procurement and
Enforcement Plan
Reviewed By:

Nick Zettel (Electric Manager – Resources), Bill Hughes ( Electric Manager – Resources), Dan Beans ( Electric Utility Director) Adopted By: Redding City Council
Date: June 5, 2018
Packet Pg. 304 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve SCHINSTOCK, BRIANAppendix E E-2

TABLE OF CONTENTS

1. Introduction......................................................................................................... 3

1.1 Utility Code ................................................................................................ 3

2. RPS Procurement Plan ...................................................................................... 3

2.1 Purpose ..................................................................................................... 3

2.2 Compliance Periods and Procurement Targets ......................................... 4

2.3 Portfolio Content Categories ...................................................................... 5 A. PCC1: ( RPS Enforcement Regulations 3203(a)) ........................... 5 B. PCC2: ( RPS Enforcement Regulations Section 3203(b)) .............. 6 C. PCC3: ( RPS Enforcement Regulations section 3203( c)) ............... 7 D. PCC0: ( RPS Enforcement Regulations section 3204(a)(2)) ........... 7

2.4 Redding’ s Plan for RPS Compliance ......................................................... 8

2.4.1 Existing Eligible Renewable Resources .......................................... 8

2.4.2 Procurement Plan for Future Renewable Resources ...................... 8

3. RPS Enforcement Program ............................................................................... 9

3.1 Enforcement Policy .................................................................................... 9

3.2 Optional Compliance Measures ............................................................... 10 A. Excess Procurement: .................................................................... 10 B. Delay of Timely Compliance: ........................................................ 10 C. Cost Limitations for Expenditures:................................................. 10 D. Portfolio Balance Requirement Reduction: ................................... 11

4. Review and Updating Requirements .............................................................. 11

5. Review and Revision History .......................................................................... 12 Packet Pg. 305 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve SCHINSTOCK, BRIANAppendix E E-3

1. Introduction
Senate Bill 2 in the First Extraordinary Session ( SBX1- 2)17 defines the California Renewables Portfolio Standard ( RPS) and imposes minimum renewable energy procurement targets for all retail sellers and publicly- owned utilities ( POUs), including the City of Redding ( Redding).

SBX1- 2 authorized the California Energy Commission ( CEC) to develop procedures for enforcement of the RPS for POUs. As part of that enforcement authority, the CEC adopted Enforcement Procedures for the Renewables Portfolio Standard for Local, Publicly- Owned Electric Utilities” ( RPS Enforcement Regulations). 18 This document describes Redding’ s RPS Procurement and Enforcement Plan, as required by the Public Utility Code, which must be approved by Redding’ s City Council.

1.1 Utility Code
REU must comply with many state laws that govern certain aspects of utility operations. These include the following code sections, which relate to California’ s Renewable Portfolio Standard:

Renewable Portfolio Standard requirement Public Utilities Code (PUC) § 399.30(a)(1) Compliance Period and Procurement Targets PUC § 399.30(b) and (c) Portfolio Content Categories PUC § 399.16(b) and (c)
RPS POU Compliance PUC § 399.30(n)
Optional Compliance Measures PUC § 399.30(d)

2. RPS Procurement Plan

2.1 Purpose
The purpose of the RPS Procurement Plan is to identify the policies and procedures for Redding to meet the RPS requirements and any future adopted state- defined renewable goals.

The most recent adoption, SB350, mandates that 50 percent of retail sales must be created by eligible renewable energy sources by 2030. SB350 also requires Redding to produce an Integrated Resource Plan that will guide the Procurement Plan. 17 SBX1- 2 (Simitian, Stats. 2011, Ch. 1) was signed by California’ s Governor on April 12, 2011, and made significant revisions to Public Utilities Code § s 399.11-399. 32, the California Renewables Portfolio Standard Program. Various provisions of § 399.11, et seq., were subsequently modified.
18 The CEC adopted the RPS Enforcement Regulations on June 12, 2013, in Order No. 13 -0612- 5.

Packet Pg. 306 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve SCHINSTOCK, BRIANAppendix E E-4

2.2 Compliance Periods and Procurement Targets
Compliance periods are multiyear, required targets. Although Compliance Periods 1 and 2 have passed, they are included below for reference:

A. Compliance Period 1
1) During Compliance Period 1, January 1, 2011, to December 31, 2013, Redding shall procure, at a minimum, renewable energy resources equivalent to an average of 20 percent of retail sales over the three ( 3) years of the compliance period.

Expressed as:

10.0 EP 2011 + EP 2012 + EP 2013 . 20 (RS 2011 + RS 2012 + RS 2013) Where:

RS X = total retail sales made by POU for the specified year X.

EP X = electricity products procured for the specified year X; this may include excess procurement and historic carryover that the POU has chosen to apply to the compliance period containing year X.

B. Compliance Period 2
1) For Compliance Period 2, January 1, 2014, to December 31, 2016, Redding shall procure renewable energy resources to meet or exceed the sum of 20 percent of retail sales for each of 2014 and 2015, and 25 percent of retail sales for 2016.

Expressed as:

11.0 EP 2014 + EP 2015 + EP 2016 0.20(RS 2014) + 0.20 (RS 2015) +

0.25 (RS 2016)
C. Compliance Period 3
1) For Compliance Period 3, January 1, 2017, to December 31, 2020, Redding shall procure renewable energy resources to meet or exceed 33 percent of retail sales by 2020. During the intervening years of Compliance Period 3, Redding shall increase procurement to reflect an imputed compliance obligation.

Expressed as:

EP 2017 + EP 2018 + EP 2019 + EP 2020)

0.27 (RS 2017) + 0.29 (RS 2018) + 0.31 (RS 2019) + 0.33 (RS 2020) D. Compliance Periods beyond 2020
1) Compliance periods beyond 2020 are not formally established; however, SB350 requires a 50 percent renewable standard by 2030.

The following table summarizes the annual “ soft” targets, but compliance is determined over the entire compliance period using the formulas above.

Compliance Period 3
2017 2018 2019 2020 … 2030
Packet Pg. 307 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve SCHINSTOCK, BRIANAppendix E E-5
27% 29% 31% 33% 50%
Table 1: RPS Renewable Requirement

2.3 Portfolio Content Categories
In addition to meeting the renewable energy procurement target, the RPS established Portfolio Content Categories ( PCC) that outline the eligible renewable energy resource products that must be procured to ensure compliance with minimum and maximum values as summarized in Table 2.

A. PCC1: ( RPS Enforcement Regulations 3203( a))
1) PCC1 electricity products must be bundled at the time of procurement to be classified as PCC1, and the POU may not resell the underlying electricity from the electricity product back to the eligible renewable energy resource from which the electricity product was procured. The electricity products must be generated by an eligible renewable energy resource that is interconnected to a transmission network within the Western Electricity Coordinating Council ( WECC) service territory. For purposes of this section 3203, the first point of interconnection to the WECC transmission grid is the substation, or other facility, where generation tie lines interconnect from the eligible renewable energy resource to the network transmission grid.
a) Electricity products must be generated by an eligible renewable energy resource that has its first point of interconnection within the metered boundaries of a California balancing authority area.
b) Electricity products must be generated by an eligible renewable energy resource that has its first point of interconnection to an electricity distribution system used to serve end-users within the metered boundaries of a California balancing authority area. For purposes of this section 3203, the first point of interconnection to an electricity distribution system is within the service area boundaries of a utility distribution company.
c) Electricity products from the eligible renewable energy resource with a first point of interconnection outside the metered boundaries of a California balancing authority area must be scheduled into a California balancing authority area without substituting electricity from another source. For purposes of this section 3203, electricity generated by the eligible renewable energy resource must be scheduled into a California balancing authority area on an hourly or sub -hourly basis. The POU’s governing board, or other authority as delegated by the POU governing board, must have approved an agreement before the electricity is generated to schedule the electricity from the eligible renewable energy resource into the California balancing authority area on an hourly or sub - hourly basis. If there is a difference between the amount of electricity generated within an hour and the amount of electricity scheduled into a California balancing authority area within that same hour, only the lesser of the two amounts shall be classified as PCC1.

Packet Pg. 308 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve SCHINSTOCK, BRIANAppendix E E-6
d) Electricity products must be subject to an agreement between a California balancing authority area and the balancing authority in which the eligible renewable energy resource is located and executed before the product is generated to dynamically transfer electricity from the eligible renewable energy resource into the California balancing authority area.
3) Electricity products originally qualifying in PCC1 that do not meet the criteria of section 3203 (a)(2)(A) and are resold – ( D) shall not be counted in PCC1.

B. PCC2: ( RPS Enforcement Regulations Section 3203( b)) 1) PCC2 electricity products must be generated by an eligible renewable energy resource that is interconnected to a transmission network within the WECC service territory, and the electricity must be matched with incremental electricity that is scheduled into a California balancing authority area.
2) PCC2 electricity products must be bundled when procured and must meet all of the following criteria:
a) The first point of interconnection to the WECC transmission grid for both the eligible renewable energy resource and the resource providing the incremental electricity must be located outside the metered boundaries of a California balancing authority area.
b) The incremental electricity used to match the electricity from the eligible renewable energy resource must be incremental to the POU. For purposes of this section 3203, “incremental electricity” means electricity that is generated by a resource located outside the metered boundaries of a California balancing authority area; prior to the date of contract or ownership agreement, electricity is not in the portfolio of the POU claiming the electricity products for RPS compliance from eligible renewable energy resources with which the incremental electricity is being matched; is executed by the POU, or other authority, as delegated by the POU governing board.
c) The governing board, or other authority as delegated by the governing board, executes the contract or ownership agreement for the incremental electricity at the same time or after the contract or ownership agreement for the electricity products from the eligible renewable energy resource is executed. d) The incremental electricity must be scheduled into the California balancing authority area within the same calendar year as the electricity from the eligible renewable energy resource is generated.
e) The electricity from the eligible renewable energy resource must be available to be procured by the POU and may not be sold back to that resource.

C. PCC3: ( RPS Enforcement Regulations section 3203( c)) Packet Pg. 309 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve SCHINSTOCK, BRIANAppendix E E-7
All unbundled renewable energy credits and other electricity products procured from eligible renewable energy resources located within the WECC transmission grid that do not meet the requirements of either PCC1 or PCC2 fall within PCC3.

D. PCC0: ( RPS Enforcement Regulations section 3204( a)(2)) 1) Any contract or ownership agreement originally executed prior to June 1, 2010, shall count in full toward the procurement requirements if all of the following conditions are met:
a) The renewable energy resource met the Commission’ s RPS eligibility requirements that were in effect when the original procurement or ownership agreement was executed.
b) Any contract amendments or modifications occurring after June 1, 2010, do not increase the nameplate capacity, expected quantities of annual generation, or substitute a different renewable energy resource.
c) If contract amendments or modifications after June 1, 2010, increase nameplate capacity or expected quantities of annual generation, increase the term of the contract, or substitute a different eligible renewable energy resource, only the MWhs or resources procured prior to June 1, 2010, shall count in full toward the RPS procurement targets. The remaining procurement must be classifie d into PCC1, 2, or 3, and follow the portfolio balance requirements in accordance with RPS Enforcement Regulations section 3204 ( c).
d) The duration of the contract may be extended if the original contract specified a procurement commitment of fifteen ( 15) years or more.

Compliance Period 1
2011- 2013
Compliance Period 2
2014- 2016
Compliance Period 3
2017- 2020
PCC1 ( Minimum) 50% 65% 75%
PCC2 ( No Direct Restriction) n/a n/a n/a
PCC3 ( Maximum) 25% 15% 10%
PCC0 Is not subject to portfolio balancing requirements Beyond 2020 is to be determined
Table 2: RPS Balancing Requirement

2.4 Redding’s Plan for RPS Compliance

2.4.1 Existing Eligible Renewable Resources
Redding currently has the following renewable energy resources under contract and/or ownership that meet the RPS eligibility requirements:

Wind
Big Horn Wind Project (PCC0) - In 2006, Redding entered into a 20-year contract with possible 5-year extension for wind energy through the M-S-R Public Power Agency by participation in the Big Horn Wind Project. Redding has contracted for 70 MW of capacity that yields approximately 180,000 MWh of eligible renewable energy annually.

Packet Pg. 310 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve SCHINSTOCK, BRIANAppendix E E-8
Hydro (< 30MW)
Whiskeytown Hydro ( PCC0) - In the mid-1980s, Redding invested in small hydrogeneration at Whiskeytown Dam. The Whiskeytown Project has a capacity of approximately 3 MW and yields roughly 26,000 MWh of eligible renewable energy annually.

WAPA Small Hydro Program ( PCC0) - Redding participates in WAPA’ s Small Hydro Program; this contributes approximately 6,000 MWh of eligible renewable energy to Redding annually.

2.4.2 Procurement Plan for Future Renewable Resources
In order to meet the RPS mandates, Redding plans to preserve its existing PCC0 resources, carry forward excess procurement from one compliance period to the next, and look for valuable opportunities to diversify and expand its RPS portfolio while protecting Redding’ s customers from excessive rate increases that could jeopardize economic growth and viability within the City. The Integrated Resource Plan will be the guiding document and tool for choosing the optimal plan.

3. RPS Enforcement Program

3.1 Enforcement Policy
In compliance with the requirement for the governing board of a POU to adopt a program for enforcement of the legislation prior to January 1, 2012, the Redding City Council passed Resolution 2011-197 “ Resolution of the City Council of the City of Redding to Revise the Renewable Portfolio Standard for the City of Redding’ s Electric System” on December 20, 2011. Resolution 2011-197 adopted the following RPS targets:

A. An average of 20 percent in 2011 through 2013;
B. 25 percent by 2016; and
C. 33 percent by 2020 and thereafter.

Resolution 2011-197 also adopted the following Enforcement Policies:

A. Redding will make a reasonable effort in the context of Good Utility Practice to be in compliance with the requirements of SBX1- 2.

B. Redding will report annually to the City Council on its status of compliance with SBX1 -2.

C. Redding will notify the City Council of any potential for lack of compl iance with the requirements of SBX1- 2 that may be considered for a notice of violation and penalty imposition.

D. Redding will provide an explanation and analysis to the City Council on such potential for Packet Pg. 311 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve SCHINSTOCK, BRIANAppendix E E-9
lack of compliance with SBX1- 2, as well as a plan of corrective action and timeframe for returning the City to compliant status.

E. At such time, the City Council will direct staff on its recommended course of action.

Packet Pg. 312 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve SCHINSTOCK, BRIANAppendix E E-10

3.2 Optional Compliance Measures
Specific optimal compliance measures are permitted, and are adopted, by Redding and the City Council. Redding adopts the following optional compliance measures, which may be utilized in the event that factors beyond reasonable control interfere with its ability to meet the procurement requirements set forth in Public Utilities Code § 399.30 and § 3206 of the RPS Regulations.

A. Excess Procurement:

Redding shall be allowed to apply Excess Procurement from one compliance period to subsequent compliance periods using the criteria outlined in § 3206(a)(1) of the RPS Enforcement Regulations beginning on January 1, 2011, and shall be calculated as set forth in RPS Enforcement Regulations § 3206(a)(1)(D).

B. Delay of Timely Compliance:

Enforcement of timely compliance shall be waived if Redding demonstrates that any of the conditions defined in RPS Enforcement Regulations § 3206(a)(2) are beyond the control of Redding, and Redding would have met its RPS procurement requirements but for the cause of delay.

C. Cost Limitations for Expenditures:

Redding establishes a Cost Limitation on the procurement expenditures for all eligible renewable energy resources used to comply with the RPS, consistent with RPS Enforcement Regulations § 3206(a)(3).

The Cost Limitation applied to each RPS procurement expenditure will consider the following:
1) Incorporating the annual RPS expenditure into Redding’ s current portfolio should not require rate increases of more than 1.5 percent per year at any time during the life of the considered RPS procurement.
2) The per-kilowatt- hour cost of the considered RPS procurement expenditure should not exceed, nor be projected to exceed, 75 percent of Redding’ s current per-kilowatthour retail residential energy charge. 3) When estimating the considered RPS procurement expenditure, the following costs will also be included:
a) The costs associated with firming and shaping, and/or storage, as needed for intermittent resources; and
b) The costs associated with delivery of the renewable energy.

In the event that procurement expenditures exceed the adopted Cost Limitation, Redding shall re-evaluate its RPS Procurement Plan to ensure that other options are not available that would otherwise allow Redding to meet its RPS procurement requirement. Such review Packet Pg. 313 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve SCHINSTOCK, BRIANAppendix E E-11
will include a re-evaluation of current procurement commitmen ts, planned procurements, long-term commitments, and the availability of alternative resources in other portfolio content categories.

D. Portfolio Balance Requirement Reduction:

Redding shall be allowed to reduce the portfolio balance requirement for Procurement Content Category 119 for a specific compliance period if conditions beyond the control of Redding occur that warrant a delay in timely compliance ( as adopted under § 2.2 (B) of the RPS Enforcement Program) as defined in § 3206(a)(4) of the RPS Enforcement Regulations.

If Redding uses this reduction measure, Redding will update its RPS Procurement Plan with the adjusted information and submit such updated plan to the CEC.

4. Review and UpdatingRequirements (RPS Enforcement Regulations § 3205(a)) Redding is required to complete an Integrated Resource Plan that will guide the Procurement plan.

A. Redding will provide the following notice regarding new or updated renewable energy resources procurement plans:
1) Redding shall post notice in accordance with Chapter 9 (commencing with § 54950) of Part 1, Division 2, Title 5 of the Government Code, whenever the City Council will deliberate in public on the RPS Procurement Plan.
2) Along with the posting of the notice of a public meeting to consider the RPS Procurement Plan, Redding shall notify the CEC of the date, time, and location of the public meeting to consider the RPS Procurement Plan. This requirement is satisfied if Redding provides the CEC with the uniform resource locator ( URL) that directly links to the notice for the public meeting. Alternatively, an e mail with information on the public meeting in Portable Document Format ( PDF) may also be provided to the CEC. 19 Procurement Content Category 1 is defined in § 3203 ( a) of the RPS Enforcement Regulations.

Packet Pg. 314 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve SCHINSTOCK, BRIANAppendix E E-12
3) Redding will notify the CEC if any URL provided by Redding no longer contains the correct link, and Redding will send the CEC a corrected URL that links to the information, or a PDF containing the information, as soon as it becomes available. 4) If Redding distributes information to its City Council related to its renewable energy resources procurement status, or future procurement or enforcement programs for the City Council’ s consideration at a public meeting, Redding shall make all relevant information available to the public at the same time it is distributed to City Council, and shal l provide an electronic copy of that information to the CEC for posting on the CEC’s website. a) This requirement is satisfied if Redding provides the URL that directly links to the documents or information regarding other manners of access to the documents to the CEC. Alternatively, an e mail with the information in PDF may also be provided to the CEC.
b) Redding will notify the CEC if any URL provided no longer contains the correct link, and Redding will send the CEC a corrected URL that links to the information, or a PDF containing the information, as soon as it becomes available.

5. Review and Revision History
Revision
Number
Revision
Date
Summary of Changes
1 10/15/2013 Original version adopted by City Council Date:

October 15, 2013
2 10/07/2014 Annual update: Removed Lewiston and added Colusa 3 06/05/18 Combined Procurement and Enforcement plan.

Included SB350 updates, removed Colusa biomass
project, and rearranged information for a more clear,
concise document.

J:\14_RESOURCES\ 01_PROCEDURES AND FILINGS\ PROCEDURES\ RPS- 001 RPS PROCUREMENT AND ENFORCEMENT PLAN Packet Pg. 315 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve SCHINSTOCK, BRIANAppendix F F-1
Appendix F. Energy Storage Compliance Plan
Procedure No:

ESCP - 02
Version:

Draft 1
Approval Date:

September
19, 2017 Energy Storage
Compliance Plan
ESCP) Effective Date: October 1, 2017
Document Owner: Lowell Watros

REDDING ELECTRIC UTILITY
Energy Services Division
ESCP-02 Energy Storage Compliance
Plan ( AB 2514 & AB 2227– Public
Utilities Code Sections 2835-2839)
Reviewed By: Lowell Watros ( Resource Planner – Enterprise Services), Nick Zettel ( Manager – Enterprise Services), Dan Beans Interim Electric Utility Director)
Adopted By: Redding City Council
Date: September 19, 2017
Packet Pg. 316 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve SCHINSTOCK, BRIANAppendix F F-2

TABLE OF CONTENTS

1. Introduction/ Background ............................................................................................................... 3

2. Energy Storage Procurement Plan ................................................................................................. 4

2.1 Plan Overview ....................................................................................................................... 4

2.2 Compliance Periods .............................................................................................................. 4

2.3 Definitions of Energy Storage Technologies ....................................................................... 4

3. ESCP Review Requirements ............................................................................................................ 5 Packet Pg. 317 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve SCHINSTOCK, BRIANAppendix F F-3
Introduction/ Background
Redding Electric Utility ( REU) started analyzing energy storage technologies in 2004. In 2005, REU installed its first thermal energy storage ( TES) devices within its service territory ( a chiller- based TES system at Redding Municipal Airport and a direct expansion TES system at the Redding Fire Department).

Subsequent to REU’ s continued pursuit of cost- effective TES installations throughout the Utility’ s service territory, Assembly Bill (AB) 2514 ( Energy Storage Bill) was introduced to the California Legislature by Assembly woman Skinner in 2010. This bill passed and was signed into law (Public Utilities Code Section 2835- 2839) by Governor Arnold Schwarzenegger September 29, 2010.

This energy storage law requires the governing board (City Council) of a local, publicly- owned electric utility by March 1, 2012, to open a proceeding to determine appropriate targets, if any, for the utility to procure viable and cost- effective energy storage systems and, by October 1, 2014, to adopt an energy storage system procurement target, if determined to be appropriate, to be achieved by the utility by December 31, 2016. The law includes a second target to be achieved by December 31, 2020. The law further specifies:

Section 2836 - As part of this proceeding, the governing board may consider a variety of possible policies to encourage the cost-effective deployment of energy storage systems, including refinement of existing procurement methods to properly value energy storage systems.

The governing board shall adopt the procurement targets if determined to be appropriate pursuant to paragraph ( 1) by October 1, 2014.

The governing board shall reevaluate the determinations made pursuant to this subdivision not less than once every three years ( in September 2017 and September 2020).

Section 2836.4 - An energy storage system may be used to meet the resource adequacy requirements established by a local, publicly- owned electric utility pursuant to Section 9620 ifit meets applicable standards.

Section 2836.6 - All procurement of energy storage systems by a load-serving entity or local, publicly- owned electric utility shall be cost-effective.

Packet Pg. 318 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve SCHINSTOCK, BRIANAppendix F F-4
Energy Storage Procurement Plan

2.1 Plan Overview
The purpose of the ESCP is to identify the policies and procedures for REU to meet the requirements set forth with AB 2514 and the Energy Storage section of the Public Utilities Code ( Sections 2835- 2839).
a) The ESCP incorporates REU’ s TES Program with the legislative mandate requiring utilities to review various energy storage technologies and to set procurement and periodic review targets.
b) Under AB 2514, each utility is to review the applicability of various storage technologies to their local operating requirements and identify which of those, if any, would benefit the utility’s electric service requirements. REU has completed an assessment of its TES Program and determined the Program to be beneficial in assisting the overall operating conditions of the Utility.

Under ESCP- 01, REU had a procurement target of 3.6 MW to be installed and operational by July 1, 2017. That target was obtained and REU is now in the Operations and Maintenance O& M) phase for the TES Program as it is now configured. Due to the current ( no growth) load forecast and adequate power supplies available for the foreseeable future, no further additions to REU’ s energy storage capabilities are contemplated at this time. During the next review period, as part of ongoing Integrated Resource Plan ( IRP) efforts, REU will analyze the value of all qualified energy storage technologies as defined by AB 2514, including TES. The existing TES assets are expected to have an effective 20-year plus life span. While the TES systems have been proving to be quite reliable, some routine maintenance will be needed over the multi-year time period that the equipment is expected to be in service.

Compliance Periods
AB 2514 established the following compliance periods:

1. On or before March 1, 2012, REU must initiate a proceeding to determine appropriate storage targets.

2. Procurement targets must be adopted by October 1, 2014.

3. Review initial storage targets by September 2017.

4. Review the storage targets set in September 2017 by September 2020.

Packet Pg. 319 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve SCHINSTOCK, BRIANAppendix F F-5
AB 2227 established the following compliance periods:

1. On or before January 1, 2017, REU must report to the California Energy Commission ( CEC) demonstrating that it had complied with storage targets adopted by City Council on October 1, 2014.

2. By January 1, 2021, in similar fashion as Item 1 above, again file a progress report with the CEC, related to City Council adopted targets on October 1, 2017.

Definitions ofEnergy Storage Technologies
AB 2514 specifically defines what constitutes and qualifies as an energy storage system. The definition as stated in the law (section 2835 ( a)( 1) – ( 2)(A)) is:
commercially available technology that is capable of absorbing energy, storing it for a period of time, and thereafter dispatching the energy.” An “energy storage system” shall do one or more of the following:
1) Use mechanical, chemical, or thermal processes to store energy that was generated at one time for use at a later time.
2) Store thermal energy for direct use for heating or cooling at a later time in a manner that avoids the need to use electricity at that later time. 3) Use mechanical, chemical, or thermal processes to store energy generated from renewable resources for use at a later time. 4) Use mechanical, chemical, or thermal processes to store energy generated from mechanical processes that would otherwise be wasted for delivery at a later time.

ESCP Review Requirements
Redding adjusts its load forecast annually. This forecast will be used to anticipate the ESCP’ s needs in future years. This ESCP will be updated as appropriate to reflect Redding’ s periodic review of loads and available power resources, including energy storage technologies.
a) Redding will review the initial procurement targets set in September 2014 no later than September 2017, and again no later than September 2020.

AB 2227 added to the requirements of AB 2514 minimally in that local, publicallyowned electric utilities, such as REU shall submit a report to the Energy Commission demonstrating it had complied with the energy storage system procurement targets and policies adopted by the City Council in September 2014 by January 1, 2017, and in similar fashion by January 1, 2021. Basically, AB 2227 provides for routine progress reports to the CEC.

Packet Pg. 320 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve II I Ill lllll i n, mH „„
y q ' w °'

CITY OF REDDING
µ m ' REPORT TO THE CITY
COUNCIL MEETING DATE: February 15, 2022 FROM: Nick Zettel, Interim Director ITEM NO. 4. 5( b)of Redding Electric
Utility APPROVED
BY*** m ck. ulM1u, t. a I)c, cfcr cs('Yi, edcl la:,. cu4.+ l)f 1rtY " .. itro
w
mm' Sira... 4
ity 1 i'.- r ) u d tSciciucti Uvre4lar 2t,'
2Q7,nzettel@cityofredding. org btippin@cityofredding.
org SUBJECT: 4. 5( b)-- Agreement with EGIA forRebate Processing Services
Recommendation Approve Consulting and Professional Services Agreement ( Agreement) with Electric and Gas Industries Association, Inc., to continue providing automated rebate processing services to Redding Electric Utility in an amount not to exceed $ 1,353, 551; and authorize the City Manager, or designee, toexecute the Agreement and any future amendments. Fiscal
Impact This Agreement will befunded from budgeted customer program accounts, using Public Benefits Program and Low Carbon Fuel Standard ( LCFS)revenue sources.Alternative
Action The City Council ( Council) could choose not toapprove the Consulting and Professional Services Agreement ( Agreement) and provide alternative direction to staff.Background/
Analysis Under Public Utilities Code § 385, Redding Electric Utility ( REU) offers rebates to promote energy efficiency and conservation. On December 19, 2017, the Council authorized the City Manager to execute a contract with Electric and Gas Industries Association, Inc. (EGIA) toprovide automated rebate processing services to REU. The contract held a one-year term with three successive one- year renewal terms by mutual agreement of both parties.

Subsequently, three one-year extension terms were executed on August 30, 2019, June 24, 2020, and May 13,
Packet Pg. 321 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Report to Redding City Council February 9, 2022
Re: 4. 5( b)-- Agreement with EGIA for Rebate Processing Services Page 2 Throughout the contract term, EGIA effectively administered REU' s rebate incentive programs, including the Residential Deemed, Commercial Deemed, Commercial Lighting, and Commercial Custom programs. EGIA' s rebate processing responsibilities included managing online applications and databases, reviewing applications, providing customer support, and printing and mailing rebate checks to customers. The current contract will expire on June 30, 2022. To date, EGIA has processed over 4, 500 rebates online ( Table 1).

Table 1: EGIA Rebate Applications Processed
Pro ram Name A lications
Commercial Deemed 205
Commercial Custom 15
Residential Deemed 3, 890
Commercial Lighting 455
Total 4, 565
On September 21, 2021, the Council approved REU' s Demand- Side Management Integrated Resource Plan ( DSM- IRP), which transitions programs from energy efficiency ( EE) to electrification ( building and transportation) measures based on the results of the DSM- IIZP report. REU would like to continue using EGIA' s rebate processing services moving forward, including a new suite of electrification incentives for residential, income- qualified, and commercial customers. Due to the expiring contract, REU is required to use a competitive process to select a rebate processor.

Overall, REU staff has been satisfied with EGIA' s automated rebate processing services and wishes to continue using the services to deliver a consistent experience to customers and other program participants. In 2021, the City of Anaheim Public Utilities Department ( APU) performed a competitive Request for Proposal ( RFP) process and awarded their rebate processing contract to EGIA. REU staff reviewed proposals submitted by all respondents, as well as the review process completed by APU. Staff confirmed that APU required similar services to that needed by REU and the EGIA proposal encompassed the needs of REU at the lowest cost. In addition, the City of Redding' s ( City) Purchasing Officer reviewed APU' s RFP materials and determined that the City can award a contract to EGIA based on the APU procurement process.

If approved, the City will execute a five ( 5) year Agreement ( attached) with EGIA in the amount not to exceed $ 1, 353, 551, of which $ 1, 000,000 will pass through to participating customers in the form of rebate checks. The remaining $ 353, 551 is related to administrative costs for rebate processing services, printing, and mailing of checks over the Agreement's five-year term. The actual amount of this contract will depend on the number of rebate applications received. This Agreement may be renewed for up to two ( 2) successive one- year renewal terms by mutual agreement of both parties.

Packet Pg. 322 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Report to Redding City Council February 9, 2022
Re: 4. 5( b)-- Agreement with EGIA for Rebate Processing Services Page 3 Council Priority/City Manager Goals
Government of the 21st 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
Consulting and Professional Services Contract with Electric and Gas Industries Association, Inc. a ailable online)
City of Redding Purchasing approval ( available online) Previous Staff Report - September 21, 2021, item no. 4. 5( e)-- Accept the 2021 Demand- Side Management Integrated Resource Plan Report( available online) Previous Staff Report - December 19, 2017, item no. 4. 5( d)-- Approve Professional Services Contract for Automated Rebate Processing Services for Redding Electric Utility ( available online)
Packet Pg. 323 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric

CITY OF REDDING

CONSULTING AND PROFESSIONAL SERVICES CONTRACT
THIS CONTRACT is made at Redding California, by and between the City of Redding (" City"), a municipal corporation, and Electric and Gas Industries Association, Inc. (" EGIA" or " Consultant") for the purpose of electrification rebate processing.

WHEREAS, City does not have sufficient personnel to perform the services required herein thereby necessitating this Contract for personal services.

NOW, THEREFORE, the Parties covenant and agree, for good consideration hereby acknowledged, as follows:

SECTION 1. CONSULTANT SERVICES
Subject to the terms and conditions set forth in this Contract, Consultant shall provide to City the services described in Exhibit A and Exhibit C, attached and incorporated herein. Consultant shall provide the services at the time, place and in the manner specified in Exhibit A and C.

SECTION 2. COMPENSATION AND REIMBURSEMENT OF COSTS
A. City shall pay Consultant for services rendered pursuant to this Contract, at the times and in the manner set forth in Exhibit B, attached and incorporated herein, in a total amount not to exceed three hundred fifty two thousand, five hundred fifty one ($ 352, 551). This sum includes all outof-pocket travel, lodging and incidental expenses incurred by Consultant that are reasonably associated with the provision of services under this Contract. The payments specified herein shall be the only payments to be made to Consultant for services rendered pursuant to this Contract.

Pursuant to Exhibit B, attached and incorporated herein, in addition to payment of services rendered, City shall reimburse Consultant for rebates paid to customers, printing and postage in a total amount not to exceed one million, one thousand dollars ($ 1, 001, 000).

B. Consultant shall submit monthly invoices to City for work completed to Exhibit B to the date of the invoice. All invoices shall be itemized to reflect the amount billed to each task with sufficient backup to validate claimed performance and expenses incurred.

C. All correct, complete and undisputed invoices sent by Consultant to City shall be paid within thirty (30) calendar days of receipt.

SECTION 3. TERM AND TERMINATION
A. This Agreement shall be effective as of the Effective Date and shall continue for a period of five 5) years from the Program Start Date as defined by Timeline in Exhibit A: Task 1 ( the " Initial Packet Pg. 324 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Term"), unless terminated earlier in accordance with this Agreement or otherwise amended by agreement of both Parties. This Agreement may be renewed for up to two successive one( 1) year renewal terms ( each, a " Renewal Term") by mutual agreement of the Parties in writing at least one hundred and twenty ( 120) days prior to the expiration of the Initial Term or any Renewal Term, as applicable. Vendor and Client shall mutually agree to any additional terms and conditions or fee changes applicable to each such Renewal Term.

B. If Consultant fails to perform its duties to the satisfaction of City, or if consultant fails to fulfill in a timely and professional manner its obligations under this Contract, then City shall have the right to terminate this Contract effective immediately upon City giving written notice thereof to Consultant.

C. Either Party may terminate this Contract without cause on thirty ( 30) calendar days' written notice. Notwithstanding the preceding, if the term set forth in Section 3. A. of this Contract exceeds ninety ( 90) calendar days in duration, Consultant' s sole right to terminate shall be limited to termination for cause.

D. Consultant hereby acknowledges and agrees that the obligation of City to pay under this Contract is contingent upon the availability of City' s funds which are appropriated or allocated by the City Council. Should the funding for the project and/ or work set forth herein not be appropriated or allocated by the City Council, City may terminate this Agreement by furnishing at least thirty 30) calendar days' written notice of its intention to terminate. In the event of a termination pursuant to this subdivision, Consultant shall not be entitled to a remedy of acceleration of payments due over the term of this Agreement. The Parties acknowledge and agree that the power to terminate described herein is required by Article 16, Section 18, of the California Constitution, and that constitutional provision supersedes any law, rule, regulation or statute which conflicts with the provisions of this Section.

E. In the event that City gives notice of termination, Consultant shall promptly provide to City any and all finished and unfinished reports, data, studies, photographs, charts or other work product prepared by Consultant pursuant to this Contract. City shall have full ownership, including, but not limited to, intellectual property rights, and control of all such finished and unfinished reports, data, studies, photographs, charts or other work product.

F. In the event that City terminates the Contract, City shall pay Consultant the reasonable value of services rendered by Consultant up to the date of termination pursuant to this Contract; provided, however, that City shall not in any manner be liable for lost profits which might have been made by Consultant had Consultant completed the services required by this Contract.

Consultant shall, not later than ten ( 10) calendar days after termination of this Contract by City, furnish to City such financial information as in the judgment of the City' s representative is necessary to determine the reasonable value of the services rendered by Consultant.

G. In no event shall the termination or expiration of this Contract be construed as a waiver of any right to seek remedies in law, equity or otherwise for a Party' s failure to perform each obligation required by this Contract.

Page 2 ends

SECTION 4. MISCELLANEOUS TERMS AND CONDITIONS OF CONTRACT A. City shall make its facilities accessible to Consultant as required for Consultant' s performance of its services under this Contract, and, upon request of Consultant, provide labor and safety equipment as required by Consultant for such access.

B. Pursuant to the City' s business license ordinance, Consultant shall obtain a City business license prior to commencing work.

C. Consultant represents and warrants to City that it has all licenses, permits, qualifications and approvals of any nature whatsoever that are legally required for Consultant to practice its profession. Consultant represents and warrants to City that Consultant shall, at its sole cost and expense, keep in effect or obtain at all times during the term of this Contract any licenses, permits and approvals that are legally required for Consultant to practice its profession.

D. Consultant shall, during the entire term of this Contract, be construed to be an independent contractor and nothing in this Contract is intended, nor shall it be construed, to create an employer/ employee relationship, association, joint venture relationship, trust or partnership or to allow City to exercise discretion or control over the professional manner in which Consultant performs under this Contract. Any and all taxes imposed on Consultant' s income, imposed or assessed by reason of this Contract or its performance, including but not limited to sales or use taxes, shall be paid by Consultant. Consultant shall be responsible for any taxes or penalties assessed by reason of any claims that Consultant is an employee of City. Consultant shall not be eligible for coverage under City' s workers' compensation insurance plan, benefits under the Public Employee Retirement System or be eligible for any other City benefit.

E. No provision of this Contract is intended to, or shall be for the benefit of, or construed to create rights in, or grant remedies to, any person or entity not a party hereto.

F. No portion of the work or services to be performed under this Contract shall be assigned, transferred, conveyed or subcontracted without the prior written approval of City. Consultant may use the services of independent contractors and subcontractors to perform a portion of its obligations under this Contract with the prior written approval of City. Independent contractors and subcontractors shall be provided with a copy of this Contract and Consultant shall have an affirmative duty to assure that said independent contractors and subcontractors comply with the same and agree to be bound by its terms. Consultant shall be the responsible party with respect to all actions of its independent contractors and subcontractors, and shall obtain such insurance and indemnity provisions from its contractors and subcontractors as City' s Risk Manager shall determine to be necessary.

G. Consultant, at such times and in such form as City may require, shall furnish City with such periodic reports as it may request pertaining to the work or services undertaken pursuant to this Contract, the costs or obligations incurred or to be incurred in connection therewith, and any other matters covered by this Contract.

Page 3 ends

H. Consultant shall maintain accounts and records, including personnel, property and financial records, adequate to identify and account for all costs pertaining to this Contract and such other records as may be deemed necessary by City to assure proper accounting for all project funds.

These records shall be made available for audit purposes to state and federal authorities, or any authorized representative of City. Consultant shall retain such records for three ( 3) years after the expiration of this Contract, unless prior permission to destroy them is granted by City.

L Consultant shall perform all services required pursuant to this Contract in the manner and according to the standards observed by a competent practitioner of Consultant' s profession.

All products of whatsoever nature which Consultant delivers to City pursuant to this Contract shall be prepared in a professional manner and conform to the standards of quality normally observed by a person practicing the profession of Consultant and its agents, employees and subcontractors assigned to perform the services contemplated by this Contract.

J. All completed reports and other data or documents, or computer media including diskettes, and other materials provided or prepared by Consultant in accordance with this Contract are the property of City, and may be used by City. City shall have all intellectual property rights including, but not limited to, copyright and patent rights, in said documents, computer media, and other materials provided by Consultant. City shall release, defend, indemnify and hold harmless Consultant from all claims, costs, expenses, damage or liability arising out of or resulting from City' s use or modification of any reports, data, documents, drawings, specifications or other work product prepared by Consultant, except for use by City on those portions of the City' s project for which such items were prepared.

K. Consultant, including its employees, agents, and sub- consultants, shall not maintain or acquire any direct or indirect interest that conflicts with the performance of this Contract. Consultant shall comply with all requirements of the Political Reform Act ( Government Code § 8100 et seq.) and other laws relating to conflicts of interest, including the following: 1) Consultant shall not make or participate in a decision made by City if it is reasonably foreseeable that the decision may have a material effect on Consultant' s economic interest, and 2) ifrequired by the City Attorney, Consultant shall file financial disclosure forms with the City Clerk.

SECTION 5. INSURANCE
A. Unless modified in writing by City' s Risk Manager, Consultant shall maintain the following noted insurance during the duration of the Contract:

Covera e Required Not Required
Commercial General Liability X
Comprehensive Vehicle Liability X
Workers' Compensation and Employers' Liability X
Professional Liability( Errors and Omissions) X
Place an" a'' in the appropriate box)

Page 4 ends

B. Coverage shall be at least as broad as:
l. Insurance Services Office form number CG- 0001, Commercial General Liability Insurance, in an amount not less than $ 1, 000, 000 per occurrence and $ 2, 000, 000 general aggregate for bodily injury, personal injury and property damage;

2. Insurance Services Office form number CA- 0001 ( Ed. 1/ 87), Comprehensive Automobile Liability Insurance, which provides for total limits of not less than 1, 000, 000 combined single limits per accident applicable to all owned, non- owned and hired vehicles;

3. Statutory Workers' Compensation required by the Labor Code of the State of California and Employers' Liability Insurance in an amount not less than $ 1, 000, 000 per occurrence. Both the Workers' Compensation and Employers' Liability policies shall contain the insurer's waiver of subrogation in favor of City, its elected officials, officers, employees, agents and volunteers;

4. Professional Liability ( Errors and Omissions) Insurance, appropriate to Consultant' s profession, against loss due to error or omission or malpractice in an amount not less than $ 1, 000, 000.

5. The City does not accept insurance certificates or endorsements with the wording " but only in the event of a named insured' s sole negligence" or any other verbiage limiting the insured' s insurance responsibility.

C. Any deductibles or self-insured retentions must be declared to and approved by City. At the option of the City, either: the insurer shall reduce or eliminate such deductibles or self-insured retentions as respects the City, its elected officials, officers, employees, agents and volunteers; or the Consultant shall procure a bond guaranteeing payment of losses and related investigations, claims administration and defense expenses.

D. The General Liability shall contain or be endorsed to contain the following provisions:
l. City, its elected officials, officers, employees, and agents are to be covered as additional insured as respects liability arising out of work or operations performed by or on behalf of Consultant; premises owned, leased or used by Consultant; or automobiles owned, leased, hired or borrowed by Consultant. The coverage shall contain no special limitations on the scope of protection afforded to City, its elected officials, officers, employees, agents and volunteers.

2. The insurance coverage of Consultant shall be primary insurance as respects City, its elected officials, officers, employees, agents and volunteers. Any insurance or selfinsurance maintained by City, its elected officials, officers, employees, agents and volunteers, shall be in excess of Consultant' s insurance and shall not contribute with it.

Page 5 ends

3. Coverage shall state that the insurance of Consultant shall apply separately to each insured against whom claim is made or suit is brought, except with respect to the limits of the insurer's liability.

4. Each insurance policy required by this Contract shall be endorsed to state that coverage shall not be canceled except after thirty ( 30) calendar days' prior written notice has been given to City. In addition, Consultant agrees that it shall not reduce its coverage or limits on any such policy except after thirty ( 30) calendar days' prior written notice has been given to City.

E. Insurance is to be placed with insurers with a current AMBest' s rating of no less than A-VII.

F. Consultant shall designate the City of Redding as a Certificate Holder of the insurance.

Consultant shall furnish City with certificates of insurance and original endorsements effecting the coverages required by this clause. Certificates and endorsements shall be furnished to: Risk Management Department, City of Redding, 777 Cypress Avenue, Redding, CA 96001. The certificates and endorsements for each insurance policy are to be signed by a person authorized by the insurer to bind coverage on its behalf. All endorsements are to be received and approved by the City' s Risk Manager prior to the commencement of contracted services. City may withhold payments to Consultant if adequate certificates of insurance and endorsements required have not been provided, or not been provided in a timely manner.

G. The requirements as to the types and limits of insurance coverage to be maintained by Consultant as required by Section 5 of this Contract, and any approval of said insurance by City, are not intended to and will not in any manner limit or qualify the liabilities and obligations otherwise assumed by Consultant pursuant to this Contract, including, without limitation, provisions concerning indemnification.

H. If any policy of insurance required by this Section is a " claims made" policy, pursuant to Code of Civil Procedure § 342 and Government Code § 945. 6, Consultant shall keep said insurance in effect for a period of eighteen ( 18) months after the termination of this Contract.

L If any damage, including death, personal injury or property damage, occurs in connection with the performance of this Contract, Consultant shall immediately notify City' s Risk Manager by telephone at ( 530) 225- 4068. No later than three ( 3) calendar days after the event, Consultant shall submit a written report to City' s Risk Manager containing the following information, as applicable: 1) name and address of injured or deceased person( s); 2) name and address of witnesses; 3) name and address of Consultant' s insurance company; and 4) a detailed description of the damage and whether any City property was involved.

SECTION 6. INDEMNIFICATION AND HOLD HARMLESS
A. Consistent with California Civil Code § 2782. 8, when the services to be provided under this Contract are design professional services to be performed by a design professional, as that term is defined under Section 2782. 8, Consultant shall, to the fullest extent permitted by law, indemnify protect, defend and hold harmless, City, its elected officials, officers, employees,

Page 6 ends

and agents, and each and every one of them, from and against all actions, damages, costs, liability, claims, losses, penalties and expenses ( including, but not limited to, reasonable attorney' s fees of the City Attorney or legal counsel retained by City, expert fees, litigation costs, and investigation costs) of every type and description to which any or all of them may be subjected by reason of, or resulting from, directly or indirectly, the negligence, recklessness, or willful misconduct of Consultant, its officers, employees or agents in the performance of professional services under this Contract, except when liability arises due to the sole negligence, active negligence or misconduct of the City.

B. Other than in the performance of professional services by a design professional, which is addressed solely by subdivision (A) of this Section, and to the fullest extent permitted by law, Consultant shall indemnify protect, defend and hold harmless, City, its elected officials, officers, employees, and agents, and each and every one of them, from and against all actions, damages, costs, liability, claims, losses, penalties and expenses ( including, but not limited to, reasonable attorney' s fees of the City Attorney or legal counsel retained by City, expert fees, litigation costs, and investigation costs) of every type and description to which any or all of them may be subjected by reason of the performance of the services required under this Contract by Consultant its officers, employees or agents in the performance of professional services under this Contract, except when liability arises due to the sole negligence, active negligence or misconduct of the City.

C. The Consultant' s obligation to defend, indemnify and hold harmless shall not be excused because of the Consultant' s
inability to evaluate liability. The Consultant shall respond within thirty ( 30) calendar days to the tender of any claim for defense and indemnity by the City, unless this time has been extended in writing by the City. If the Consultant fails to accept or reject a tender of defense and indemnity in writing delivered to City within thirty (30) calendar days, in addition to any other remedy authorized by law, the City may withhold such funds the City reasonably considers necessary for its defense and indemnity until disposition has been made of the claim or until the Consultant accepts or rejects the tender of defense in writing delivered to the City, whichever occurs first. This subdivision shall not be construed to excuse the prompt and continued performance of the duties required of Consultant herein.

D. The obligation to indemnify, protect, defend, and hold harmless set forth in this Section applies to all claims and liability regardless of whether any insurance policies are applicable. The policy limits of said insurance policies do not act as a limitation upon the amount of indemnification to be provided by Contractor.

E. City shall have the right to approve or disapprove the legal counsel retained by Consultant pursuant to this Section to represent City' s interests. City shall be reimbursed for all costs and attorney's fees incurred by City in enforcing the obligations set forth in this Section.

SECTION 7. CONTRACT INTERPRETATION, VENUE AND ATTORNEY FEES A. This Contract shall be deemed to have been entered into in Redding, California. All questions regarding the validity, interpretation or performance of any of its terms or of any rights or obligations of the parties to this Contract shall be governed by California law. If any claim, at

Page 7 ends

law or otherwise, is made by either party to this Contract, the prevailing party shall be entitled to its costs and reasonable attorneys' fees.

B. This document, including all exhibits, contains the entire agreement between the parties and supersedes whatever oral or written understanding each may have had prior to the execution of this Contract. This Contract shall not be altered, amended or modified except by a writing signed by City and Consultant. No verbal agreement or conversation with any official, officer, agent or employee of City, either before, during or after the execution of this Contract, shall affect or modify any of the terms or conditions contained in this Contract, nor shall any such verbal agreement or conversation entitle Consultant to any additional payment whatsoever under the terms of this Contract.

C. No covenant or condition to be performed by Consultant under this Contract can be waived except by the written consent of City. Forbearance or indulgence by City in any regard whatsoever shall not constitute a waiver of the covenant or condition in question. Until performance by Consultant of said covenant or condition is complete, City shall be entitled to invoke any remedy available to City under this Contract or by law or in equity despite said forbearance or indulgence.

D. If any portion of this Contract or the application thereof to any person or circumstance shall be invalid or unenforceable to any extent, the remainder of this Contract shall not be affected thereby and shall be enforced to the greatest extent permitted by law.

E. The headings in this Contract are inserted for convenience only and shall not constitute a part hereof. A waiver of any party of any provision or a breach of this Contract must be provided in writing, and shall not be construed as a waiver of any other provision or any succeeding breach of the same or any other provisions herein.

F. Each Party hereto declares and represents that in entering into this Contract, it has relied and is relying solely upon its own judgment, belief and knowledge of the nature, extent, effect and consequence relating thereto. Each Party further declares and represents that this Contract is made without reliance upon any statement or representation not contained herein of any other Party or any representative, agent or attorney of the other Party. The Parties agree that they are aware that they have the right to be advised by counsel with respect to the negotiations, terms, and conditions of this Contract and that the decision of whether or not to seek the advice of counsel with respect to this Contract is a decision which is the sole responsibility of each of the Parties. Accordingly, no party shall be deemed to have been the drafter hereof, and the principle of law set forth in Civil Code § 1654 that contracts are construed against the drafter shall not apply.

G. Each of the Parties hereto hereby irrevocably waives any and all right to trial by jury in any action, proceeding, claim or counterclaim, whether in contract or tort, at law or in equity, arising out of or in any way related to this Agreement or the transactions contemplated hereby.

Each Party further waives any right to consolidate any action which a jury trial has been waived with any other action in which a jury trial cannot be or has not been waived.

Page 8 ends

H. In the event of a conflict between the term and conditions of the body of this Contract and those of any exhibit or attachment hereto, the terms and conditions set forth in the body of this Contract proper shall prevail. In the event of a conflict between the terms and conditions of any two or more exhibits or attachments hereto, those prepared by City shall prevail over those prepared by Consultant.

SECTION 8. SURVIVAL
The provisions set forth in Sections 3 through 7, inclusive, of this Contract shall survive termination of the Contract.

SECTION 9. COMPLIANCE WITH LAWS - NONDISCRIMINATION
A. Consultant shall comply with all applicable laws, ordinances and codes of federal, state and local governments.

B. In the performance of this Contract, Consultant shall not discriminate against any employee or applicant for employment because of race, color, ancestry, national origin, religious creed, sex, sexual orientation, disability, age, marital status, political affiliation, or membership or nonmembership in any organization. Consultant shall take affirmative action to ensure applicants are employed and that employees are treated during their employment without regard to their race, color, ancestry, national origin, religious creed, sex, sexual orientation, disability, age, marital status, political affiliation, or membership or nonmembership in any organization. Such actions shall include, but not be limited to, the following: employment, upgrading, demotion or transfer, recruitment or recruitment advertising, layoff or termination, rates of pay or other forms of compensation and selection for training.

SECTION 10. REPRESENTATIVES
A. City' s representative for this Contract is Vince Karlson, telephone number ( 530) 339- 7262, fax number ( 530) 339- 7299. All of Consultant' s questions pertaining to this Contract shall be referred to the above- named person, or to the representative' s designee.

B. Consultant' s representative for this Contract is Clayton Reed, telephone number ( 802) 793- 0663, faY number ( 916) 609- 5350. All of City' s questions pertaining to this Contract shall be referred to the above- named person.

C. The representatives set forth herein shall have authority to give all notices required herein.

SECTION 11. NOTICES
A. All notices, requests, demands and other communications hereunder shall be deemed given only if in writing signed by an authorized representative of the sender ( may be other than the representatives referred to in Section 10) and delivered by facsimile, with a hard copy mailed

Page 9 ends

first class, postage prepaid; or when sent by a courier or an express service guaranteeing overnight delivery to the receiving party, addressed to the respective parties as follows:

To City: To Consultant:

Daniel Beans Bruce Matulich
3611 Avtech Parkway 3800 Watt Ave., Suite 105
Redding, CA 96002 Sacramento, CA 95821
530) 339- 7350 866) 367- 3442 ext. 314
B. Either party may change its address for the purposes of this paragraph by giving written notice of such change to the other party in the manner provided in this Section.

C. Notice shall be deemed effective upon: 1) personal service; 2) two calendar days after mailing or transmission by facsimile, whichever is earlier.

SECTION 12. AUTHORITY TO CONTRACT
A. Each of the undersigned signatories hereby represents and warrants that they are authorized to execute this Contract on behalf of the respective parties to this Contract; that they have full right, power and lawful authority to undertake all obligations as provided in this Contract; and that the execution, performance and delivery of this Contract by said signatories has been fully authorized by all requisite actions on the part of the respective parties to this Contract.

B. When the Mayor is signatory to this Contract, the City Manager and/ or the Department Director having direct responsibility for managing the services provided herein shall have authority to execute any amendment to this Contract which does not increase the amount of compensation allowable to Consultant or otherwise substantially change the scope of the services provided herein.

SECTION 13. DATE OF CONTRACT
The date of this Contract shall be the date it is signed by City.

Page 10 ends

Il' W17'? ti( i; ti WI EI) F+', ; oty and ' ar aaltar t E1ae r;xec e ti i C.cau trac t c n tl i vs arv yr; r s rt f-c ri k rw:

TY F Ft CI[ ti1,

4. P' t n ci al' ar a ratir n
ID t+ec:
13y: a
ry `Ti, C",ity 1' na er
P"""" I+""' t I f)' EI) A TC) +"C C 14'[:

BA RY . U WALT
C'ity tt.r t y
1, A.M:, A ' IZ7.1, C' it C: l r By:

Cf)fi] IJLT, 1 tT
Il te a 2n . -- m.._"
W__._.__
l' y: r c H Gt nn V e Pre ide t
ax Na., 94- 1t 2 7
C' a c N l
Packet Pg. 334 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Exhibit A — Service Description
This Exhibit A is subject and shall be governed by the Professional Service Agreement ( the " Agreement") between EGIA and the City of Redding, which is hereby incorporated by reference. Capitalized terms used but not otherwise defined in this Exhibit shall have the meaning ascribed to them in the Agreement.

WHEREAS, the parties wish to document EGIA implementation of energy efficiency rebate processing services under this schedule as of the Effective Date.

Introduction
The Services under this Exhibit A consist of automated rebate processing services provided to the City of Redding.

These automated rebate- processing services will include three distinct components, which include 1) full service processing of commercial and residential electrification rebates, 2) rebate processing online application hosting service for residential new construction rebates, and 3) rebate processing online application hosting service for retail voucher rebates.

City of Redding and EGIA each will assign a Project Manager that will be responsible for completing the implementation services outlined in this Exhibit A.

The Services consists of the following major elements described in this schedule. 1) Task 1: Program Development and Start Up
2) Task 2: Full Service Rebate Processing for Commercial Electrification and Residential Electrification Deemed Rebates
3) Task 3: Rebate Processing Online Application Hosting Service for Residential New Construction Rebates and Retail Voucher Rebates.
4) Task 4: Program Management and Reporting
5) Task 5: Service Management
6) Task 6: Task Orders
Tasks 2 and 3 need to be developed and launched in tandem.

Page 12 ends

Task 1: Proqram Development and Start Up
Overview
In coordination with City of Redding, EGIA will adapt their proprietary rebate processing system described in Exhibit C to the specific needs of the City of Redding.

Responsibility Matrix
The Program Development and Start Up functionality consists of the following:

Function City of EGIA
Redding
1 Identify Project Manager X X
2 Finalize All Program Specifications with City Program S X Management
3 Customize Program Specifications and Rules S X
4 Customize Consumer Messaging Requirements S X
5 Design Check Stock and Envelopes For Approval ( if S X applicable)
6 Setup Bank Account/ Trust Account For Funding Rebate S X Checks ( if applicable)
7 Finalize Program Messaging For Website Online S X
Application
8 Design Phone Script For Program For Approval S X
9 Program Checks and Envelopes Sent To Printer S X
10 Develop Program Customer Communication Letters S X
11 Complete Development Of The Rebate Database and S X
Rebate Processors Desktop Application
12 Complete Development of Online Application S X
13 Develop Program Specific Reporting S X
14 Develop Program Invoicing S X
15 Record Final Draft Of Approved Phone Script S X
16 Draft and Program Customer Rebate Status emails S X
17 Complete Development of Automated Online Rebate S X
Status Function
18 Train CSR' s On Program, Including Terms & Conditions, S X Requirements, Qualifying Products and Application
19 Develop Standardized Online Reporting Dashboard S X
20 Final Test All Systems and Processes with City Final S X Approval
21 Launch Program & Begin Processing Rebate Applications S X Note: " X" indicates responsible party and " S" indicates supporting party.

Page 13 ends

Timeline
Activity Phase 1: Launch
new electrification
programs in 2022
Development
schedule prior to
Program Start Date
of 7/ 1/ 2022
1 Identify Project Manager 45 2 Finalize All Program Specifications with City 30 Program Management
3 Customize Program Specifications and Rules 30 4 Customize Consumer Messaging Requirements 30 5 Design Check Stock and Envelopes For Approval 25 if applicable)
6 Setup Bank Account/ Trust Account For Funding 25
Rebate Checks ( if applicable)
7 Finalize Program Messaging For Website Online 25
Application
8 Design Phone Script For Program For Approval 25 9 Program Checks and Envelopes Sent To Printer 20 10 Develop Program Customer Communication 15
Letters
11 Complete Development Of The Rebate Database 15
and Rebate Processors Desktop Application
12 Complete Development of Online Application 15
13 Develop Program Dashboard Reporting 15
14 Develop Program Invoicing 10
15 Record Final Draft Of Approved Phone Script 10
16 Draft and Program Customer Rebate Status emails 10
17 Complete Development of Automated Online 10
Rebate Status Function
18 Train CSR'
s On Program, Including Terms &
5 Conditions, Requirements, Qualifying Products and
Application
19 Develop Online Reporting Template and5
Standardized Reports
20 Final Test All Systems and Processes with City5
Final Approval
21 Launch Program & Begin Processing Rebate0
Applications

Page 14 ends

Task 2: Rebate Processinq
Overview
Using the processes and tools developed during program startup, EGIA will process residential and commercial rebate applications submitted by City of Redding Electric Customers.

Responsibility Matrix
The rebate processing functions and responsibilities are shown below.

Function City of EGIA
Redding
1 Validate Utility Customer Status X
2 Validate Rebate Application Compliance X
3 Enter Rebate Application into Database X
4 Perform field verification/ inspection of rebate reservations X pre- installation) and rebate applications ( post- installation) and update in database.
5 Maintain Rebate Filing System X
6 Maintain Customer Call Center( call handling and X
Customer Service)
7 Facilitate customer communication including customer X denial letter/email correspondence
8 Follow- up On Incomplete or Deficient Applications X
9 Facilitate Issue Resolution/ Customer Escalations S X 10 Print Rebate Checks X
11 Mail Rebate Checks to Utility Customer Account Holder X 12 Collect W9s and issue 1099s to commercial customer S X Note: "X" indicates responsible party and " S" indicates supporting party.

Timeline
Rebate processing begins upon approval completion of the startup phase, and will typically continue 2 months after the last rebate is submitted at the end of the contract.

Page 15 ends

Task 3: Provide Online Application Hostinq Service
Overview
Using the processes and tools developed during program startup, EGIA will provide an online application hosting service for Residential New Construction and Retail Voucher rebates. City of Redding Staff will be reviewing and approving Residential New Construction and Retail Voucher rebates using EGIA' s online tool.

Responsibility Matrix
The Online Application Hosing Service functions and responsibilities are shown below.

Function City of EGIA
Redding
1 IT Security Monitoring X
2 Ongoing Database & Network Maintenance X
3 Ongoing Application Updates/ Enhancements X
4 Data Integration & Updates X
5 Ongoing Dashboard Performance Reporting X
6 Automated Invoicing X
7 Automated email Generation X
8 Application Hosting X
9 24/ 7 IT Support X
10 Maintain Auto Generated email/ Customer Correspondence Content X 11 Validate Utility Customer Status when rebates are submitted X 12 Validate Rebate Application Compliance X
13 Enter Rebate Application into Database X
14 Perform field verification/ inspection of rebate reservations ( pre- installation) X and rebate applications ( post- installation) and update in database 15 Maintain Rebate Filing System X
16 Maintain Customer Call Center( call handling and Customer Service) X 17 Facilitate customer communication including customer denial letter/ email X correspondence
18 Follow- up On Incomplete or Deficient Applications X 19 Facilitate Issue Resolution/ Customer Escalations X
20 Print Rebate Checks X
21 Mail Rebate Checks to Utility Customer Account Holder X Note: " X" indicates responsible party and " S" indicates supporting party.

Timeline
Online application hosting begins upon approval completion of the startup phase.

Page 16 ends

Task 4: Proqram Manaqement and Reportinq
EGIA will provide program management services required to implement the rebate program and report to the City of Redding. EGIA will provide an online dashboard that allows for reporting. This dashboard will include standardized reporting developed by EGIA to track the cumulative amount paid for incentives, encumbered rebate funds, the remaining budget for each program offered, and total number of rebates processed based on rebate status. This list will include but not be limited to, the following:

Monthly, year- to- date, and annual reporting periods based on EGIA batch and/ or check dates Number of rebates ( total and by rebate type)
Incentive amount( total and by rebate type)
Quantities ( number of units) per measure type
Administration costs
City of Redding will provide the final list of qualifying measures and the rebate/ incentive amounts desired.

The City of Redding will also have online access to all utility specific data held in the EGIA ERPS system. This data can be downloaded at any time into an excel file for full utility reporting and data analysis to allow Redding Electric to generate additional program reports. EGIA will also periodically review data quality to update or remove erroneous or testing data.

Responsibility Matrix
The program management functions and responsibilities are shown below.

Function City of EGIA
Redding
1 Fund Account Maintenance X
2 Call Center Management X
3 Enforce Financial Security Measures X
4 Prepare and Transmit Database Reports/ Program Files X 5 Ongoing Quality Assurance and Quality Control X
6 Monthly/ Quarterly and Annual Reporting X
7 Twice Monthly Incentive Reimbursement Invoicing X
8 Monthly Rebate Processing Fee Invoicing X
9 Monthly Scheduled Conference Calls With Utility Program X Managers.
10 Qualified Product List( QPL) Maintenance X
11 Ongoing CSR/ Rebate Processor Training X
12 IT Security Monitoring X
13 Ongoing Database & Network Maintenance X
14 Data Integration & Updates ( customer account and prior X participation updates)
15 Application Hosting X
16 IT Help Desk X
17 24/ 7 IT Support X
Timeline
This activity is ongoing through the course of the contract.

Page 17 ends

Task 5: Service Manaqement
Overview
Service Management is the function of managing the program in a manner that that will achieve the City of Redding program goals within the program budget. These goals are listed in the Table below.

Quality Metric Goal
Rebate Processing Time
g5% of rebates processed within 30 days of receipt of completed application.

Frame
Call center availability 95% of phone calls answered within 60 seconds. 95% of calls monitored per EGIA quality assurance program achieve rating of Call center quality
meets expectations" or better. REU may request and monitor specific phone calls within 30 days of call receipt as needed for special circumstances ( e. g. customer complaint)
Response Rate
97% of phone and email messages returned to customers within one business day.

Rebate Portal Availability
Rebate application portal maintains service availability of 97% not including planned outages.

Functions
The functions of Service Management consist of:
1) Facilitate or make data available to enable City of Redding review of customer interactions including phone calls and email correspondence as needed for special circumstanced ( e. g. customer complaint). 2) Prepare for and review quality metrics at monthly meetings. 3) Document issues discussed and agreed up on changes for moving forward. 4) Integrate agreed up on changes into EGIA' s service offering.

Function City of EGIA
Redding
1 Facilitate review or make data available to enable review X X 2 Prepare for and review quality metrics at monthly meetings. X S 3 Document issues discussed and agreed up on changes for X S moving forward.
4 Integrate agreed up on changes into EGIA' s service offering. X Note: " X" indicates responsible party and " S" indicates supporting party.

Timeline
1) Facilitate review or make data available to enable review— Monthly 2) Prepare for and review quality metrics at monthly meetings - monthly 3) Deliver meeting minutes— 5 business days from end of quarterly meeting 4) Document issues discussed and agreed up on changes for moving forward — within 5 business days after monthly meeting.
5) Integrate changes into service offering — 10 business days from monthly meeting.

Page 18 ends

Task 6: Task Orders
Overview
At times additional services related to the scope of work may be requested by the City of Redding through the issuance of a written Task Order. These services may include adding new rebates to the program after the initial startup phase, changing existing rebates based regulatory requirements, updating program forms, development or updating of program materials or websites, or other tasks deemed necessary in support of the rebate processing services.

All Task Orders must be completed and signed in a form agreeable to both parties prior to proceeding with services but subject to the terms and conditions of this Agreement. Task Orders may be negotiated with a not- to- exceed amount or as a fixed- price and may include milestones or project deliverables and timelines. Consultant Standard Hourly Billing Rates included in Exhibit B will be used when calculating pricing associated with approved Task Orders.

Responsibility Matrix
The task order functions and responsibilities are shown below.

Function City of EGIA
Redding
1 Initiate a written task order defining scope of work and/ or X deliverables.
2 Determine cost and schedule associated with fulfilling the X requested task.
3 Finalize task order by signed agreement of both parties X X 4 Perform work prescribed by task order X
Note: " X" indicates responsible party and " S" indicates supporting party.

Timeline
Timeline and cost associated with each task order will vary based on the task order.

Page 19 ends

Exhibit B — Fee Schedule
For each calendar month, EGIA shall invoice, and The City of Redding shall pay to EGIA the fees set forth in Exhibit B according to the payment criteria and other provisions of this Agreement. w... i. m IIII I I
II II I I VI im.. a u IIIIIIII
m m m
i. ,.. IIIII.-; im. IIIII a m.

I
1 Pro gram Develo pment and Startu p— Phase 1 One- Time 8 600. 00 1 8, 500 Task 2: Residential Electrification Rebate Processing
Per Rebate

11. 61 295 3, 425
Application
2 Task 2: Commercial Electrification Rebate Processing
Per Rebate

16. 91 113 1, 911
Application
Per Month $ 1, 458. 00 60 87, 480
Task 3: Provide online hosting of Residential New
Construction Rebate Application and Processing System
Per Rebate
Application

16. 91 160 2, 706
3 Per Month 991. 00 60 59, 460
Task 3: Provide online hosting of Retail Voucher Rebate Application and Processing System Per Rebate

11. 61 75 871
Application
4 Task 4: Program Management and Reporting AND Task 5:

Per Month $ 2, 597. 00 60 155, 820
Service Management
5 Task Order Contingency
Maximum
25, 000 1 25, 000
Budget
Collect W9s and issue 1099s relating to Commercial
6 Electrification, Residential New Construction and Retail AppPcation

21. 20 348 7, 378
Voucher Rebates
7 Printing and Postage( reimbursed at cost)
Maximum
1, 000 1 1, 000
Budget
Monetary compensation( rebates) paid to customers Maximum reimbursed at cost) Budget
1, 000, 000 1 1, 000, 000
Total Administrative Fee for Startup- Item 1 ( Not to Exceed) 8, 500 Total Administrative Fee for Service- Items 2, 3, 4, 5, 6( Not to Exceed) 344, 051 Total Reimbursement for Rebates to Customers- Items 7, 8( Not to Exceed) 1, 001, 000 Total( Not to Exceed) 1, 353, 551
I d° uu u rnu rn I dr u Dy I I r uu C
A minimum rebate- processing fee of$ 300/ month will be charged should monthly rebate processing volume fall below the 11- rebate application minimum.

Page 20 ends

Cr
u u. s0 u u r° Nr u. s° Dy u00uu I y I r u ur u
Chief Executive Officer 225
Chief Financial Officer 190
Chief Technology Officer 190
Vice President, Utility& Government Services 180
Vice President, Marketing& Member Services 180
Vice President, Contractor Services 180
General Manager, Member Services 160
Director, Distributor Services 150
Director, Business Development Financing 150
Director, Utility& Government Services 145
National Sales Manager, Financing 145
Marketing Creative Director 145
Director Communications& Marketing Partnerships 145
Sr. Manager, Financing Strategic Partnerships 140
Director, Business Coaching 140
Director, Events Management 135
SeniorApplication Developer 130
Sr. Manager, Trade Ally Services 125
Senior Technical Program Manager 125
Information Technology 120
Video Production Manager 120
Marketing Communications Manager 110
Sr. Web Developer 110
Sr. Graphic Designer 110
Corporate Operations 110
Utility Svcs., Contractor Svcs., Member Svcs 105
Distributor/ Member Services, Contractor Services 105
Manager, Call Center Operations 105
Manager, OEM/ Distributor Incentive Processing 100
Marketing Communications 100
Marketing Communications 95
Member Services, Contractor Services 95
Events Coordinator 95
Contractor Services, Utility Services 95
Information Technology 90
Utility Services 75
Utility Services 70

Page 21 ends

Exhibit C — EGIA Product Description
This Exhibit C provides an overview of EGIA' s proprietary" EGIA Rebate Processing System" ( ERPS). This Exhibit defines the framework and specific features of the tool that will be adapted to the City of Redding' s needs. Unless eaplicitly stated otherwise and with approval from the City of Redding, all framework and specific features defined herein will be incorporated into the EGIA Rebate Processing System( ERPS).

J ._ . ._ _. ::=:.;'' J'° '°'_. _.:

The EGIA Rebate Processing System( ERPS) is designed to cost effectively process traditional mail-in applications, instant rebate coupons, bounty programs, sales staff incentives, wholesale or retail buy- downs and other innovative incentives specified by program sponsors. The EGIA Rebate Processing System also provides for 24/ 7 online application submittal, online program management reporting and has a fully developed rebate reservation capability that can be rapidly tailored to address utility specific program requirements.

The rebate processing system is designed to accommodate and track outside funding such as state or community block grants, local government funds or to leverage funds provided by multiple organizations. EGIA' s rebate processing system and online application can deliver combined energy/ water rebates.

The EGIA Rebate Processing System online application includes but is not be limited to providing:

Ability to customize online rebate application form to incorporate and match information requested on the utility rebate applicarion related to customer' s purchases and rebate data fields required for the urility rebate program.

Automatic confirmation acknowledgment that the application has been received( hardcopy or email) Automatically assigning a unique rebate number for easy application tracking.

Ability for the customer to print- out a copy of their online application and acknowledgment that their application has been received.

Online rebate status information so that customers can track where their application is in the process.

Ability to rapidly modify online application form to reflect qualified energy efficiency product or program changes.

Context sensitive online help functionality that makes it easy for customers to navigate.

Web user interface that can be customized to the utilities Web design standards and will not require the client to download any additional software in order to use the application.

A modular design that can be seamlessly incorporated into the utilities existing Web sites navigational frameworks.

The ERPS will support server- side validation of all form fields processed on a utility request. This will include such elements as user input fields, select options, checkboxes, radio buttons or hidden fields. The system will also validate on the server side for valid data type, data length, and valid character ranges as well as disable HTML special characters for any input fields that cannot be adequately validated, such as free form input fields.

The online application is highly secure and has been successfully audited by PG& E and Nicor Gas IT security personneL The application employs industry leading security protocol and is not susceptible to security vulnerabilities such as SQL injection attacks, cross site scripring cross site request forgery, and buffer overflow. For greater detail on EGIA' s technology solution and data security architecture, see the" IT Application and Data Security" secrion of this proposal.

Page 22 ends

m. :. '" 1 . m. '" 1 :. W .. W
m. . .,. 1
EGIA currently administers nearly$ 500, 000, 000 in public benefit funds for large scale rebate programs covering over 300 utilities and water agencies. The ERPS robust database allows the utility using their own manpower tY rough the software solution or EGIA CSR' s as part of a full service tiiriikey solution to choose qualifying models from drop down lists. Web based applications load directly into the database minimizing rebate processor data entry. All program rules and eligibility requirements are loaded into the database before the program starts. Attempts to process applications that violate the rules and requirements automatically generate error codes assuring that no incentive checks are issued unless the error code is resolved.

1., :. W m. :.

W.., .,.. '" lW :. W ..

Il•. u. u c u
Every time an application is touched by a rebate processor, a date is entered into the database. Each time a CSR contacts an applicant or the applicant contacts the utility or EGIA, the details of the conversation can be typed into the comments section of the desktop application rebate form. When letters are sent, the date is recorded and a pdf of the letter is electronically saved. When a check is mailed the date and check number are recorded in the database automatically.

Page 23 ends

n
u
1:. u_ 1
EGIA' s rebate processing system has been designed to ensure accurate, timely payment of qualifying purchases and prompt and courteous follow- up. It is supported by a superior database management system that significantly reduces the chance of errors by automating most of the system functions. The following two process flow diagrams depict( 1) rebate processing as a hosted software service illustrating the relationship between the ERPS solution and utility processing manpower( With the hosting service, all rebate processing manpower is provided by the utility, items highlighted in yellow represent areas where utility manpower is required, and( 2) the typical process flow if EGIA were delivering a full service turnkey rebate processing solution. mui(/ l,!°1l-011r111JdIu YJ111 J1Jld%/ llll/Il` i
lllil/J/I,l11 1l/ llllllld/! udrOrl/%l,lllllllllU/ l/i
d,UllllllN l///!%r` iao rl1/I!!! ijJiiuef a a/+ i u ai ul iikll1J111 ii III' Flll// i/%/ 7A/ l'» f1/II IU!/( llpl.. , . , : { ; x^
o w . w : w ,
f« 1,, r rnf»« f« rr,» D 1%
C bc i 89 roF 0' Et': a r
y
fh,p rlv P v. nYe! a.. i Nhpa tl r. u p n: uro
w «- «... P p... v «.
u,: n i . ...,: J.. p
uR: ,,„.
x ao m rs d m . m. '. a. z ?,..
eN_.
pl .. ..
a ' vn ro +, w p: u m
s a+i m
ro u a i m ro w a ,: ro i u; r..
m a. a . o:. m , y a n
o':: m a,e'« n. I:

TI Y ; ry'. Yf P P YYA k " M1 1 1
m .. ` . a c. c
vi46'. uirr N Y R oraotp . f /.. x
a
i
w
M M C.' I' I tIIfM R" C': NV1..`d p.:: ur^ ar<:: it o-« u-+ n rr C wwiuh ii: L,;. m , f u uVte . 11. y,:'u
m ^. ' s : z : a µi M. 11 II Ce'"IM IMfM t.`C+"' W,.` N D t/' Tllll@ YP. C; pYdC.' d r r n o . -:. r m. - .

ERPS uptl t tl wiY.h ...,,.,,
up n reaeipt
epplYaarrt inforrr7aYan uv' •[ a ka e: nt r t FRPS . ":„ r, vo. ; ,,, av., r, r ea a a uvaA-, a 5,, d,. u x i ,^ J, a. r c r gat¢'; c: tl 3 i i r,...; Pfi r, zr,/ W tVq l4". icrm E' 14 Ni) Qu l h d Peaidu+ t Y lid U lity Gus tsWm r
ii q ; ir i i iii o
3: :
j%, i". ' 1Mi 1 li FY IAYM
Prov id drby ut lity}
werlPl d
i
ri f
C a afn t aa: crunt I sk i i i
u - -
l/ ,,,,, 1„ i ;2//1 l/ Pa erwQrk i pQ stm rked ptltlre s« Mat h s Accoiunt' r p
vviChirr 7C) C days af' irrsL ll rtion ' IrrstallatYon addre: as IsvarlYY d I a in t accaunt Infornr tiorr I,
1Va ld' urchase 1ate I
L1Mnrc mentatl+ o n
p ogra n start/ end dates Received( Ulilit l
Uate/ Tii7 e r tacard t i,,,,,
upan input fiui r
rl r
rr llll// 17 1/%(,/,/ D„ uirpJll IlJllIlJ1 ijirllNl,iaJJJlJliuu7l/ NIGIIlGJ/ I/%I/ll/,1 7/ l/1 i111 N u»»> 17d11111 i iq» " Jr/IJJ/JI'»11Ji11111/ lllr,'ll'111f1%l/I/ll,'/rr ffl i%1'!// II UI li,;, llq i i/ ir( ' 1
1/+l .
a ,, o l.•, : , I << .
i
l Y91,'„/( IJGGI (! lUllliduiYrll, f ff ffff / i;, ;.
6tu. k aaE.' a .: O r lda., 221_ oc- ruu Vk: l6c.l; ailnrsrn( 9.. 1&:: itla Fh 11JD11, UUI101 111I11J11J11JDJJ1J11111pV1111 I1//rl11f 1o11 111 I111 J11111„1111 Jll/ 1iiI ll ll I ,,,/, llll, i„ N111 hpplO al9arn F ealds F' uircha/ Inslallatie rr rat i Camplete Equi, m nt description Reba#e Appllca#lon Read r For Pay men# EquYprnent make, i7iadel+ Syste[ r v rifles th t applic ation has p ased all clata insp r,tian' I Include lGarnflrmatlon serl l numu r v lid tican te. ts Pa( Onlino Ap rlic tion) « quiprr errt cast c' te tal cc st Utility verifies Y. hat all sup+ arting rJesci it7ent tir,n h s been filed.

WritCe: n eanfiri, a[ ian nf Prafe sic, nal cor tr cCcar' s name, .... , Systern updates at tus ta` appravad..

F7 bat Number Isr ce pted phcane numtier£ k addre. Utilit. uk mits fil:. t. a ile I ac7rn U" eri'fy y 3 3 Re dyto ubrnitto utility in r ext invoiee InCludFs9$ uppa rtiilig Verify pre errc o# cusTarr er a"
pocumenta#Yon si nat.ur; i F., oc,=a , cv A i. An: s aa<- t u Requiremeni
i
ii ° o%aiij ///,///% iiii i
Tatal nuiTib r of units installed
III u ;;, ....... m l a
m
1 a. .... .
lwed U. ...,.
w. u I I
l orrect e d R bate/ A , wpp 11 at1on Rece C t111trM i, ,, f Datcjtimc re recard d upan receipt
P1V/%, i, f,'! l,f, 211,( r;.`i, IO//!' l,' 1 %////%//% V U1J1'/
ii +
llcYliCy,.... Dcrcurrrenc . 13c.ci Yrar7 L`] at- a. a e I rr. ce 6:;. innYn/. nc9

Page 24 ends

i
ir. ,,..
r.

F o p n
y, 1 11 _ , yt t;
i: o .
fy'
u
Sl' i °
o , e
u, : 5 iti., %
u q h w
f' 4
p1[ 7 rr f rr 16} , I
k v 9i
iV
U VIVO I N 1 w i i. w r I r w . H i f «
b u ui i u i i uil 14 , v
i " „ V ` " r
m u
i
a u, u ro
r
a
I lu
ri V t yb. blk df iC N 1
Vll i4U t i, qni uGor f I V
ii , ,
VI IIII VIIII IIV.,.

C t
iNN d'+ w^
I . r,_ r , p^
I oe,,. F; tf t. h ;
w mn , ........... a.
r r wd I a l, E4 n 2 W. r
Y;
w' N ta at aM M I
u c 9qsm
I A'9"F9n PoiI MY 4fl N 4 k' 4VfiTB"
w , u"k, G- kNY'. 9q4;«""' w . drr.^.,. i,: ti i<. uwr G o t iuRQ tlu , rae ogf:, uti'; e uu iip „° ,
s ,,
o" tl u" krJo C9, G;, om , rc, I a fP" Ge µ, kw
uir¢.,... .. .. .

W,,,.

I
i m c Vf i I" a l tl Ph IW y m t+ tpr
u u
r II 11 1"^ Y! II' Nlili i 3 m S iiK aro r a c uu titk' a 18d ti I l I V+ r d rafl 1; r u r i a au r. am ri
P. i"
i a r, r a w " I C1" Y"" Ir"
RtlPr rc, 4+ u
ub I t
a
i
w
r
a FTM ra a u l i: m a rd wp V a dc^ a i
t G iP i rr p R R ro l I G m i s tl u u w s r,w r p s u' r 9 ra Wuw' a r rrnflr r r mv tln k
M NPiaf wr V u
w Ip e! 94 i
u_......._ _. 6tr rv u i ro 4a ua
umr w+ M' arN u¢ a„ r r m, u, a i k:: ro
a w a u rn
ar° W a
a a I
i a
u
o,., ...,._.. . F i I rY; , rc„ r L° ,,, a, l
1 ; r ; r., ,
I
1r o. N, W, a ..:, .., .,, wa..,.. ,,., . m,.............. ; lff( i Po ""
nP' i m m' Ki
i d. aP r W W" allal 6ab t, N— Re 4
p d w wr k yu, a a h,...an G ro ; k l ww 1 a it t'+
m._ . ._...... ,........ . I;.

Np r""' u u r9 Nuw I whn w 1
w d ar ra
aur a 6 rhu rr 1 arp n u roa a r;Abu w r d la r tCi 4 tl° a W ro& n a 9 91 a i i
p rzr A n a r Qr u« ir m' u c u o
wui w a m. l z
M¢ u nw ap, 1^ t r C m rm, i u E : w ro m r i 1 p u d ma ra ofi i u w R N. 4 wM ii a rt u, ir ia awuu r. u r a l rop^'" W w i a. ; ^ ia.riknw ti,{^ ii a""nr v a n a d. rs' a ak^ s l, mu, a;, k; ifr u^ru mrw u r r rr r, r mav Yr a s u° pa qk r a I ra ra' u i r t
ud wf r ubrr G r. I, uo° au u
iwr^, 3 w" r A 1Ni.'
N19 r d+ 4 Ww b'
r5 __ ._..._. B. la, _
n;[. 1M M1 N.' ti,' N"' I
i P, N C r Sni n sr1 uek,
g,
x M ra q y a uq a a4 iwa k a u o,, V @ 9 w I 4 b
e d. ,
E.. w„ I
sw , „ c: u r a t r uaa N l'
u m....,
w,
w., . ap; ce u
1 u t
r au¢ a" ror¢ a d w w u a ril u ru.,
r
r a urnmiu m N, I a laa Saitin, tl" aa i: x l,wlare nqm C uaPo Page Packet Pg. 348 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric m . u, u ,, ", ,, ,,,, n, m ,,,,
One of the key features of the EGIA Rebate Processing System is its automated Problem Letter generation and follow- up system. If an application is deficient, the ERPS can automatically generate a letter/ email to notify the customer that either information is missing( i.e. customer signature, receipt, etc.) or the application is declined( i.e. non- qualifying measure, duplicate rebate submitted, etc.). In the case of an incomplete application, once a notification letter goes out the system will automatically alert the utility or EGIA processor if the missing information is not provided within a specified time period. At that point a second letter/email can be sent or processing CSR can phone the customer to remedy the deficiency.

Below is a chart listing typical error codes and a sample auto- generated customer email notification.

G
a
iras-r C: npp E pc Es N r n r- rcr E wAt. M ;

AD SALES RECEIPT APPEARS TO BE ALTERED M R
l T CU T4MEI I PPL i D TC I/1C M-, p,
BC SUBMITTED WATER BILL IS OVER 6 MONTHS OLD M R
C- CU 1" C} MEI fUAME, SERUI E AD[? F E vS M, SSifUG Ff C7M fLL M., ft.

CD CUSTOMER ASKED TO DELETE REBATE M D
F : fEEp US7C} MEF^ Sf. E f EIPT: " M.;, f;,

DM DUPLICATE MEASURE A D
DN _ NAN1E 4 1 APPLICAT147f D} ESN' F MA` CH hlf M C1N tLl,_ M. ; I,,

FO NO RESPONSE FROM CUSTOMER M D
lA- Iw14;# IUSTl1LLAT141U ADDI E"vS C} N Fd Ell ..................................................................................................................................................................................................

IR RECEIPT IS ILLEGIBLE
Mfw! M4DEL lUM Ef IC}l`4N F C IPTSi1t Iln c amm tVeror G4 4 d PN fl E,{ rIR{ lW; lf'
NM ; NO CUSTOMER NAME ON WATER BILL „ "'"'' uj
ukv nn nuG A
g
NP t 4:PUE HAS Pf T E UPRLIEDNQ NON- QUALIFYING MODEL NUMBER k IN' 4 t1LILIIY#. R 1S f F INI1' IRL PAPERWC5f2K NCST PF( 7U1DED E Y 9 d F"" LE 4 8' C': 1f NV NEED FURTHER VERIFICATION OF QUAL `°"''"'
4R PUfd HASED E EF4f E 41 AFTEI PF( 7GF
OR COPY OF SALES RECEIPT IS MISSING I u Lp,'" V_ B kILLAa' k. Mq Y PUF7CHl SED 4UE c P+fE YEAf2 AGC7 -! ,,
r, yarc r pgallo ti rn d ar tll a G+, rat uvu rt R bate wr u rt irm ilJm q Iuu nsi + mee cann tl

PF PROOF OF FULL PAYMENT REQUIRED
m rl t dd eµ rac s mq f y ro au ueVa te i 1u t t mr uurca l paan wrra riu Rne cdacuu rerrYaiftiorcw rce auesC F hek w.

P WATEI E iLL NEEDED F4fd A CC} UNTUEI
PP POSTMARK 90 DAYS AFTER ONLWE SUE x^'' 14 611m t' flrur ro; u ir tae i r+ rrrrfi. rd i mtwal l° o- a ra rrrtl+ rv a h Ikau I Gl NUl` QUAl 9F1'( N ITY
w rr ttqa r w rr,a r tl h td s" c urcn, tGua s owo- d m ara tllu r r unC rvu¢rrol rP,

RD NO SALES DATE ON RECEIPT
qy ap rrc aµ i i6 Q wr s t G rm rpm u^ 1 R IX rm asn a u p z a i, au p?,? 1 VF3tlue af aruurr s a tai: i ruv i a at F E F EQU1Ed D EFF#GI PICY f*1C7T MET re c wv tl N., y b rJ S PusC a3 atl rav , yrc ar a,pyrlluc ep ra air n* E 6 pQa re s: o, or uqq x zi e im t cam eY l.

RO RESIDENTIAL APPLICANTS ONLY m eda rit a r u yNu G a a r V° er! 7 irfl u uS iG I T CUvTC} lvaEF I ETUj NED MEf CHAf 1DI E
ur r u ou rratl u0: u¢ N i, r u t o f yao-a p u aau lre mro- i ur d ri mrn rrcaR t um aem mu akar C r p r r, M s a 4 I t w dak. 1Czy b a, uiGal Cur a Q Ih tt, t e c{ evoc e rr uasY IP 4 a IF ic ti, ains ww9th V r ql warec4. urnv a u asn SA NO SERVICE ADDRESS ON WATER BILL u b uasYrc re rM viYNrJkm Bae i ra m irn ercn a N.

S INUAL9D T4F E
R s b w a G r v 36mr, i Ifumru i s1 a p n wm i rfi a a e ropliim, t raa a ma q r nk Cl t wrau UD UTILITY DECLWED r111E receuus si e batle aN m lao m ettn i rage+ u& p si ulbmra tGn rn usstiira Nracu um nG @'Var, r rea pd' s UP PUI CHASE PF ICE MIS b( G:'FI 4M I EGE :"" um s r d ol-.

UZ ZIP CODE DOES NOT BELONG TO SERVI
M i
11` Vu f" itta Hiifl arw B r ICuds& rr cx I I f Pr ceu e siirrc rrY l v r U 9 G 111f1 1f: h ll7'', i3' F GCM1 111r GMb
3 r Yt° akC dtvea ue S' ucate, R0
a a' p arrrt a, d4",' i
B nm t: 4; k ti P' 7 r.. 3' re
r: f, a 1 p r- 73

Page 26 ends

Packet Pg. 349 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric I:: ° u: ": ",,, u :

The following process flow diagram depicts the typical rebate invoicing and check cutting process that is included in both the Hosted Service and the Full Service for the City of Redding. v. .,, w - - o ti..__. ..
a M n, w
a . ,,
r r u @: arz r c 5 p+
I i r
I
w
t l s l mr+ a^ uWuiM
I i m i i
IX' I..
w i . k 8"vi' Y4' ., 6, "." f1,. a
i I DI II li^ g *
9N are w b6w wus * ro a ou„ kn ira, .

II Iqm ` i i ` Q 9roe. rlw r7ir, rau& ns p a s u tu tlh I
I 9uGtl a d r' d"" I Iw MI4uo^, 4,hiu m
II IIIIIIII II IIIIIIIIII II II IIII I III II I i i i u ,,, r ,- ri,,,
i °
u
upo i, uoioioioioiouoiioiomiiiuuuup, iiiipuuuuuuuuuuuuuuuuu uuuuuuuuuuulluuuui uuuuuuuuiiuui, p, @U 1
u
uui,, '
a Y, m..,. a
cm t k a I m a rv r a rr a+ uu a d l i i uw i n I
u, w paw N.' tiv° o' Y z 9v d rk u flrr Wu r if¢, wlf wi, 1 srd RP r' uw a:& aata ir ed dflv`w kt Iru d n r' f, a¢ 4 aMt r r.rlaN+
C" ka 4@y+ q r au u t,ll r n s^ rorc,° o rd' r kN wruAd u' e, Pat r u rY r rnro lih' ku9k rt: a
a...... w ,....
tlw
i a t u mGaGr I y c q`"
p
u9 K' NPr N YF z1 4'
n r
ro
F^ da i w i g irm rvu. u w' vn daamyrdm m r d9tl; dc^ 4u^GwC, u oa a:: w y ti. 4 wrcr Y aa, il ur r, w r a i I,. fliBi yF" r rw h Po o rr w^ Sa a l nn r Broa raa t a a r& r.ns u d iµalu z alu¢ d k a iv „ a N6b, y rr arvirast rmuni! I zWmd,' 9Jre9 d0. I rm s r a u g. g ,u ,'; ` s, F r' ,,,- 1
m
fl,„ .,
Sx1 s
wtl
pz n M1 rru I
a
A uo r rer uax wm, Unu, • , w
II
G
il k, I. M
k dU l it I Y& p,
ui u M,.,, w.. .... . ...... .........

A^
n a a° a ro P"... ... " e PY5 1'f N' r,
r
a, w r
I i u
z ar ra 1 r r:+a r.. .. 8` bt ttaqtirwt rtc&aa p a e amxxu orea uogcuta ku a i ww xoa r n sCw I NwB4* m...,,,,,, ..... ,
o.. ...
dp
adc' r
I A
timiu6 r rh Por i c mudiV wn a ga n c& ea, armur s
l auw LP^ 9..... w..,
e.... , e,
r
4 x i: ! i 1 r 9; , a ; i ,,
P t
f, I P b i= l , i , i I+
r r` M P < „ „,,, ,,. ,, 1
Q
r h r"
a wr, 6+ a ee,,
m mr
u r
A w
m
m aV¢
aui+ a. t m uurfrr
lruma lv e ItR rt6amma 1
i i; t Cu1E pru I s; t nroe6 V hl uaguwrn w 9. m...... ... ...... rt,,;
a
M m
p a it i4s, iN
n wn_ I ,
Y N pa+ afikffi u P a, b va'++ w k+ wM+ n II
I
I
uorauiqaw r h 0 d" uwut tl s^ tl wM anro Y' di° y re. J^ s+ 1. I u, 911° a;+`et4' Page
27 Packet Pg. 350 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric ll f; 1 11 11 . l f; l f; 1 11 When EGIA is delivering rebate process as a comprehensive full service, we us an assoriment of different methods described below to prevent and detect fraud, based on the source of the potential fraud. If the utility is using EIGA' s hosted solution, they may want to consider similar steps to safeguard rebate program funds.

Consumers— For this type of rebate program there is the potential for customer fraud in several areas. A customer could copy their receipt and give it to another person to claim a rebate, a customer could attempt to get more than one rebate for the same device and in rare cases a customer can alter the rebate check with a bogus dollar amount greater than the authorized rebate.

The EGIA' s ERPS tracks customer by name, address and measure making it virtually impossible for a customer to obtain more than one rebate for the same measure. To deal with receipt copies given to another person, the ERPS can capture a transaction number or invoice number from the receipt. The database gives an error message if a rebate processor attempts to enter a receipt number that has already been used by that customer at that address. To prevent check alteration, EGIA uses Positive Pay, a Wells Fargo product that compares every check presented for payment to a file of issued checks. The bank emails EGIA daily to confirm any exceptions. Any check that is presented to Wells Fargo that is not on the list of checks issued, or is for a different amount, will cause an exception email to be generated. EGIA receives the email, giving us the opportunity to review the check and decide if it should be paid or not.

Organization— At EGIA, we prevent the potential for fraud within our organization by carefully segregating duties.

EGIA Chief Financial Officer( CFO) invoices customers and receives payments for rebate funds. The senior bookkeeper prepares the deposit and records the receipt of funds in the general ledger. The CFO records the receipt of the funds in the invoice log file, which is not part of the general ledger. EGIA' s Informarion Technology Department runs the database to generate the rebate checks based on the invoice. The senior bookkeeper prints the rebate checks. The mail processing department stuffs the checks and mails them after comparing the number of checks received to the invoice. Rebate programs have zip code restrictions so no employee can enter a rebate for themselves and use their own address. The senior bookkeeper cannot enter a rebate. The CFO reviews all rebate bank accounts each day, and EGIA carries insurance against employee theft. u, n,
When EGIA provides full service rebate processing, we closely monitor the un- cashed check logs. Once a check becomes" stale", typically after 60 days, EGIA contacts the customer to attempt to reissue the check. EGIA strives for zero unclaimed properry for each of the rebate programs it administers. EGIA' s philosophy is to do everything in its power to get the check into the applicant' s hands. Current program experience is tl at about 99. 5% of issued checks are cashed within 60 days of the issue date. For the 0. 5% that are not cashed, EGIA CSR' s call the customer to confirm their address and make arrangements to void the original check, and reissue a check if appropriate. It is our experience that virtually all reissued checks get cashed, so with our proactive, hands- on process, there is very little unclaimed properiy.

However, in the event that the customer cannot be reached and checks remain uncashed for 90 days, EGIA will document the occurrence, report information to utility management and remit the outstanding funds back to the utility sponsor, or upon instruction from utility program management, roll the funds back into the program. r, m ° n,
The EGIA Rebate Processing System is configured to support a reservation or pre- approval process that reserves funds for rebate applicants and assures that program commitments never exceed authorized budgets. The system automatically tracks program expenditures and provides real- time updates on the status of rebate funds claimed and reii aining in both percentage and dollar terms. This information is accessible to the utility program managers tY rough the online reporting portal( see example of the Metropolitan Water District SoCalWaterSmart report below).

EGIA currently operates a comprehensive reservation/ budget tracking system for all of the water agencies participating in the Metropolitan Water District Commercial Rebate program.

Page 28 ends

Packet Pg. 351 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric w"" ...
p'
uw w°"'"
m sMlba urd Ft parts EGIA a> Craa nm: rci II I
ePonnr lP dn! 8' dVitneni II 6 4n•.m: VAhhai' a
YYam< laM: JXA ..,
TYW: Ciun iizrancivl... W
EI fRF P w.,( IW IJI I IIGIPFkI 41NiFR& TFi Gx „ I
Gt. flf' TC M t I
F.et% TF R1411NGPIIf: IPPA. WkTER fJla' iTPr, fGT
OJ1' i li{ t lY F+teL R+ PFfJyTkil".'f
MaimWnr+ tl oi' Y:

I LMI'iM, C:
tl dL41 d1"F L-0JIT' fRN'
L. k; S' IIRGF. M' r:5 P PLk* ZtClplW' JYATER il5ir IGT' r5v( FftY' N( s: Uf hf, n, n1T I
I N d dllh I I H bll Q I
I<< RUri1CIPF1411' C4k CYI'.' I' PCICf fJl" G4 MYf'_; l'. CYtIIJ' YY Re1aXIM} enr. 1': N II ...... ...... ...... "_ I ....
tle. vYcc: adl
Cip...,,,,.
h fl( L411k. 4 II.!' Dk'rIN

11. i- ,.... f . I.. I ,
x 1 ANII
I Y 2T. 1 1k7.. Ip.X
ilililililililililililililililililililililililililililllllllllllllllillllllll' d r.., , s: i a tv. r,. i , u i-.,, u.

Wl i..< < << v> i, m. an.._ a- viun= w u r ni ii,,; or',, i leSy.,., f f1' 0 d':"" ...

IIIII I IIII II IV ReGat Funds ExPended
Reserwatiam s i7ut tsndang
Fu ds Auailab8' e Frmr New Resexvakians
In order to receive an online reservation, consumers simply visit the online application, fill in a simple pull-down menu to ensure eligibility and provide their contact information( i.e. customer name, street address, email, utility account number and measures to be installed etc.). The system will then auto calculate the anticipated rebate amount and generate a confirmation page providing a unique reservation number and funds reserved.

Once the customer completes and submits the application, the reservation system blocks the amount requested for a period( i.e. 60, 90, 120 days). If a completed application is not received within the acceptable timeframe, the funds allocated to that customer' s reservation willbe cancelled, with those funds being reapplied to the next available consumer. If consumer interest in the program exceeds the level of available program funds, the reservation system is equipped with a waiting list capability, allowing consumers to add themselves to the list on a first come first serve basis.

The ERPS reservation process will auto generate an email notifying the waiting list consumer that funds are now available, confirm their interest and automatically issue a reservation confirmation so that they can proceed with their purchase and receive a rebate.
m "" ", ,
When delivering rebate processing as a full service, EGIA provides comprehensive call center support. To assist management and ensure high quality service, EGIA' s call center is equipped with silent monitoring. Leveraging this

Page 29 ends

Packet Pg. 352 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric system monitoring capability, EGIA management is able to periodically assess CSR call handling performance, and tY rough ongoing program training and evaluation, is able to ensure deliver of quality customer interaction at all times. EGIA' s call center system is also equipped with substanrial call tracking, call reporting and automated call redirection capability. For example, if the CSR group assigned one utilities customer calls is e eriencing heavier than normal call volume, the system can be programed to auto- direct overflow calls to other available cross- trained CSR' s throughout the call center. This enables call peaking to be handled on the fly, with no loss of service or reduction in overall call center performance.

Typical full service call center activity includes:

1. EGIA maintains a staffed, dedicated bi- lingual customer services call center during normal business hours of 8: OOam to 5: 00 pm PST, Monday tY rough Friday( except federal holidays).

2. EGIA establishes a dedicated toll- free telephone line to enable utility customers to automatically retrieve general program information, ask program related questions and inquire in rebate application status.

3. EGIA Customer Service Representatives( CSRs) return all phone messages within 24 hours of receipt, within the business week. EGIA provides after- hours voice mail services for customers calling outside of normal business hours.

4. To maintain high quality customer service and provide accurate program information, EIGA CSRs receive weekly program updates and have online automated informational resources readily available on their desktop workstations to assist in answering customer questions and tracking customer inquiries. CSRs also have an auto transfer capability to seamlessly forward complex or sensitive calls to higher level personnel within the office to assure customer issues are handled with utmost care and professionalism.

5. EGIA' s call center is equipped with industry leading call center management and tracking software that enables comprehensive call monitoring and call reporting. At the outset of the program, EGIA meets with utility program management to determine what level of call center activity reporting is desired by the utility.

6. EGIA recognized the importance of providing superior customer service during every customer touch point. EGIA provides in- depth call handling, delivered through a highly trained and program dedicated team of CSRs. EGIA CSRs focus not only on addressing the customers' immediate inquiry, but also seek to further educate and inform customers regarding utility rebate programs. In support of new program launches, seasonal or special promotional activities, the EGIA call center supports outbound telemarketing to targeted consumers and trade allies.

7. EGIA maintains customer service support, after the termination of this program, until all rebate requests pending have been resolved.
r r;; :: ullk:.

EGIA has developed and deploys a highly fle ble online, secure, and password protected real-time reporting dashboard for its utility clients. The reporting dashboard is designed with standardized reporting that provides program performance tracking information typically required by utility program managers, and can be customized to provide program management with the precise information and format required. In addition to the graphical and tabular charts illustrating program performance, utility program ii anagers will also have 24/ 7/ 365 access to all utility specific data held in the EGIA ERPS system. This data can be downloaded at any time into an excel file for full utility reporting and data analysis.

EGIA' s reporting system is highly fle ble and user friendly and enables the online delivery of graphs and program analytics that allow utility program managers to gauge program participation levels, historical trends and other information that may be used to assess and refine the program.

Page 30 ends

Packet Pg. 353 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Q a ra. d .:` v r a rooz l 1f: Q r il. r u.. m
IIII u"
W I I II IIK"I Ii i
uuuii
evA,
iuu . i
olaiNif" rtn.,, ni N.; ta„ I' vdlruin iul, rr4. nr rhd u1174: 04, d7 U:; r . Inr a' P a. au a P.rlirl.. fJ4A, y+.Yr. uiil . intrnnrLir friF I-„. aiic I I, u i7ir n• F;^„ R. i, y i" iinflrurid I
I
I c rts — Ia, e erut
Ta t? Grntraclara VRS Parkmen" ts Swo noarv VRS Hima ta Pa+ae kTe6ates Tlni tm Pav Reoa rts hw C mntv hau 9obs S 4ro issuvnis Camc la6e d] bs Pimai' ine F. oorks F' raleTts hu LY' tias ia+ mr mNas suY erni te d dtrr' insr yy UP9irad uCali carni prn rs r s p f: C1," 1 C 1 SeemcNu. V ar Co iTRA;; Cac114 '. r y v w u, IC u« Crik u" r, IGusnr d ui u' p A r x. Ft. d s iGa rth r, r ror, ean x' ,. f 1) 1)
Y' i Y Y
i GC
Y { r) a i lr)
y;
J INWN. . . . w' urv. mo. m.'.. i) . . wwwr.. . . . ..., i) . . . .

C t.
f. I .. i .
r
Y .

I Y
I 1 1 1 G. I
I. i 1
Q fl: 1e! 6' ir rtrc Pii' i w q° E. or,_ „ ', ' Yu rt Y` a. w 6n ur v r: u a H ar i ,', , IFru itry 5. v6n u v.°> r. t`p. 9. r,° e t . << r, ., t E i,,
sai, u
z ar r b" sE i
r*`
s
m
a
aw ti d a
i, y ea
IF" i ject f. i li. w
r„ I r ay y nmrt v.' r wt a t s il
5aan, le Size Average e n ergy s vfn...s
52 3Il. 7^2
r ,.,
A ve,rage F2 AweRa e year 6 ui k
r,
2a2 k. 37 59 64
4) W W ,
i
i
I ,°
G; , ;
u
o
NOrE• 7h s daf rrnat: on a rrd data+ s m v' d s is` a nd srrbjert P nn. m,c sentat6e. n w wanankva amy klna; rrvduding fwt. UY fJrrnLed rp ac. uracy naef iakk py, an,,.- alcu` at.

Page 31 ends

Packet Pg. 354 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric N
I w I I II V
IVli l VpuIV...... .
ri ta ,>, >.,. r i,. m n a. a-, ; ,. ia . a. m r n .,.. r , r:, „ . n,. F, .,. , , , ni r, R p ua° ts- t t r a, eAmmeart
i Y. f R. G41REY. dM i.WA#' I, M I i. dA .,!! n.., V, 1,. 1' il l IJH7.. I. Lr.(.?.' IFxik„ fkM? btI. FV: CW.> Al15. d! s. l'n'.hdN. 4, fnaPaXv {„ N.: ni. 9Nf. lidRNlr: Ixl., f.GS: lklf l) kd IFINl M+ hhr'! n.lYelf. 1, 1: Y.YY41Y. 6Rllib;' e I P r Itllr>nfuar: 9. rr
A„. a„ sa;
v, c wcw, r. ae x n
i
nrz„,, d, III I
I IIIIIIIIIIIIIIIIIUIIIIuIII uu umlV ihum u u uu miu m uuu imim IIOIIll011l
eE « „ ,
e nr., z
oe a . P e . ,, . ..

IN'.

IRepo[ is qQeiat onal
e. e Reea aes 1 rtras
ae a srax= s ma.,.

III^ rt!
tt
NaddnOP10 P,} IIn7ANNU Ij IU'
I IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIl PoO°
I MIry IIIIII IIIIIIIIIU PI' e— IuiStxll R_ batE:
y III il II YI I
o
neue
ff, F a. a, sx M
D ''
an
mo o , g
o oan
a 3 lllllllllllri
oA m. ee o 4k. oP o.. 9
o,_ a on = a, a wm. dd _, . AP. E., ,, e. h P i
o, H r mxA P , i
a i
A',
u", p kd "'`"'"'' 1'^' U' k
a= I s-, ix,
r,
a u, a,
aeom, e,.
e! b x
p
R5
s
a H d
sa s e, edevuas
a I
am '+ I
a
e
ne 6
e
E o s od dow
oilm 4 Illu m
r, uw. n u,<. r , , ,, u, ,.. r- ,. A,.. w u „,, r, ,. 9.,:, sp f. 0 f..... ......... tVv. l... ........ ......., I fv,, xv7.... r, , Fl, Rtep rts- Mlar agerr mt
Too C A trxta. rs I RS 9a , t Suinm, rv I VRS TV' me. fo Pav I' f; ilme tn Pav I Re ports bv C Aunh I Nervlo6 s Submessmns 4 mulat9] abs I P' a li'na Pxoorts I P p bV CXtizc Me4w 9nh ul; m'ufs8vms d y M.6at1s{, errctut dv g An eYigi l{ Je( aan cePer, l glk; M!ull ! m udn rm' tiWY+Mu ili u iui i i!! i us "
tlI6+MGvvmi msiiNniainN imVrvi .. iV u w a4 v wmi ru6oMmuv, N{ Nau n4immuni f G' ar' b SNIW Y/ P, fiIE hlewv eab5 uec i' v i i v7 sn Vli au a xmn m zax o aFa
i
f, q e aunx m z- a a^aw lu,
senaosi a i i xas.

NugP 1t 3'$ lJi' s, n. 694
w
Gu 7 LF Ylot
uzorn esa. as o iso ae. o
w Fry-. wi
M.
uN au o a o a c w.,,. „,»° o nnu Pe e
F w
rr
h
r
r , o! m ,,,.. nn.,............,.

MpTE,: SM' JDfPG&E j:h are, caGegr. zaY 6 Ch d G_ su6mvs5ion to E GIA mat wh n theywere su6ma[ ted[ n C& PCA.

Page 32 ends

Packet Pg. 355 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric EGIA has developed and maintains a very robust database management system that can track every element of rebate programs administered by the utility tY rough an EGIA application hosting solution or directly from EGIA tY rough full service deliver. The ERPS can be easily modified to incorporate any unique future requirements. The database supports the development and deliver of all program reporting requirements and product and consumer tracking reports.

Database security and the safeguarding of sensitive customer data is a high priority. The most reliable, rigorous security systems are used to protect program and customer data. EGIA systems are protected by multiple firewalls, SSL security and data encryption.
e _ .. r m° i r f a
u, u" IU" r o n ru ti`" w^ w r l' °" " W 9 9 V s waP aVa r s, a u,
f
i
m , , e „ , a r ' N:+ N!; 9d 1. aV V w$ m' t w k» I! Ib ro W, u" P r+ ` i,' a u w d,,
N ^ a
l
r
P U "
u
ma t
r
a,
a
ir
v, ' j
f'l( v, „.
o,
t
y i Bru4?
F%N N 4P` l,
o
u
N au@ i I n' @ r a
e
I
m e - i, ui" k a a o l o wd ro 0
w a u a awu a
K 4tlw 31v re
inr Y r
dtl r re N: t
r a
m_,.. ... e w,. .,. 1'=,
d k: ce m i ti I k l. ls pn d^'
r'`
f p „
The following is an overview of EGIA' s Information Physical Technology Architecture. EGIA l as deployed a fully redundant IT infrastructure utilizing IT industry best practices, and a state of the art technology stack to ensure the greatest level of data security available while maintaining high levels of performance and reliability.

EGIA' s information technology team has developed an all- inclusive database that maintains the tecY nological security and integrity of the database and accurately reports gathered data. The database features include, but are not limited to:

Automated problem and decline email and letter generation Automated rebate status updates for consumers
Automated safeguards that reduce any deliberate or unintentional misuse of the program by applicants to avoid fraud( i.e. duplicate receipts and serial numbers) A data entry screen that is modeled after the program specific application for fast and accurate data entry Queries that can be written to offer any type ofreporting from all program information Storage of all consumer and product information
Rebate check generation interface

Page 33 ends

Packet Pg. 356 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric EGIA' s ERPS and database management system is configurable and can perform the following tasks:

1. Customer/ product information as received on rebate applications is stored into the database, including:

Rebate number
Application received and postmarked date and control number End-user( customer) name, billing address included zip code, contact name, day- time and home phone numbers and email address
Installation location address including zip code
Device/ equipment place of purchase, manufacturer, model name, model number, unit quantity, unit price and devise specific information
Rebate amount for each measure
Date rebate check is issued and check number

2. During the start- up phase, all program specifications and energy eff'iciency requirements are prograiiniied into the database.

3. EGIA will upload the most up to date list of eligible measures into the database so that the efficiency and qualification of ineasures is immediately determined upon data entry of application.

4. EGIA' s database management system allows up- to- the- minute, live tracking ofrebate program budgets and customer rebate status.

5. The ERPS auto generates problem and denial letters in both email and letter form, for incomplete or ineligible applications.

6. The ERPS is capable of importing records from other source files and databases, exporting data in a variety of formats and transferring data electronically between EGIA and the utility database system.

7. Using a secure website, EGIA provides web access for utility program managers to review comprehensive real-time rebate program performance in a standardized format and have password protected online access to program files and reports.

8. EGIA employs stringent IT security to protect customer data and guard against unauthorized access to customer and program data.

9. EGIA implements routine database back up which includes all transaction logs backed- up every two hours, with a full database back-up every night.

The following comprises EGIA' s network architecture:

Private cloud computing for high availability failover, and Disaster Recover is implemented, providing greater uptime for all EGIA administered rebate programs.

Servers are located in a mission critical data center, with industry best practices in physical and electronic security, uninterruptible power, totally redundant, carrier neutral fiber networks, state of the art environmental and fire detection/ suppression systems, and are SAS- 70 compliant.

Industry recognized security standards for firewalls and DMZ methodologies are implemented to ensure all systems and utility customer data is fully secured. Multiple levels of security are utilized.

Intrusion Detection and Prevention Systems are implemented based on the following:
o Network Protocol Anomaly Detection
o Network Traffic Anomaly Detection
Systems are actively monitored for performance, to ensure uptimes and reliability requirements are met.

Data is fully encrypted utilizing 256- bit encryption. All sensitive data is encrypted and backed up to a secure off-site location to protect against any system failure.

Page 34 ends

Packet Pg. 357 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric ai." d Wfi u" sd l^: T iM" W in 7id" u......._... y
i,, rf//m
i //// r,,/ / p/%frir ++I 1` j
j
i f 19)+ 1 //%/ y 11jN r Uf/r // I fY lg i ll/ re
r
i ! ii ; w i y
JIVv i/Paf// oirJ?' r, ur Il i
i h, u' ro`
y
f
ur
w;,, `° re u b
m
r
m , y ,
d
I
J
u. . 1
e€
I In
i
w
e
r a
r _. ._
z
M
o , . w
F
r
rf
w ;
a:,
w
R flu ar a
s
u
r w w W . u ,,
w+
m a wr
n.
r i r
r,_
o_.
r
z 4 a a
j ,f fi a, a
rl,,, i,:,
J
ii
e .. w. , dw._. ,.. . ..... _ s ....... dw:.. ....... .. .. ee. _ n u:, ,°:

The consumer portal is a secure web based application where utility customers access the online rebate application and rebate status information. The online application portal is customizable to accommodate unique utility branding. Typically, the consumer online application will be linked from the utilities current program website.

Additionally, the utility processing and reporting portal is a secure web based application that enables utility rebate processors to review, validate and approve applications and utility program managers to have access to all program data through the real- time program reporting dashboard. All access is role based and can be authorized by the utility program administrator.

Page 35 ends

Packet Pg. 358 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric l" ":+ w d N" ' w"" 1i""":
w"
a rm , 1+[ J,
O///// D/////% r%/is l G(
r u,
9' rr/i w
I/ JJ, Jli; fi lr+ o
idiu; rria m
r l
ll i
w : , "
G n n, r, ux p
a n
YVN+, w,+ w a- a
r""'.`
w.

M s aw,°.

W
nrta,' r ar a lf^ m il wa ro. uWa w
nw9 pl. p w, w a N wruw d wra4rrm l6l+ m.
u:, , : u,:,,
The following diagram depicts the EGIA high level application communication flows. The transactional data flow is captured at various points. The database where customer data resides is considered critical, and all steps are taken to ensure that security at no time is compromised. Data at rest is encrypted in Advance Oracle databases.

All systems are firewalled. The utility program managers will have access to the on-line reporting portal. This allows real time reports to be generated by the utility program administrators. The detailed level reporting is configurable and can be tailored to meet specific utility management requirements.

I' a° M° r fl i,. kt
buoio Cw' ou i i I p` m'
I
iuiw°'"' P. , w ww uN .
iuu
f
I
t
au
j I
I' ; N, o
l
m
r;' %/
r w;
r
m
r a/
f
1 4
1 i., e,
r
d
z
a
f
f r
I, i/, .. 1,
F i
r u r
W4w WwN'llu w y
I u , r o rv
J
f J
a. . . l
m f
if I f
w w
f r
1 m.., e...... 1
i
f x ; f
r
1 r
t i I
v

Page 36 ends

Packet Pg. 359 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric uu .

WI l I AW.!! L l dI AW. l b" AW.!! V f; LgV Wl l l b" ll l dI AW. l b" AW.!! L dI AW. AW.!! L .... b" WI AW.!! L I AW.!! L User Account Administration
Microsoft Active Directory is utilized for user account administration. User accounts are stored and are syncY ronized between the Primary and Secondary domain controllers, for redundancy.

System Logs
Webserver system, application logs and SMTP logs are stored on the local hard drives of the servers in the default paths.

System Log Process
EGIA implements NAGIOS reviewing application that automate alerts and quickly filter key Event ID codes, alerts, and reports to the appropriate personnel.

System Logs Storage
System Event logs are stored using the built-in process of the applications and operating systems. Windows Server stores the logs on the local hard drives accessible only to Domain Administrators or Local Administrators. SQL logs are stored on local hard drives in different locations.

System Log Review
Default viewers are used according to the application and operating systems. ISA has its own default viewers for Reports and Alerts. Windows Servers Event Logs are viewed using System Manager. IIS services are viewed using Notepad. Managed services and/or hosting facilities are being reviewed at this time. Senior EGIA IT employees are used to review log files.
n u u, n
u_ m, m
Website Vulnerability Testing
EGIA is currently working with VeriSign to perform penetration testing and vulnerability tests on a daily basis.

Antivirus& Anti- Spyware
Antivirus currently deployed on the network is Symantec End- point antivirus.

Security Patch Management
Currently evaluating Kaseya, Microsoft System Center, and Managed Services( outsourcing) to enhance patch management.
r, m , :°„ 1_ m
System Recovery
EGIA utilizes VMWare for high redundancy and failover. The EGIA systems can failover to our secondary VM cluster at any point in time. Recovery time is very fast, and in most cases, transparent to our users.

Application Recovery
Application recovery is executed using the disk to disk backup system.

Recovery Time and Recovery Point
Recovery times are same day or next using the local backup device.

Page 37 ends

Packet Pg. 360 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Karlson, Vincent
From: Edenburn, Amber
Sent: Thursday, November 4, 2021 11: 29 AM
To: Karlson, Vincent
Cc: Hutson, Kamryn
Subject: RE: Piggy- Back RFP
Hi Vince,
I reviewed the information and agree that Anaheim' s process meets City standards and approve bypassing the RFP process to piggy- back off of Anaheim' s contract.

Th nlc you,
Amber Edenbtirn, Purcl tasing Officer
City of Redding
530- 225- 4135
530- 225- 4434
Office Hours: Mondav- Fridav, 7am- 4pm
City ofRedding Facilities are o aen to the public with eqz iretazents to wear a mask ifyou are not vaccinated. Ifyou p• efer, barsi ess can be cor2ducted online at wtivw. cityof eddi zg. org, by ztsing tlte df op boxes locatecl outside tlze facilitzes or by contacting City of Redding depc r•tmei2ts clir ectly by p 2arze at wtivw. c ityofr eddira g.org/contacts. Th.a ik youfo^ yoiir patie 2ce arzd ensur•ing the health and safety ofthe public uncl Cit Staff.'
From: Karlson, Vincent< vkarlson@citvofreddin. ar>
Sent: Thursday, November 4, 2021 11: 00 AM
To: Edenburn, Amber< aedenburn@ci. reddin. ca. us>
Cc: Hutson, Kamryn < khutson@cityofreddin. or>
Subject: Piggy- Back RFP
Hi Amber,
W spoke last vti eek about th r q airemer ts ta allow us to piggy- back onto anoth r campany' s due diEigenc, in arder ko str arnline the contracfi and av ard proe ss to a s lect vendar and avoid the creation af an F Ff and subsequent r view/ selecfoon pracess, by utilizing khat ir ady cr mpl ted by a similar organizatian, Du ing th t conversatior, it was cornmunicated that to be consid red, ot wc uld be pre erable that the origina ing organization be a city or other municipal en ity, and thak their solicitatic ro for bids and award af contract rrairrc r d or was in lin with current City af F dding processes.

Ta bring ya a up to speed, ou cantracf with 6ectric Gas Industries AssQciakion ( EGIA) uvill be expirinc at the nd of fhe fiscal year, and vve have currer tly xhausted availabl contract xt nsions. We have be n happy weth EGIA' s pe formance in regarcls to fihe handling of aur El ctric rebate processing anc the reporteng tha th y
do for us, so would like o continue the relationship if at al6 possible, by vard of a n w contract akilizir g the rec n daa dilig nce ccrrnpleted by a like organiza ion. i
Packet Pg. 361 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric I have spoken ta City afi Anaheirrr, w o recenfly cornpleted the RFP and cor petifiive selectian process fiar like services, and awarded their cr r tract to EGIA { aur curren vendor) to perfa rm services similar to those they currently perforrv far us. ! t appears from that conversation and r view afi th RFF' ar d council report, that their selection and award process is very sirnil r, if nQk identical, to ours.

They published n RFP, r nked th e propos ls received from the seven vendars, and made their sel cfion and recomrri ndation to their city couw cil and subs q. ienfi ward of contract, based or their review and rar lcing af the prapasals received.

I have reviewed the a tached, and f el that it wil! hopefully m et the requirements to allow us to piggy- back anto their proc ss in our selection nd atirvard of a new contract to GIA t a h ndl our li ce r sponsibiliti s.

Ta further complete additional due diligence, our R U Customer Programs department reviewed the w b sites of the responding vendor s to the Anaheim FI, and fe l that based on fhat r view, there wasn' t an ov rwhelmir g desire to explare th offerings of the other vendors eyQnd thafi which had alre dy been completed by City oF Anaheim.

If you could review the attached and advise next steps, that would be uvar d rFul. I am sure thafi Gity of Anaheirn wauld be willir g
ta provide any additional in orrn tion you desir tcr assist in rna6 ing n infarrned d cisic r a d help us rnove through the process.
leas r ch aut to me should you ne ci any addifional ir forrr ation or clarification.

Best regards,
z
Packet Pg. 362 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric II I Ill lllll i n, mH „„
y q ' w °'

CITY OF REDDING
µ m ' REPORT TO THE CITY
COUNCIL MEETING DATE: September 21, 2021 FROM: Nick Zettel, Assistant ITEM NO. 4. 5( e)Director of Electric
Utility APPROVED
BY***
H "_..^" c eticl As istan I7 icat r ra' ct r 1J til[ y )/ 7/ 2O2 y p} aun,' i, , t 41 y
kJ21.
nzettel@cityofredding. org btippin@cityofredding.
org SUBJECT: 4. 5( e)-- Accept the 2021 Demand- Side Management Integrated Resource Plan re ort and arove ad'ustments to Reddin Electric Utilit ' s Customer Pro rams.

Recommendation Authorize the following relative to Redding Electric Utility' s Demand- Side Management Integrated Resource
Plan: 1) Accept the 2021 Demand-Side Management Integrated Resource Plan Report; 2) Authorize the transition of customer incentive programs from energy efficiency to an electrification focus;
and 3) Authorize the Electric Utility Director to make future adjustments to these programs to manage the transition, remain in compliance with state mandates, and respond to community
needs. Fiscal
Impact There are no immediate fiscal impacts related toapproving this report. The recommended transition plan will use existing customer program budgets from various available funding sources, including Public Benefits Program ( PBP) and Low Carbon Fuel Standards ( LCFS)
funding.Alternative
Action The City Council ( Council) could choose to adopt any combination of the recommendations above, and/or provide additional direction to staff.Background/
Analysis Since 2017, the City of Redding' sElectric Utility ( REU) Customer Program Portfolio ( Program Portfolio) has primarily focused on energy efficiency incentive measures that support the State' s ongoing energy efficiency goals. Programs include energy efficiency equipment rebates for residential, commercial, and low-income customers. REU' scurrent Program Portfolio supports the state' s energy efficiency doubling goals under the California Clean Energy and Pollution Reduction Act of 2015 (Senate
Packet Pg. 363 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Report to Redding City Council September 14, 2021
Re: 4. 5( e)-- 2021 DSM- IRP Report and Adjustmen ts to REU Customer Programs Page 2 On March 2, 2021, the Council approved the 2021 Energy Efficiency Potential Forecast Forecast) study and adopted updated energy efficiency goals for the next 10 years. The adopted goals were approximately two-thirds lower than the goals adopted in 2017 due to a reduction in cost- effective energy efficiency potential in Redding. At this time, REU committed to developing a Demand- Side Management Integrated Resource Plan ( DSM- IIZP) that uses the Forecast results to develop a plan to transition from current energy efficiency offerings to programs that align with the updated goals while meeting the needs of the community.

The DSM- IRP Report ( attached) uses a process similar to Redding' s integrated resource planning process but is focused on demand- side ( behind the meter) resources rather than supplyside resources. The DSM-IRP helps support REU' s mission of providing reliable, cost- effective service by identifying an optimal demand-side management plan that achieves regulatory requirements, community and customer needs, and system reliability. The report documents how staff utilized a series of cost and ratepayer impact tests to ensure cost- shifting between participants and non- participants is minimized, and future incentives produced a return- oninvestment result for all REU customers.

Using a five- step approach, REU staff analyzed hundreds of ineasures, including energy efficiency, building electrification, and transportation electrification, to determine which measures and programs are cost- effective for the REU service territory and rate structure. The report concluded that building electrification programs and transportation electrification programs best support the guiding principles identified in the DSM- IIZP as 1) the recommended electrification programs help maintain low electric rates whereas the historical energy efficiency programs provide upward rate pressure, and 2) the recommended electrification programs are a cost- effective way to reduce greenhouse gas ( GHG) emissions whereas historical energy efficiency programs did not cost- effectively reduce GHG emissions.

Building on the findings of this study, REU staff recommends transitioning from the current suite of energy efficiency programs to building electrification and transportation electrification programs. To ensure the success of the new programs, staff recommends a phased approach that will allow time for all stakeholders to adapt to these new types of programs. The proposed schedule to transition from energy efficiency to electrification programs is as follows:

Reduce existing rebate incentive levels by 50 percent on January l, 2022 Terminate existing energy efficiency rebates on June 30, 2022 Launch new building electrification and transportation electrification rebates beginning July l, 2022. Planned rebates include:
o Residential Heat Pump Water Heater Replacing Gas Water Heater - $ 1, 000 o Residential Heat Pump Clothes Dryer Replacing Gas Clothes Dryer - $ 200 o Residential New Construction — Heat Pump Space Heat and Heat Pump Water Heater - $ 1800
o Commercial Heat Pump Water Heater Replacing Gas Water Heater - $ 1, 000 o Residential and Commercial Electric Vehicle Rebates - $ 1000 o Commercial Electric Forklift Rebate - $ 2500
o Electric Vehicle Rebates for low-income qualified customers ( new or used vehicle) - $ 3000
o Community Projects Set Aside for grant matching and other projects related to Low Income Transportation Electrification - $ 325K
Packet Pg. 364 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Report to Redding City Council September 14, 2021
Re: 4. 5( e)-- 2021 DSM- IRP Report and Adjustmen ts to REU Customer Programs Page 3 It should be noted that methods for reporting electrification program savings relative to the energy efficiency goals adopted on March 2, 2021, are currently under joint development by multiple California publicly owned utilities. However, as shown below, staff estimates that the recommended electrification rebates at planned quantities will not achieve the Council adopted energy efficiency goals. Nevertheless, there is sufficient funding available to expand these programs, if appropriate, based on community needs and pending early success of the electrification programs. Once the quantification methodology for reporting electrification program savings has been developed, staff may return to the Council with recommended changes to align the energy efficiency goals and the expected reportable energy savings. f, 1 i ry ir, u-! N ir:: V;:_; & , uir:; A ` i ir y , p: r n a
1 ''° ti,. a
o ,
n, ,
n ' r=.. s,;
Yr raa u,rc14
m0oii,h a" m i V . . . . . . . . . . . . . . . . . . . . . . . . . . . tii r l %l' 1 J
I 1 J
11 , uu
N ''' ll' ,`` l 1' '
F 1 ,,
J I 1;'"'; f
I„ , l P ,
II JI11 iu u 1 , , I
f..

J; lV; '- j I 0 F
1<< f l l, , 1 J 1 1 111 . 1 1 I
I 1 ; l ' -, f
111
F n, 1 il G II, I A I r T
li i - u r, m,:
y
i y u , r ti.; i m.. i . u..,, i u o. i. v , i, i^. 7 .

J .! l,:. h; k 7, F t., f.! l,,,,. , fJ.. s' uY f;;: r., rl'. Y I:' a:Yll r' 4° II
Illlllllllllllllllllllllll ill" 1 4m g''., lir. n:
iB '
l((lflldfflf lifi 0. V da' b 1" Illil' ukIIJC I J4:; 0 , r r r r r YifY4Vll' OaUI " zlllH' s if.:'t"Bx° Cb iil, a i."' u ' J".'. b If the recommendations are authorized by the Council, staff will incorporate the DSM-IIZP Report and associated changes to the Customer Programs into the mid- cycle update to REU' s 2019 Integrated Resource Plan. Staff will bring the mid-cycle update to the Council in the fall of 2021 for presentation, review, and request for acceptance. The goal of the update is to provide the Council with an overall review of REU' s portfolio efforts, including potential updates to the Customer Programs.

Council Priorities/City Manager Goals
Government of the 21st 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
2021 Demand- Side Management Integrated Resource Plan ( available online) Previous Staff Report - March 2, 2015, item no. 4. 5( a)-- Authorization to Submit Redding Electric Utility' s Energy Efficiency Potential Forecast Study ( available online) Packet Pg. 365 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric ni
III IVn, C W
Wlllllllllllllllllllllllllllllllllllllllllllllllllllllllm m
I
Ilq I IWuuuuuu i
II
i miiu miiu iiio

IIIIIIII
Illlllu
IIIIIIII IIIIIIIIII IllllluIIIIIIII
Illlllu

IIIIIIII
IIIIUI
IIIII
r
I , . .. I i IIIIIIIIIIII W
w I w uu
uiiiiiii
Packet Pg. 366 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric II
w
iii° iii°
Acronyms, Abbreviations, and Definitions List.................................................................................... 1 DSM- IRP Project Partners................................................................................................................... 4

1. 0 Executive Summary................................................................................................................ 5

1. 1 DSM- IRP Process and Recommendation .................................................................................... 5

2. 0 Purpose and Background........................................................................................................ 9

2. 1 Overview of the Demand- Side Management Integrated Resource Planning Process ............... 9

3. 0 Overview of Methodology.................................................................................................... 10

4. 0 Guiding Principles................................................................................................................ 13

4. 1 State Laws, Policies, and Regulations....................................................................................... 13

4. 2 Rules and Requirements Related to Funding Sources.............................................................. 18

4. 3 Community Feedback from the 2018 IRP Process.................................................................... 21

4. 4 Precedent from the 2019 NEM 2. 0 Solar Committee............................................................... 22

5. 0 Identify Key Assumptions and Cost- Effectiveness Tests......................................................... 25

5. 1 Avoided Costs............................................................................................................................ 25

5. 2 Cost- Effectiveness Tests............................................................................................................ 25

6. 0 DSM Program Options and Portfolios................................................................................... 29

6. 1 REU Existing Programs.............................................................................................................. 29

6. 2 Comparison to peer POUs and IOUs......................................................................................... 33

7. 0 Measure and Program Analysis............................................................................................ 39

7. 1 Measure Level Results ............................................................................................................. 39f

7. 2 DSM- IRP Program LevelResults................................................................................................. 41

7. 3 Conclusion and Future Planning Efforts.................................................................................... 41

8. 0 Electrification Program Development................................................................................... 43

8. 1 Building Electrification Program ............................................................................................... 43

8. 1. 3 Education and Outreach ........................................................................................................... 44

8. 2 Transportation Electrification Program.................................................................................... 45

8. 3 Electrification Program Budget................................................................................................. 48

8. 4 Electrification Program Implementation .................................................................................. 49

9. 0 Conclusion........................................................................................................................... 50

10. 0 Appendices.......................................................................................................................... 51

10. 1 Appendix A: Avoided Costs....................................................................................................... 51

10. 2 Appendix B: Retail Rates and other Costs................................................................................. 53

10. 3 Appendix C: Formulae Used to Calculate Energy Efficiency Cost- Effectiveness Tests ............. 56

10. 4 Appendix D: IRP Customer Survey and Survey Results............................................................. 71

10. 5 Appendix E: DSM- IRP Measure Results..................................................................................... 75

10. 6 Appendix F: 2021 Potential Forecast Study Goal Comparison ................................................. 81 II rlliVa;; a, a u o il. u iil 1. 11
Packet Pg. 367 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric LI S" " L S
Table 1- 1: Summary of Cost- Effectiveness Components for Each Measure Test......................................... 6 Table 1- 2: Program Performance of FY 2019 EE Programs ( Historic) vs. Future BE and TE Programs..................................................................................................................................... 7 Table 3- 1: Tools Used in DSM- IRP Study and Analysis................................................................................ 12 Table 5- 1: Summary of CSPM Cost- Effectiveness Tests.............................................................................. 26 Table 5- 2: Summary of Cost- Effectiveness Components and Treatment................................................... 27 Table 6- 1: Residential DSM Portfolio Measure Comparison ...................................................................... 37 Table 6- 2 Commercial DSM Portfolio Comparison..................................................................................... 38 Table 7- 1 DSM- IRP Study Measure Level Results....................................................................................... 39 Table 7- 2 DSM- IRP Study Results................................................................................................................ 41 Table 8- 1: Existing Residential Buildings Electrification Program Details................................................... 43 Table 8- 2: Residential New Construction Building Electrification Program Details.................................... 44 Table 8- 3: Commercial Building Electrification Program Details................................................................ 44 Table 8- 4: Transportation Electrification Program Details......................................................................... 46 Table 8- 5: 10- Year Electrification Available Budget forecast summary...................................................... 48 Table 8- 6: 10- Year Electrification Planned Expenditure Summary............................................................. 49 Table 8- 7: Measure Quantities included in Planned Expenditure Summary.............................................. 49 Table 10- 1: Avoided Cost Forecast by Component, $/ kWh........................................................................ 51 LI S" F F I S
Figure 2- 1: Example of Various Costs and Benefits Evaluated ..................................................................... 9 Figure 3- 1 Critical Steps in DSM- IRP Development..................................................................................... 10 Figure 4- 1: Timeline of Key Legislative Actions Impacting DSM- IRP Planning............................................ 14 Figure 4- 2: NEM 2. 0 Avoided Cost of Site Electricity.................................................................................. 24 Figure 10- 1 2021 Energy Efficiency Goals vs. Estimated Net Energy Savings............................................. 81 II rlliVa;; a, a u o il. u iil 1. 111
Packet Pg. 368 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric

I I , I I I I
AB Assembly Bill
CARB California Air Resources Board
Carbon Allowance The amount of carbon allowed to be emitted as authorized by the government; an allowance is commonly one ton of carbon dioxide CEC California Energy Commission ( also Energy Commission) CO2e Carbon Dioxide Equivalent
COR City of Redding
CPUC California Public Utilities Commission
DOE Department of Energy
DSM Demand- Side Management; refers to initiatives that encourage consumers to optimize energy usage
DSM- IRP Demand- Side Management Integrated Resource Plan Energy Commission California Energy Commission ( also CEC) ES Energy Storage
EUL Effective Useful Llfe
EV Electric Vehicle
FES Federal Environmental Surcharge
FY Fiscal Year ( July 1- June 30 for Redding; October 1- September 30 for the US Government)
GHG Greenhouse Gas
IRP Integrated Resource Plan
LD PEV Light- Duty Plug- In Electric Vehicle
LIEEP Low- Income Energy Efficiency Program
MMBTU One Million British Thermal Units ( 1, 000, 000 BTU) MT Metric Ton
M W Megawatt
MWh Megawatt- hour
f r,rr„ rijnn a, k515rr vi Ylr„ i, a, ri: i I", r
fii ihYlr„ i, a I.. I at f l 1.

Packet Pg. 369 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric NCPA Northern California Power Agency
NEM Net Energy Metering
NSPM National Standard Practice Manual
PEV Plug- In Electric Vehicle
POU Publicly- Owned Utility
PUC Public Utilities Code
PV Photovoltaic ( solar)
RE Renewable Energy
REC Renewable Energy Credit
REU City of Redding Electric Utility
RPS Renewables Portfolio Standard
SB Senate Bill
Scenario Portfolio of ineasure options used for comparison STATE State Regulatory Surcharge
Therm Measurement of heat equivalent to 100, 000 British Thermal Units ( BTU) ZEV Zero Emission Vehicle
f r,rr, rijnr a, k515rr vi Ylr, ii, a, ri: i I", r
fii i' rYlr, ii, a I at f l ,,
Packet Pg. 370 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric j
GDS Associates Consultant who aided in IRP development, ensuring all mandates were met; Modeling software company
ESP Portfolio modeling tool
Ascend Analytics Consultant that developed avoided cost study Itron Load forecast company
I`; 91VI 11 1' I' rr,; I, r;. I I' r P: rir,;5r a I 1.

Packet Pg. 371 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric I
This report documents the City of Redding Electric Utility Department' s( REU)" Demand- Side Management Integrated Resource Plan" ( DSM- IRP). The DSM- IRP uses a process similar to Redding' s integrated resource planning process but is focused on Demand- Side ( behind the meter) resources rather than supply- side resources. The DSM- IRP process helps support REU' s mission of providing reliable, costeffective service by identifying an optimal Demand- Side Management plan that achieves regulatory requirements, community and customer needs, and system reliability.

1. 1 DSM- IRP PROCESS AND RECOMMENDATION
The DSM- IRP followed a five- step process described below. v 1 ms 5!, " III a III I, i u IG i IG i u IV m
In Step 1, staff reviewed all funding requirements, relevant statutes and regulations, community feedback, and City Council determinations from the IRP and the NEM 2. 0 committee. Based on this information, REU staff developed a set of principles to guide the planning process. These principles are as follows:

JJJJ: Offer measures where program participants save money JJJJ: Ensure customer programs do not cause transfers of funds from participants to nonparticipants JJJJ: Focus on programs that cost- effectively reduce carbon emissions n'
m
sil'. i"' o
h" a' III.!' II1 16' I' III" Pi."' ll rrrrrrllR YIIIV; I II, XW IV re. U ll ' rrrl l' u l I V."' PyV° r r II'° rrrl' m
In Step 2, staff reviewed the industry cost-effectiveness tests and selected the tests that would best reflect the guiding principles. The primary tests evaluated are as follows:

JJJJ: Total Resource Cost Test( TRC,$): The TRC is the primary cost test used in the evaluation of energy efficiency programs across the nation and within California. The TRC compares the lifecycle avoided utility cost to the installed cost of an energy efficiency measure. The shortcoming of the TRC test is that measures identified by this test as being cost- effective tend to provide upward rate pressure, thereby creating a fund transfer from nonparticipants to participants. The TRC does not yield results that align with the guiding principles identified in Step 1 and is not used in this analysis.

Utility Cost Test( UCT,$): The UCT compares the lifecycle avoided utility cost to the utility rebates and program overhead of a measure. Like TRC, the shortcoming of the UCT test is that " cost- effective" measures tend to provide upward rate pressure, thereby creating a fund transfer from non- participants to participants. The UCT does not yield results that align with the guiding principles identified in Step 1 and is not used in this analysis.

JJJJ: Ratepayer Impact Measure ( RIM, $): The RIM test calculates the utility lifecycle net revenue impacts of a measure. A measure that passes the RIM test provides downward I > rr5r, i., iPivr , Yi. arrii' r i l;
Packet Pg. 372 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric rate pressure and can help identify measures that align with the guiding principles because it provides benefits to both program participants and non- participants.

JJJJ: Participant Cost Test ( PCT, $): The PCT calculates net measure benefits to a customer over the lifecycle of the measure. A measure that passes the PCT test is cost- effective for a customer and can help identify measures that align with the guiding principles.

JJJJ: Carbon Impact Cost Test( CIT,$ Metric Ton of GHG emissions reduction): The CIT, a City of Redding specific metric, is the ratio of lifecycle rate impacts of a measure to the lifecycle GHG emissions reduction of that measure. The CIT helps identify measures that help costeffectively reduce carbon emissions. Note that measures with a positive CIT save carbon while providing downward rate pressure.

The three cost- effectiveness tests used in this analysis are the RIM ( ensures that non- participants are not negatively affected), the PCT ( ensures that participants are not negatively affected), and the CIT quantifies cost- effectiveness relative to emissions reduction). The components that are included in each cost- effectiveness measure are shown in Table 1- 1, where the three metrics that align with the guiding principles are highlighted in blue.
i , I I I I II IIIIIII I 1111 IIIIIIIIIIIIIIU IIIIIIIIIIIIIJI II IIIIIIIIIUJ I I1 U I 11111111111111 I1 I i IU11 11 I II I I1 III 11 lll 1J IJ 111II1 11 i II 11IIII l , I 111111 1 111111111 1 1 111 1111111 1 I I 1 1 1 1 II 1J 11»»>» 111111J1111 11J11 1 11 1 1J11JJ1J1JJaJJl1J1J1JlJ1JJ1JJJJJIJIJ 1JJ1J l 11J l JJIJJJIJIJ aJJ1JJ JJ1JJl»>>»»» 1 , > > > , , , , i»»> 11 1, 1,>»> l,>>» 1J11J, Jl>> 1>>1»a 1>> l>>>i JJ »> 1 l, Jll»al11 a J<< 11J »>> 1 l,>»>> I» l l>> 1J »>> 1 >>>>> a>>»> I»> ,,,,,,,, a ,,,,,,,, 1,,,,,,,,, 1,,,, 1,>> GHG Emissions Reduction X
Electric Energy and Capacity Avoided Costs X X X X
Other Fuel Savings( natural gas, fuel oil, propane, etc.) X Non- Energy Benefits( e. g., water, O& M costs, etc.) X Environmental and Health Benefits
Incremental Costs for Measure and Installation X X
Program Administrator Overhead Costs X X X X
Incentive Payments Paid by Utility X X X X
Customer Bill Impact X
Utility Revenue Impact X X
r.' IlII', Yklld °" °' I II IIII IIII! i llll`" & , u° i :""' 1 11\\ C,! pII Yf' PiPi ,&: IIIIIIIIB Q IIYf'! pllYl° i Q: If. raV`° YI i" h' raV° ill., lf.' rpfi"'". w:. Yv m
sil'. i"' , aa' III.!' 111 16' I' m. U ll , IIIIm. U m. l°.!' IV u". i"' I` o.!' m. Urrrlli R'.!' h 1° II, XW IVmm In Step 3, staff defined detailed characteristics of each measure, including measure cost, useful life, electricity impacts, fossil fuel impacts, and many others. This information was used to model the impacts and calculate the cost- effectiveness metrics in Step 4. n' ms 5!, V a I' a, ° yn III. 5'. ulull m , y ull rr ium In Step 4, REU staff analyzed hundreds of different measures, including energy efficiency measures, building electrification measures, and transportation electrification measures. The results of this analysis are shown in Table 1- 2, which quantifies the performance of past and future programs using the cost tests I > rr5r, i. iPivr. , Yi. arrii' r i fS
Packet Pg. 373 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric shown in Table 1- 1. Past programs are based on FY 2019 actual results, and future programs are based on measures expected to be installed in FY 2023- 2027.
i , i + irrr 1 I III ,:,». ,». i i II III III IIIII 11111. l JII111, 1I II III II I111111 l 1111 1 iiII IIIIII111111 I11J 111 I Jl 1 J1111 JJ111111111JJJJ1IJ J JJ t a 1 ilItlr1r»l 111 11111 ll l l l J, J 1 1 1JIJ JJJ 1J1 1 1 rJl JJ 1 1 1JJJ J JJ rr Ir ffJ6 ill l 1 1 r li V J lla,, 1 lllll»» lliI iJ I l ul»i JI 1 J Juuui l i iii i i i 1 I l, f
l, ll, la f 1 1 i i 1a ll l11 a laa laaaa
i J J
l 111 J a11 f1 aala1 1J I»>I>> 1 1,1>» t , 1
f11 1 1 Jll 1 , , 1 I 1 i > > l 1 Jf. . . l . I l l . l . . . I 1 . . l,,,,,,,. . Jl,,,,,,,,, 11 Jll1. l 1J11 II . II . I1 . » al 1>>>»»>>> l, ii>> 1.». . 111J J 1,,,,,„ r,,. f,,,„ Energy EffiFY19 Rebates $
4, 090, 000 (; G,! r fcJ, UUU r fcJ 950, 000 r° 7Cl, UUU 8, 330 Shade Trees( FY19) 160, 000 1. 8U, UUU IC U 80, 000 1 1 U, UUU 240 Low Income Direct Instal)
FY19)
460, 000 C' 7Cl, UUU rC U 500, 000 18U, UUU 1, 230
Residentia) Energy
Discount( FY19)
Z 930, 000 (, U: 1 U, UUU N/ A 3, 010, 000 0 0
Public Streetlights( FY19) 0 1: 1. U, UUU p U 210, 000 90, 000 500 Building Electrification $ 6, 860, 000 $ 1, 560, 000 70 1, 970, 000 $ 3, 530, 000 20, 780 Transportation
Electrification
1, 280, 000 500, 000 110 500, 000 970, 000 7, 610
ll : a lk. ll ° Id': ua o- a u° uo I o- 9: uuuo a iryGa, a II l ' U , Il o-;" u a uu° oa IP u4 o-. ii° 4 IV' i ii u I' a u yin; 111 Il o-;" u akuu Based on the information in Table 2, REU staff found the following:

JJJJ: All energy efficiency measures and rate assistance fail the RIM test, indicating that these measures create a transfer of funds from non- participants to participants through increased rates.

JJJJ: Energy efficiency measures are not a cost- effective way to reduce carbon since they are 10- 40x more expensive than the current carbon credit allowance price.

JJJJ: Energy efficiency measures are cost- effective for the customers who participate in the energy efficiency programs, as indicated by a positive participant cost test.

JJJJ: Building Electrification Measures pass the RIM test, indicating that they will provide downward rate pressure.

JJJJ: Electrification measures are a cost- effective way to reduce carbon emissions in that they save carbon and provide downward rate pressure. Furthermore, electrification programs are the only programs that create a positive return on the investment of Public Benefits funds.

I > rr5r, i. iPivr. , Yi. arrii' r i 7
Packet Pg. 374 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric l1., u lo
m
si 15'. i"' I Ai a '." V.!' I XW; m III.'° XW YII II Yn IY! i"' II. N I u @' m; U YII II I I m;` yY Building on the findings of this study, staff recommends ending the current suite of energy efficiency programs, and transitioning to building electrification and transportation electrification programs. To ensure success of the new programs, staff recommends a phased approach that will allow time for all stakeholders to transition from our current EE Portfolio to a new building electrification program. This allows for adjustments to be made as new measures are introduced and allows time for participants and non- participants to become familiar with the new programs. The phased approach includes:

JJJJ: Commercial and Residential Electric Vehicles
JJJJ: Electric Forklift Rebates
JJJJ: Low Income Residential Electric Vehicle Rebates
JJJJ: Residential and Commercial Heat Pump Water Heaters Replacing Natural Gas Water Heaters
JJJJ: Electric New Home Construction
JJJJ: Custom Community Projects
REU has identified a budgeted need $ 2, 795, 000 between FY 2023- 2027. However, REU has identified budget of nearly$ 7, 000,000 for the next 10 years. As these programs mature, building codes change and REU responds to community needs, more programs and measures will be developed and the remaining budget will be allocated. Future measures that may be considered as programs mature include but are not limited to the following:

JJJJ: Residential and Commercial Heat Pump Space Heaters Replacing Natural Gas Furnaces JJJJ: Induction Cooktops
JJJJ: Panel Upgrades
JJJJ; Residential and Commercial EV Chargers
I > rr5r, i. iPivr. , Yi. arrii' r i
Packet Pg. 375 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric

2. 1 OVERVIEW OF THE DEMAND- SIDE MANAGEMENT INTEGRATED RESOURCE

PLANNING PROCESS
Integrated resource planning is a process undertaken by utilities to develop a long-term plan that identifies adequate resources to meet future peak demand and energy needs and deliver safe and reliable power while minimizing costs to customers and impacts to the environment. Typically, an Integrated Resource Plan ( IRP) focuses on the resources needed to meet the predicted customer load over a longterm planning horizon of 10 to 20 years. However, utilities can significantly impact the customer load by offering Demand- Side Management ( DSM) programs that alter customers' energy consumption and behaviors.

For this study, REU is applying the integrated resource planning process to evaluate the costs and benefits of various customer program options with the goals of maximizing customer benefits, minimizing costs, and meeting all federal and state regulations. This Demand- Side Management- Integrated Resource Plan DSM- IRP) uses sophisticated analytical tools to compare program costs and benefits, and quantify the impacts of these programs on Redding' s customers. These tools simulate the hour- by- hour effects of various DSM technologies on the utility system, perform lifecycle cost and benefit analysis, and allow city staff and policymakers to identify the preferred portfolio of programs. Figure 2- 1 shows an example of some costs and benefits that are evaluated.
w , w„
I,,,,, al;;;;,;;;;: I,;;;;: f,,,,, I
w„
I,,,,,
r,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,, l1fIIIII,tIIfIIIIf lf lllll 1 llf
lflllllf
i,„,,,,,,;;;;, If,;
l all
fllfffffl fl l
il II
f»>»»>»»»»> i»»»»»
f
fff a
f,,. f » , , f
J (( I 11lJJ l j J11 JIJ JJJJJJJJ 1»I J1JJ 11JD1J1/ JJI 1 w
I I
ii ii II I Ip G m UI f U P P r a I uuu
m m
ii.

II II"' y"
I, Il dr ""'°. 9" rlkllll"' P;" Ild' Ql" a IVII IlQlll , Ql° i° i rii llllYl, kd!" II" Yld' II° i . A\ CrlVllll r, ll u!!16':;I I' iarr.5r, r i i: i I" . I.., rr, i. ari: i
Packet Pg. 376 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric I
The critical steps of the DSM- IRP development undertaken are shown in Figure 3- 1.

I" I w wl. wiu Jll l" d l wiu ` d l l. l wa
Va u: u a: uu a . u u: uu a . uu a uu. uu e u:^.
rc V" rc::' V" 1': V" V' Y1V" V' Y1. VV" V': V" V"':' rc" V"' rc:' Q':' V" V V" V" VV" V' Yl' V" V': rc" x:' t0/ rc V" Q''. s': mV p" s' mV..: mV p' .&".: mV rcs_ . V" V" rVV YIa: mVV" tl mVQ Q V"' rs" s mV mVV"'':' : mV mV"' s mVV" tlQ I: u q
n,. u a I: u. u: u^; ua a uu a: u a uu a.

I I wd l` nl W JI ` d la d ll I w
n nl W` d ll Wa l Wa"`
mV" s" s4. VV YI.': V" tl" s':' mV': V Q V"_'' V" tlmVV" tl: mV V YI. mV::" s" s4. V: mV" s V" mV':_'' V"_': mV" s:" s,, mV Q_' Q s:' V"_': mV" s:"' sn V YI_' mV"' s4. VV"_': s: mVV" tlQ V YImVV" tl':'_' V" rs. d''', x:`':: u' V" V'^ x:': s : rc: V''':: :': V IYI VY1. uV" Vo:°". 6". u: rc". rc V" VQ : rc V" V p' u a :: e. u u C° C V f u e.: u u^;.

I I wd l` n d ll• ` I W" I W I' ' wiu' ` d la d ll` n l. u^
s: mVV" tlQ .' V" V" V YImVV" tl:': mVV" mV::' V"" s:: s' ' mV:' V YI' mV s4. VV"' mVV" tlQ . V" V" mVV YI.

I W
n' d l I. an` d la I I Wd I` n
I W nI W I WI I. d l
u u r C° C V . r.: u uu a ua u: u :: uu u: u : : I un: un. u u^ : u: I: u u o u: : . r. u: u n.

I I W Wl. l w nl W l wl I Wd I d l"' ' wiu I. I w I wd l` ` d l I. d l C.( u. e u . uu. u e^; . u e u e. u::^; I. ua: uu a n. u:

VV" VQ V" V'. , V" V Q' V": V" rc V" V s': V" V' V" V" V' Yl:. VV" V"' V" V:" x: rc:' :'. V':. VV"'" x: rc:'.

V" tl': V"':' V" mV mVV" tlQ . V":' s" s' V" mVQ_': mVQ 4. V s: CYI' V" tl:" s':':'' . mVV" tl,, as4. V:' mV" s: V":' V" mV' V" V" V" m11V YI m11Q Q': V" tl" a V" zs4. V p': V" m11:': V" tl" a.

W W I' JII Wd l` W JII w d l` w d l . . JII `
C. : l f a:. u e u:: a l u: l e uu: u u uu a : u u n. u:^ n,:. u u u r'; u. u u: u u ua ^.. ul r o: u u u:: a u u: v ru: . u u:. uu r u:
n
o
u.. u: ul.

II u i, o- ° M N. , u u uu! a ll ° II iiuyi °°" Illl l' ll ! r ll ll. u° u nu y°°.

GJvrSrvir iv r P IVIr Pl ir: ir, lr.; i 1. f: 1
Packet Pg. 377 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric To compare the merits of DSM resource options against other options, the DSM- IRP utilizes various tools and methods to quantify these resources' financial impacts on community stakeholders. For this DSMIRP, all costs and benefits are monetized and compared on a net present value basis over a particular measure' s lifecycle. Such modeling allows various measures and scenarios to be quantified in terms of present value financial impact on the community.

This analysis utilizes a suite of complex analysis tools and industry standards throughout the planning process. A brief overview of the study and tools used to support the analysis is shown in Table 3- 1.

IIII I II IIIUl,,I1 111111111 II1 I 1) 1 , 11IIJJJ111) 1 Il111111111 IJJ IUI l111,,IU III111111111111 J II IU J1 f IUI l11111111 I I II II111 IIIIIII lll II I II II1 I 11111111111111 1 11 1 1111 1111I 1111111111111JJ1J, 1 1 I I I11 1 11111) 11 . 1 )) 111111 II I1 1J I I)))) 1 11111J)) 1 J))) 11 1))))))) 11 11 IJJJ, JUl11 U11111111 JUI ) 11 ) JJ ,,, J) J 111I 1J 11J)JJ I111JI11) 1 JJ 1J JJJ J l i rr ri i i i rlr rftlrrr r r rtrtrlt r l . fr rll r iliI i>» ili ii fl frl ili l>»i 1 f t ilili>»Jlr rr lrl rl f/ 1 f111ffifflffl r1 rritlrrtrl( rlrr iff fll»ft, fl ffl»/»irlJf fllf f i, 1a1 1111>» lfll» ll»„ 11/ 11» I ll ll,»,» I 1, f i flf ff>>rl llff f 1111 f f fflffff rt t1 1lf11ffltllt,ff1f>»llffllf il t The REU long- term load forecast, developed by ITRON, is used as the base- case load forecast. Any impacts of DSM programs are incremental to the base case.

Ascend Analytics PowerSimm planning software is used to develop the utility avoided cost, inclusive of all generation, transmission, Develop Key Assumptions
distribution, carbon and renewable fees, and all other fees.

Step 2: The CPUC Avoided Cost Calculatorl is used to develop an avoided cost forecast for natural gas rates.

Identify Key
Assumptions& The" 2017 CMUA Savings Estimation POU Technical Reference Cost- Effectiveness Manual" z is used to define energy efficiency measure impacts, load Tests shapes and other key characteristics.

The basis of all cost-effectiveness tests used are defined in the Develop Cost- Effectiveness
National Home Performance Council, Inc., Resource Value Tests
Framework" .

When necessary, REU has modified the tests to apply to the specific needs of the Redding community. All tests used in the analysis are defined in Section 5. 2.

Define all characteristics of each measure including measure cost, Step 3: base case cost, utility rebate, utility administrative and overhead Define cost& performance
costs, energy savings, measure load shape and others.

Identify&
characteristics of each
Characterize DSM
measure and program.

Develop and document assumptions for all measures that are not Program Options defined elsewhere.
and Portfolios
Identify measure groupings as appropriate into programs. This allows the cost-effectiveness tests to be applied at the program level when appropriate.
1 https:// www. cpuc. ca. gov/ general. aspx? id= 5267
z
https:// www. cmua. org/ energy- efficiency- technical- reference- manual 3 https:// www. homeperformance. org/ sites/ default/ files/ nhpc_ nesp- recommendations_ 20140816. pdf GJvr,=rvir iv r P IVIr Pl ir: ir, lr.; i 1. 1.

Packet Pg. 378 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric ii IIIUl,, IIIIIIII11J11JJJJ1 11iii 1) 1 , 1 JJJ111) l11JJJJJJI IJJi lJ11,,1 11 111111111111 J IU J1 i i lJJ11111111111111111 1 ii Illlll ii II I IIIII!!!!!!!! iii 1 11 l11111 1 11111111J11111111!! 1 l i 1l, i 1111111J1 ii > > 111111111111I1111 Il 1 lJJJJ1111JJJJJJJ 1 11 IJJJ, JUl11 U11111111 JUI ) 11 ) JJ ,,, J) J 111I 1J 11J)JJ I111JI11) 1 JJ 1J JJJ J 1»>> l>»,>»> f al>>>, I>>>> 1>»> rfJJI JJ1>> ff»J , , 1>>»» l>>>>>»>> r 1 11, 1r l>>»»» l>>>,>»> i I>>r1rJ r J 1JI fJ J11J ff>»i 1JJIJJ1 flflf JJ JfJJ11 11 11f1 Jf f rJJJJ t1JJ1 JfIJ J r11 J111 Jrt 1»ffrf1tfl»tf1 111 ft11ff l . frflffJ1»»> ff>»»»> fflff fJfr11 Jf lff tf Analyze DSM portfolios and All measure, program and portfolio attributes are loaded in the Step 4: identify the programs and Statewide Energy Efficiency Planning tool," ESP Portfolios," which measures that best align quantifies the costs and benefits of each measure.

Perform Analysis with guiding principles and
and Identify cost-effectiveness tests. ESP Portfolio Results are post- processed to determine costPreferred Plan effectiveness parameters based on the cost- effectiveness tests developed in step 2.

Develop a plan to transition from the current State of DSM program Step 5: offerings to a preferred scenario. Quantify load impacts and revenue impacts and budgetary needs.

Develop Preferred Develop 10 year DSM
Program plan to define
Scenario into a Develop criteria and methods for making future adjustments to the criteria and rocess for adProgram
p preferred plan to allow flexibility for new measures or changing Implementation
hoc adjustments customer needs.

Plan.
ll : a lk. ll M ° 111 a a lla .. 4 n; iiiry °" h IIIG'' il' ll ° ii,;+ a iryi, N 04uyi a ll+ ii GJvr,=rvir iv r P IVIr Pl ir: ir, lr y.; i I,,
Packet Pg. 379 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric

I I I I
The Guiding Principles represent a summary of legal requirements and local policy goals REU staff must adhere to when performing analysis and selecting the optimal scenarios. The Guiding Principles are the essence of the planning process, and changing these principles could significantly alter the planning process' s outcome. To develop the Guiding Principles for this study, staff reviewed all applicable laws and regulations, reviewed the relevant community input offered during the 2019 IRP development, and studied the materials developed during the NEM 2. 0 Rate setting process. From this voluminous body of laws, community feedback, legal opinion, and precedent, REU developed a short list of Guiding Principles to govern the planning process. The details of this effort and the resulting principles are documented in this section.

4. 1 STATE LAWS, POLICIES, AND REGULATIONS
While Redding is subject to legislation and subsequent regulations related to publicly- owned utilities POUs) it is not subject to direct regulation by the California Public Utilities Commission ( CPUC). There are, however, other regulatory bodies that do have oversight over aspects of Redding' s operations. These include the California Energy Commission ( CEC) ( RPS and IRP) and the California Air Resources Board CARB) ( environmental aspects of energy use). Public Utility Code sections 454. 5 and 9615 establish the prioritization of energy efficiency, demand response, and renewable energy. These code sections and priorities affect the planning and reporting rules ( e. g. AB 2021). As a whole, the various laws and regulations provide a framework for developing guiding principles and plans. This section explains various California laws and regulatory requirements passed in recent years that apply to Redding and are summarized below in Figure 4- 1.
f. ii.al: ilii> G' rlrir, ll51r5; I
Packet Pg. 380 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric T' TE
ET I T 11EE
a
a
a l F. 0- rrr c° cas# 5ta da
d
equii me
t Fii d ,
Oj, ID
SP.. D°am we, Act
fD l"
E24F ed actiia iiw iHV
y' 20
f
fph i
P; S;
n
m e°'
Y
a tna i rl cta w,
t
1F
D'
C i 41RIB'
r
a 1C
a
nw lle ne wtd
B?t-''
a uf arr iir ra fDi I
e'YF sc uircs kc,ta 2'D..

Qf
D
ki H{
a ra+ Par i wii w
LD
atii ws ct
fD"
6a IGE nwmssiias
erefm mawe taw 3airds
r
w
sn wn tn
aa o w .
a a, a.
ffiieii y- amd rds
fD D4
D3'.
fD D2,
7F em er ra e' ine'"
a tfa iia ta dam 1,'(7 D''
fi
II u! i, u E N. ll' uuu^ Iliiiryi a° IV"" '":," ii4 ll a ii r^ 04 iia iry 4 Iluu ll! a uuyi ':'°" h Illl lld: Il ll a iryiiry uuyw:," f. ii.al: ilii> G' rlrir, il51r5; I.[
Packet Pg. 381 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric 1 m
s III' I a" u ", II.; i III i. . 0° i I' II II i 5 u iw III! i 5 iu i , 5 Senate Bill 350 ( SB 350) was signed by then- Governor Jerry Brown on October 7, 2015. Local POUs must identify all cost- effective energy efficiency and set savings targets. Additionally, SB 350 sets a statewide target for doubling electric and natural gas energy efficiency savings of retail customers through energy efficiency and conservation by 2030.

This CA law requires POUs to give rigorous consideration to energy efficiency and demand reduction resources that are cost-effective when developing IRPs. SB 350 also defines energy efficiency as" activities to achieve peak load reduction that improve end- use efficiency, lower customers' bills, and reduce system needs." Starting in 2019, SB 350 also has the CEC reviewing the IRPs of the state' s 16 largest POUs. This review is intended to ensure that the utilities reach the 50 percent RPS target by 2030 ( now 60 percent by 2030, per SB 100, described below), meet greenhouse gas ( GHG) emissions reduction targets, and maintain reasonable customer rates and reliable service. n.. m1 sn IIII'' I ° III. w'; a
Senate Bill 1037 (SB 1037) was signed by then-Governor Arnold Schwarzenegger on September 29, 2005.

The bill requires that each POU, prior to procuring new energy generation resources, first acquire all available energy efficiency, demand reduction, and renewable resources that are cost- effective, reliable, and feasible. SB 1037 also requires each POU to annually report its investment in energy efficiency and demand reduction programs to its customers and the CEC. This bill is foundational for POUs to treat energy efficiency and demand reductions as a priority resource over supply- side options so long as the demandside options are cost- effective feasible, and reliable. 1 III': I h" V! h"° III.

California Assembly Bill 2021 ( AB 2021), signed by then- Governor Schwarzenegger on September 29, 2006, requires that POUs establish, report, and explain the basis of the annual energy efficiency and demand reduction targets by June 1, 2007, and every three years thereafter, covering a ten- year future horizon. A subsequent bill has changed the time interval for establishing annual targets to every four years. Reporting requirements under AB 2021 include: ( i) the identification of sources of funding for the investment in energy efficiency and demand reduction programs; ( ii) the methodologies and input assumptions used to determine cost- effectiveness; and ( iii) the results of an independent evaluation to measure and verify energy efficiency savings and demand reduction program impacts. p,,,„ " I:; i
lll. d'°'; ; v:, u' a6
PUC § 385 Requires POUs to collect a public goods charge ( non- bypassable usage charge) and spend that money in four specific areas. These areas include cost- effective demand- side management and energy conservation, new investments in renewable resources and technologies, research and demonstration programs, and low-income services. Low- income services can include energy efficiency, education, weatherization, and rate discounts. While PUC 385 mandates the collection of the public goods charge, it f. ii.al: ilii> G' rlrir, ll51r5; I l;
Packet Pg. 382 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric provides substantial flexibility in use of the funds, though " public interest" and consistency with existing statutes are noted.

C. LL!; I: a
lll.°", a':,°;
PUC § 386 requires that POUs ensure that low-income households within a service territory have:
1) Access to affordable electricity,
2) Low- income families are afforded low- cost and no- cost energy efficiency measures that reduce their energy consumption, and
3) The level of assistance reflects the level of need.

PUC § 386 also requires that POUs streamline enrollment into LIHEAP, collaborating with other providers and utilities in the service territory. For a rate discount program, PUC § 386 requires that POUs establish participation goals.

Linked with the public goods charge of PUC § 385, PUC § 386 links low-income energy services ( energy efficiency or rate discounts) to the use of the public goods charge funds. As PUC 386 includes requirements for low- income household energy efficiency, low- income programs should be included in the DSM- IRP planning process. Those programs, however, are not required to meet cost- effectiveness tests or be included as cost- effective when setting energy efficiency goals.

1., f I; illl. JV"' u JV" u . u„, m I" lll'; m o III u' a; Both PUC § 954. 5 and § 9615 codify that " the electrical corporation shall first meet its unmet resource needs through all available energy efficiency and demand reduction resources that are cost- effective, reliable and feasible." PUC § 9615 establishes that requirement for publicly- owned utilities. The implication for both is that energy efficiency and demand reductions are the priority in the procurement of resources to meet needs not already met by current resources.

These public utility code sections indicate that publicly owned utilities give rigorous consideration of energy efficiency and demand reduction resources that are cost- effective, consistent with previously mentioned energy legislation.

Through the PUC § 9505 goal- setting process ( described below), POUs define their cost- effective energy efficiency resources and programs.
m' I: alll.` ' m u a6;' u"° a6
PUC § 9505 codifies energy efficiency planning requirements as follows:

JJJJ: Every four years, POUs must identify cost- effective EE and establish annual targets for the next 10 years
JJJJ: Every year, POUs must report progress against the annual targets f. ii. al: ilii> G' rlrir, ll51r5 a IfS
Packet Pg. 383 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric JJJJ: POU' s should not consider previous minimum investments per PUC 385 when identifying cost- effective EE.

JJJJ: A local publicly owned electric utility shall treat investments made to achieve energy efficiency savings and demand reduction targets as procurement investments.

As with other public utility code sections and supporting legislation, PUC 9505 reiterates the requirement for treating energy efficiency as a resource. Redding meets the identification and reporting requirements via its potential studies filed with NCPA. Appendix F provides a summary of Redding' s 2021 Potential Forecast Study.
i'"r I':; lu. 4 m";',;; li h" klll.

PUC § 9621 applies to POUs with annual demand exceeding 700 GWhs. This code section affects POUs related to greenhouse gas emissions and energy planning under SB 350. The targets established in SB 350 affect resource additions, including:

JJJJ: Achieving a statewide target that doubles energy efficiency savings in electricity and natural gas end uses by 2030 to the extent it is cost- effective, feasible, and does not adversely impact public health and safety.

JJJJ: The development of IRPs that achieve GHG emissions reduction targets established by CARB, in coordination with the CPUC and the Energy Commission, results in economywide GHG emission reductions of 40 percent from 1990 levels by 2030. 4 NOTE: In July 2018, the CARB staff, in coordination with the CEC and CPUC staff, issued targets that were developed around an economy-wide, 260 million metric tons of carbon dioxide equivalent ( MMTCOZe) as the mass- based GHG target for the State in 2030. 4 The achievement of this target is spread across all GHGcontributing sectors, with the electric sector targeted to account for a 51 percent to 72 percent reduction from the 1990 GHG emission ( evel of 108 MMTCOZe.

JJJJ: Achieving a renewable resource level of at least 50 percent by 2030 for the amount of electricity generated and sold to retail customers. PUC 9621 also requires compliance with the interim renewable targets in the California Renewables Portfolio Standard Program; for periods beyond the 2018 date of this IRP, the interim targets are 33 percent by the end of 2020, 40 percent by the end of 2024, and 45 percent by the end of 2027. 5 Annual updates must be submitted by the POU.

JJJJ: These objectives are to be met while also complying with the goals in PUC 454.52 related to serving customers atjust and reasonable rates, minimizing ratepayer impacts, ensuring 4 California Air Resources Board, Staff Report: Senate Bill 350 Integrated Resource Planning Electricity Sector Greenhouse Gas Planning Targets, July 2018.
5 PUC Division 1, Part 1, Chapter 23, Article 16, 399. 11- 399. 32, the interim requirements are( isted in 399. 15( b. 2. B) and 33930( c, 2).
f. ii. al: ilii> G' rlrir, il51r5 a 7. 7
Packet Pg. 384 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric reliability, strengthening the transmission and distribution system, enhance demand- side management, and minimizing pollutants with early priority on disadvantaged communities.
n':' II. a ml sn IIII'' I ° III. w' w'
Senate Bill 100( SB 100), or the 100 Percent Clean Energy Act of 2018, was signed by then-Governor Brown on September 10, 2018. SB 100 further modifies RPS requirements from 50 percent by 2030 ( set by SB 350) to 60 percent. It creates the policy of planning to meet all of the State' s retail electricity supply with a mix of RPS- eligible and zero- carbon resources by December 31, 2045, thereby achieving a 100 percent clean energy supply. While the specific RPS targets change, the core language of public utility code sections related to energy efficiency and resource planning does not.

On September 10, 2018, SB 100 was signed into law. It accelerates the RPS obligations for retail sellers, including POUs, as follows:

JJJJ: 40 percent to 44 percent by 2024;
JJJJ: 45 percent to 52 percent by 2027; and
JJJJ: 50 percent to 60 percent by 2030.

The Bill also states that achieving this policy shall not increase carbon emissions elsewhere in the western grid and shall not involve resource shuffling. SB 100 also requires the CPUC, CEC, the CARB, and other state agencies to incorporate this policy into their regulations and decisions.

4. 2 RULES AND REQUIREMENTS RELATED TO FUNDING SOURCES
Funding for DSM programs offered by Redding originates from several sources. The three major categories of funding are from Public Benefits, Greenhouse Gas, and Low Carbon Fuel Standard funds. Each type of funding has specific regulations, reporting requirements, and other conditions that must be met in order to use them. The following sections summarize the funding types that Redding uses or are available to use. While this section will reference specific programs, details about each program are available in Section 4. 2 of this document.

R,. lk I' h R II II u III! u S m
Under PUC section § 385, POUs are required to collect and spend a percentage of their base revenues on qualified Public Benefits ( PB) Programs. While the percentage is not specified, many POUs allocate a minimum 2. 85 percent of its annual base retail to fund PB. Per PUC § 385( a), this funding can be spent in four different categories, including:
1) Cost- effective demand- side management services to promote energy efficiency and energy conservation.
f. ii.al: ilii> G' rlrir, il51r5 a I.

Packet Pg. 385 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric 2) New investment in renewable energy resources and technologies consistent with existing statutes and regulations which promote those resources and technologies. 3) Research, development, and demonstration program for the public interest to advance science or technology which is not adequately provided by competitive and regulated markets. 4) Services provided for low-income electricity customers, including, but not limited to, energy efficiency services, education, weatherization, and rate discounts.

Redding currently allocates Z/ 3 of the PB to fund the Residential Energy Discount. This program provides a discount on electric usage and the fixed network access charge for qualifying low- income customers. The remaining funds have been used towards energy efficiency rebates for residential and commercial customers, customer and student education, energy storage incentives, solar incentives, and many other programs over the years. Overhead costs to support the programs are also paid through the PB fund. uN'" u u
IIII IG' I R r° um; mm
The Global Warming Solutions Act of 2006( AB 32) prescribed a statewide cap on global warming pollution with a goal of returning to 1990 GHG emission levels by 2020. The law required utilities to report GHG emissions to CARB and directed CARB to adopt
regulations6
implementing a Cap- and- Trade program. As
part of the program, carbon allowances' are distributed annually in amounts equal to the cap for that year. A set number of allowances are considered " free" each year to offset the expected cost burden of the program.

While a portion of the allowances must be deposited into a compliance account, any remaining allowances may be auctioned off. Auction proceeds are then earmarked as Greenhouse Gas ( GHG) funding. Due to early action by the utility that essentially reduced Redding' s GHG emissions profile, Redding has been able to sell a portion of its allowances to support GHG programs. As of 2020, Redding has received nearly$ 27M from auction proceeds.

Under the California Code of Regulations ( CCR) section 95892( d)( 3)-( 4), funding must be used to implement and support programs that are designed to reduce emissions. The categories are summarized below:

JJJJ: Renewable Energy or integration of RE, including construction and support for renewable energy and/ or energy storage projects.

JJJJ: Energy efficiency and fuel switching, designed to reduce GHG through reductions in energy use or changes to lower emission intensity energy sources, including EE equipment 6 CARB Cap- and- Trade regulations: Ih.tt... w.w2.:.a. rl: ca.:. nv/ nu.r: wn lk. n. a.( ca..p.: a.p7ci.: t ra. ci.e.:. n. a. ca..: a. 7ci..:
t. aci.e.. e u at n 7
Each allowance represents one metric ton of GHG emissions. f. ii.al: ilii> G' rlrir, ll51r5 a I
Packet Pg. 386 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric rebates; EE building retrofits; public or private EV infrastructure; switching from natural gas, propane, or diesel to electric equipment; infrastructure projects to support active transportation, zero- emission vehicles, or public transportation; or other projects that reduce energy demand.

JJJJ: Other GHG Emission Reduction Activities that reduce emissions of sulfur hexafluoride or hydrofluorocarbons; and wildfire risk reduction or forest carbon sequestration activities8 JJJJ: Non- Volumetric Return to Ratepayers
JJJJ: Administrative costs and educational programs that are limited to necessary costs to administer or provide outreach supporting implementation of the projects or activities funded.

Redding has primarily used GHG funding for energy efficiency, fuel switching, and emissions reduction activities. Recently, Redding returned funding to ratepayers as part of the City' s Economic Recovery plan in response to the Covid- 19 pandemic. The Economic Recovery plan impacted future funding, and no additional programs are currently scheduled for implementation. CARB recently released the allowance allocations for each EDU through 2030, which may provide additional funding opportunities for Redding.

R °.: III. t u III;, i III i II ms 5. 0 yNm. 0
By participating in the Low Carbon Fuel Standard ( LCFS) Program, Redding is able to capture credits based on residential EV charging in the City. Incremental credits are also generated through the City' s registered fleet and employee charging stations. By opting into the LCFS program, Redding is required to participate in the Clean Fuel Reward ( CFR) Program, currently administered by Southern California Edison.

The revenue collected from the sales of residential non- metered LCFS credits must be used " to benefit current and future electric vehicle owners" in Redding, and to participate in the program, Redding is required to provide customer outreach and education about the benefits of owning electric vehicles.

Additionally, by 2024, 50 percent of the revenue generated by the LCFS program must be contributed to the CFR, and of the remaining 50 percent, half must be used to support transportation electrification for the primary benefit of (or primarily serving) equity communities ( disadvantaged, low-income, or rural areas).

III,. 5! III ii yN m
As further explained in Section 4.4. 1, in limited cases, Ratepayer funding may be used if the City can justify the reasonableness of the cost.

Per Cap- and- Trade Regulations Section 95892( d)( 1)( C)( 2), wildfire mitigation activities are only eligible once CARB adopts a standardized system for quantifying GHG emissions from fuel reduction activities pursuant to section 38535 of the Health and Safety Code.
f. ii.al: lii> G' rlrir, il5 r5 a i
Packet Pg. 387 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric

4. 3 COMMUNITY FEEDBACK FROM THE 2018 IRP PROCESS
The 2018 IRP benefited from the public input process. The stakeholder process involved seeking groups who have an interest in future resource plans ( Stakeholders) and inviting their participation such that all relevant issues were identified and addressed. Through this process, participants were engaged and involved early in the development. The end result was that the concerns and perspectives of all Stakeholders were considered, with the resulting resource plan achieving what is considered to be an appropriate balance of regulatory and stakeholder objectives.

In seeking Stakeholders, REU actively sought input and participation from several types of constituents.

Actions taken to reach out to potential Stakeholders included a dedicated web page on the COR website that included information about the process, FAQs, presentations, flyers, feedback forms, surveys and survey results, as well as live recordings of stakeholder meetings. Stand- alone flyers, bill inserts, radio spots, and social media announcements were also used for customer outreach. A dedicated e- mail was created for customers to contact the IRP team directly.

Much of the customer feedback gained from the Public Process can be applied to the DSM- IRP. Specifically the sections regarding the public' s view of issues that balance environmental stewardship, rates, and reliability. Redding received 94 responses to the customer survey collected at the first public workshop and posted online in February 2018. The survey questions and results are shown in Appendix D.

Some key findings from the public survey related to energy efficiency and environmental stewardship include the following:

JJJJ: Customers prioritize low bills and reliability over the carbon footprint of the utility.

JJJJ: The majority of customers would rather meet the environmental mandates than exceed them.

JJJJ: Almost half of the customers surveyed are not willing to pay more for renewable and carbon- free electricity.

JJJJ: In the list of future resource options, energy efficiency ranked fourth behind solar, wind, and hydropower.

JJJJ: Of 86 respondents, 40 would like Redding to be an early adopter of technology, 33 would like to wait until technologies are common practice, and six would like to wait until new technologies become mandated. 7 surveys did not respond to this question.

JJJJ: If REU is required to offer energy efficiency programs, customers see value in delivering residential programs followed by an even spit of commercial and low- income programs. f. ii. al: ilii> G' rlrir, il51r5 a k1.

Packet Pg. 388 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric

4. 4 PRECEDENT FROM THE 2019 NEM 2. 0 SOLAR COMMITTEE
In 2019, upon reaching the milestone of 12MW of installed customer-owned solar PV, REU proposed a NEM successor tariff to more closely align the Net Energy Metering tariff with the cost of serving solar customers. Due to the complex nature of this issue, Redding City Council created a Solar Committee to consider all options and deliver a recommendation to City Council. The solar committee reviewed legal opinions, community input, cost of service data, and delivered a recommendation to City Council on December 17, 20199. Much of the information and decisions made regarding solar can be applied to energy efficiency. A summary of the applicable information is provided below. v I°' 1.!' II l II m°. 0 II YII II IV l' m II R.!' 1, XW I' XW'; XW rrr II l IV' II h l; N The City' s Legal Counsel provided a legal opinion on October 11, 2019, regarding the " Proposition 26 Implications of Continued Provision of Net Energy Metering Contracts." The relevant excerpts from that legal opinion that may also apply to other DSM Programs are as follows:

JJJJ: " Any cost to exceed the statutory mandate for NEM contracts must be funded from nonrate revenues or the City must develop a record indicating that the cost of these contracts is a reasonable cost of serving others, as by displacing demand for expensive marginal supplies, reducing load on REU facilities, increasing local resiliency in the event transmission of power from outside the City is interrupted, etc. Whether and to what extent such justifications are reasonable is a question for the City, its rate- making staff and consultants, and the City Council."
JJJJ: " Thus, to avoid characterization as a tax, REU' s power rates must recover no more than the reasonable costs to [ REU] of providing the service" and each customer class' rates must " bear a fair or reasonable relationship to [ its] burdens on, or benefits received, from" REU' s electric service. Cross- subsidies among customer classes are unlawful — REU may not charge one class of customers more than the cost to serve so another may pay less. ( Green Valley Landowners Association v. City of Vallejo ( 2015) 241 Cal. App. 4th 425, 439.)
JJJJ: " CONCLUSION. If the City maintains NEM contracts for those not entitled to them by statute or for a longer time than statute requires, it must fund any implicit subsidy of NEM customers from non- rate proceeds or disprove the existence of a subsidy by identifying benefits to the utility arising from supplies provided by NEM customers or costs avoided by virtue of those supplies. Whether such benefits or avoided costs can be identified and in what amounts and value are questions for the City' s staff and contract rate- makers." Staffs interpretation of these statements as applied to non- solar DSM programs is as follows:
9 The staff report and supporting documentation is available online:
http:// reddingcityca. iqm2. com/ Citizens/ Detail_ LegiFile. aspx? ID= 6040& highlightTerms= NEM f. ii.al: lii> G' rlrir, il5 r5 a
Packet Pg. 389 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric JJJJ: Any costs for DSM activities that exceed statutory mandates must be funded from nonrate revenues or the City must justify the reasonableness of the cost.

JJJJ: Cross- subsidies among customer classes are unlawful. f° m. 0 I ' II XW YII II IV° III YII II m; i f° 15 XW IV mr II. k' m,. 15 II XW IV mm The City' s Legal Counsel provided a legal opinion on December 2nd, 2019 regarding the " NEM Credit for Local Economic Impact." Specifically, the opinion addresses whether the NEM 2. 0 credit for excess energy can be increased due to local economic impacts. The relevant excerpts from that legal opinion that may also apply to other DSM Programs are as follows:

JJJJ: " Unlike the credits reflecting avoided costs and avoided system losses, those to account for the local economic impact of increased taxes and job growth are not reflected on REU' s income statement and do not reduce its cost to serve NEM customers. Moreover, these local economic impacts benefit the general public rather than non- NEM customers whose rates would subsidize that portion of the credit. Thus, the exception provided under Proposition 26 for a benefit or service " granted directly to the payor that is not provided to those not charged" ( Cal. Const., art. XIII C, § 1, subds. ( e)( 1) & ( 2)) does not apply to that portion of the proposed credit."
Staffs interpretation of these statements as applied to non- solar DSM programs is as follows:

JJJJ: When performing cost- benefit analysis, general " economic benefits" such as increased economic growth resulting from a program should not be included as a benefit.

M'
ro III II` yY II IG Nmm ', XW Yn IY lY II II° m
s, XW IV m. 0 ' Yn" II YII II IV l' lY! iu a
At the direction of Redding City Council, a solar committee was formed to review the issues surrounding the NEM 2. 0 rate for excess generation. Relevant aspects of the solar committee findings are as follows:

JJJJ: In response to City CounciPs request that the committee determine an appropriate rate at which solar installations would be feasible for new and existing homes, the committee determined the following:

The credit rate for the average solar customer to reach simple payback in 11. 5 years would need to be$. 12/ kWh.

To reach simple payback in 13. 4 years, the rate would need to be$. 10/ kWh.

These rates would support feasible solar installations in today' s market. However, they would also need to be defensible.

JJJJ: In their preferred recommendation, the solar committee stated the following.

Any adopted rate must be fair for non- solar customers as well as legally defensible." The preferred recommendation was to " determine the highest credit rate which is both quantifiable and defensible."
f. ii.al: lii> I r'ir
rw'
il r5;
Packet Pg. 390 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Staffs interpretation of these statements as applied to non- solar DSM programs is as follows:

JJJJ: REU should not overly prioritize the economics of a measure when setting incentive levels.

JJJJ: REU' s DSM portfolio should be fair to non- participants and legally defensible.

JJJJ: The definition of" highest credit rate" should be considered when developing the avoided cost rate.
iu 5 ii y ull ,,°. uIV S I iw. 1, iu. ' rr 5 III.. 5.

On December 17, 2019, Redding City Council adopted a resolution approving the solar committee' s recommended net energy metering successor tariff based on the highest defensible credit rate. The credit rate for 2020 was approved at$ 60.80/ MWh, which includes components for the avoided cost of energy, RPS procurement, transmission losses and distribution losses. ii ii II ii ii ii
r.
i/////////////////////////////////////
c
1111 11Y: 01 0 FG` I IIIIIIII 0 01 o i ao1 I.. Ib to ll„¢, C ao1 I..

II u. i, u E ° II" " '° U 04 r: iin, n, ,: 4 °° ii Il n°, o- ii° ii'°." f. ii.al: ilii> G' rlrir, il51r5;
Packet Pg. 391 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric I I I

5. 1 AVOIDED COSTS
For life- cycle avoided cost analysis, REU worked with Ascend Analytics to develop a production cost forecast model that was used to develop an avoided cost forecast. The production cost forecast determines the total cost estimated to serve load. This power supply cost includes generation, losses due to transmission & distribution, and power purchases & sales. REU is currently evaluating renewable projects that will meet RPS compliance requirements, and the cost of this project is not included in the power supply cost. The avoided cost is calculated by dividing the power supply cost by the load served and adding the cost of any RPS procurement. The components of the avoided cost are energy, transmission losses, distribution losses, and RPS procurement. The energy, transmission losses, distribution losses are all subsets of the total power supply cost, while the RPS procurement is an added cost based on the estimated cost of renewable projects. The avoided cost is calculated monthly and input into the ESP Cost- Effectiveness tool. An annualized version of the avoided cost forecast can be found in Appendix A.

5. 2 COST- EFFECTIVENESS TESTS
Conservation and load management programs offer utilities an alternative to supply- side options by focusing on their customers' demand for electricity or capacity. Supply- side options include power plants or transmission and distribution lines to deliver power. As part of integrated resource planning and subsequent demand- side management ( DSM) programs, the DSM options are compared against supplyside options via cost-effectiveness tests. As an early adopter of DSM programs, California was a leader in developing cost- effectiveness testing approaches, enshrining five cost- effectiveness tests into the California Standard Practice Manual ( CSPM). 10
Since the CSPM cost- effectiveness tests were established, the tests have been adopted and adapted within California and around the U. S. to address policy changes or other needs. In some jurisdictions, carbon emissions or equity considerations have led to their incorporation into several of the cost tests.

Regardless, the core framework of the CSPM tests has remained. Even with the emergence of the 2017 National Standard Practice Manual ( NSPM) 11, which allows for greater jurisdictional flexibility in addressing the cost tests, the concepts of the original CSPM remain.

Fundamentally, the CSPM cost test provides perspectives on DSM program cost- effectiveness. Applied at an individual measure level, program level, or DSM portfolio level, the cost tests give perspectives for cost-effectiveness for participants, ratepayers as a whole, utilities, the utility system, or society as a whole. lo https:// www. cpuc. ca. gov/ general. aspx? id= 5267 11 https:// www. nationalenergyscreeningproject. org/ wp- content/ uploads/ 2017/ 05/ NSPM_ May- 2017_ final. pdf I ir 5ri' Ylf il`r5 i a, aiii il.5' Ylr, ii, a ri:, ifr, a l I ffrS. li ri r5 a, a Ir:,al': a l; Packet Pg. 392 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric In each of these perspectives, benefits and costs may differ. For example, an incentive payment is a benefit for a participant but a cost to the utility or ratepayers as a whole.

Table 5- 1 summarizes the five CSPM cost tests. The most commonly used cost tests in the U. S. are the utility cost test, total resource cost test, and societal cost test. The participant and ratepayer impact measure cost tests are typically used to inform program design or manage overall rate impacts relative to expenditures, though they are relevant considerations when weighing the scale and scope of programs and incentives.

I11J lll . . . .,. ..,. i », 1lu,,,».+»»,», i »>>, l l„ I1iiuiui» i i J. . ,. ,, i» i >>> 1 11muu»,»», J . i i >>> l 1 11 i , w» >»>J„ uu» iiii I i»»,»1 , l i»,+++ ii, 11 1 1 Il J !,. i J„ 1 J 1 rr,, r,, , »: r , , ,.. l r , r Illlll,,,,»,», I , , ,, ,,» , ; „ 1 , lllllllll ,; , 1,,, , 111Il lll ll „ 1 , , l i lrllll1111 I 1 r»Jli»,,,,,,,»,,,,„,,,,,,,,,„ rl„,,,„ff„,r,,,,,,,,ll1l llllllll lllllllllllllllll,lll lll llli111111,,,,»,, 11„,,,,,,,,,,„„,,, J,,,,,,,, 1 11/1111111111111/1111111,/, llllll, r»,»I„,11„„,», il„/,,,,,,.,»,,,,, ir,,l,,,,,.,» J,i, llllllllrlrllllll111111111/1111,1111111111111111111111111111111,1111111r Participant( PCT) Will participants benefit over the life of Compare costs and benefits for the the measure? customer installing the measure
Utiliry/ Program Administrator Will utility bills increase? Compare program costs to alternative UCT/ PACT)) supply- side options
Ratepayer Impact( RIM) Will utility rates increase? Weighs the cost of programs and reduction in revenue against supplyside resource savings Tota) Resource( TRC) Will the cost of energy in the service Compares program and customer costs territory increase? to utility savings
Societal( SCT) Is the utility, State, or otherjurisdiction Societal- level benefits and costs of better off? energy efficiency at the jurisdictional
I eve I
ll : a lk. ll n°,
ii uuouu! a o-+ :;° II" n ':, 4 ! u r^ iry 4 4 lh'°
The TRC test is the dominant test used in the U. S. by utilities regulated by public utility commissions. This test has been adapted over the years to incorporate a greater scope of benefits and costs, often being renamed as the" modified TRC" or" mTRC." For example, as a blending of participant, utility, and ratepayer benefits and costs, modifications have included capturing benefits for health and safety impacts for participants or avoided carbon emissions compliance costs ( a utility and ratepayer benefit). The cost analysis has also become more sophisticated with factors such as considering the value of the deferred replacement costs for measure costs or considering operations and maintenance cost considerations for measures increasingly common. In California, non- price factors, such as environmental externalities, were incorporated into the mTRC.

In the end, the cost- effectiveness tests allow a utility or regulators to gauge the impact of DSM programs within their guiding policy framework. For a regulated utility, those policy considerations can be used to decide which costs tests may be most appropriate and in what manner they should be adjusted. The National Standard Practice Manual ( NSPM) provides a high degree of flexibility in guiding how a jurisdiction may develop cost-effectiveness tests to meet its policy goals, although it has one guiding principle— symmetry— that shapes the treatment of benefits and costs. The principle of symmetry is that both benefits and costs should be included for a given impact in the cost- test.

I irSri' Ylf il`r 5) i a, aiii il5' Ylr, ii, a ri:, if r aP ffr 5. li ri ir 5 a, a Ir:,al': a fS Packet Pg. 393 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric In the cost-effectiveness framework on the CSPM, Redding has substantial flexibility— it does not need to follow the mTRC used by investor-owned utilities. California law allows for publicly- owned utilities to define cost- effectiveness. The NSPM concept of symmetry suggests in evaluating the cost- effectiveness of DSM programs or measures, metrics associated with supply- side planning should be symmetrical with DSM analysis, and any selected DSM impacts must be considered for both benefits and costs.

Table 5- 2 summarizes the key benefit and cost considerations for each of the five CSPM cost- effectiveness tests. Note that for some test components, an impact may be treated as a cost or a benefit depending on the test. The algebraic formulas for these cost tests are included in Appendix C. u , ii i , uu» »>»»»»> i i i 1 i i ii J, . l 1
i I1 , I,, ,, I , i < I J
l 1 1 1 I Illi»,»> 111>>»»» IJJ , , , 1»>, t>>1,>> 1,,,,,,,,,, t,,,,,,,,, J , , , , ' 1„,,, 1ll l ll1ll l1ll1l1l11t1ll1ll 1ll1l1l l ll1,l1 li,IllIl1J111«>> 1J111111J111J»> 111 t, 11111) 1)1111J1J111J 1 111J , ) 111111111>>> 111111J1» 1f»rf,ii„,,,,,, i,,,,1J1J) 1J1J)JJ,J11J111111J111`»> J11111J111»>>> 111 1)1111) 1111J1J111J 1 1111i 111111111J111Ji>>> 111111J1J111JaJ»>» 1111111111111111J11» 1111111111 11111 , 11111111J111 fJ>> i1 ii1111111 1111111 111 1 1, Electric energy and capacity avoided costs Benefit Benefit Benefit Benefit Other fuel savings( natural gas, fuel oil, propane,
Benefit Benefit Benefit
etc.)
Non- ener benefits e.

Benefit if
gy g., water, O& M costs, etc.)
mTRC
Benefit
Environmental and health benefits Benefit
Incremental costs for measure and installation Cost Cost Cost Program administrator overhead costs Cost Cost Cost Cost Incentive payments paid by utility Benefit Cost Cost
Bil) savings/ Utility Lost Revenue Benefit Cost
r: llll',Yklld' up „ nlf, ll llll llll! i llll`" & l.; Q° i :"" d' 1 11\\ dd,!" II" Yld' 4i° i 1,: IIII B QIIIYId',!"IIYI° i rlVll" YI@:, I Il d' r' I!"'°. Illl d" II" YI"'".

As noted above, each of the cost tests provides a perspective on the benefits and costs of demand- side management when comparing DSM options to supply- side options. These tests can generally be used for any demand- side energy resource( DER), though considerations for emerging storage technology and fuel switching/ substitution create additional complexity or challenges. Additionally, not all benefits are necessarily easy to quantify, particularly when considering policy goals such as " resiliency," " equity," or health. For these hard- to- quantify impacts, some jurisdictions use multipliers ( typically on benefits) to capture the estimated importance or impact of a policy goal through the use of DERs.

There is no single approach to addressing emerging technologies or hard- to-quantify impacts, with a high degree of variability found across the U. S. For example, in Colorado, utilities regulated by the Commission apply a multiplier to TRC benefits associated with programs and measures that serve the low- income population, reflecting an equity goal of having low- income customers being able to participate in programs, reduce arrearages, improve economic stability, and generally recognize benefits beyond just the energy resource savings.

I ir 5ri' Ylf il`r5 i a, aiii il5' Ylr, ii, a ri:, if r aP ffrS. li ri r5 a, a Ir:,al': a t 7 Packet Pg. 394 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric In general, the RIM test is the cost- effectiveness test that least- favors energy efficiency. The benefits to ratepayers are only the avoided costs of supply- side options. Costs are associated with program administration, incentives, and the lost revenue that must be made up to pay for other utility system costs. The specific effect can vary based on the rate structure of utilities and the balance of fixed and avoided costs in those rates. The use of the RIM test on electrification measures is a relatively new phenomenon, with uncertain results.

As noted above, the RIM test is a tool that may be best used as a gauge to manage overall DSM program impacts on utility rates, with policy informing the acceptable range of impacts. It is worth acknowledging that none of the cost tests are perfect at capturing the totality of benefits and costs that may accrue to any given party.
m:: ll° i IIl yui 5° III. a 5
In order to meet emissions reduction goals identified in the guiding principles, staff developed a Carbon Impact Cost Test ( CIT, $/ Metric Ton of GHG emissions reduction). The CIT is a City of Redding- specific metric used to calculate the ratio of the lifecycle GHG emissions reduction of a measure to the lifecycle rate impacts of a measure. The CIT helps identify measures that help cost- effectively reduce carbon emissions. Note that measures with a positive CIT save carbon while providing downward rate pressure.

I ir 5ri' Ylf il`r5 i a, aiii il5' Ylr, ii, a ri:, if r aP ffrS. li ri r5 a, a Ir:,al': a k; Packet Pg. 395 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric I I

6. 1 REU EXISTING PROGRAMS
V III yN G III:' u u yN° I" u yni m
Redding currently offers a robust suite of energy efficiency programs for residential and commercial customers. The Residential and Commercial Deemed Rebate programs offer prescriptive rebates for a variety of different measures that work to reduce energy consumption and save customers money. While specific requirements must be met in order for customers to receive the rebate, the rebates are open for all customers to apply. Programs are paid through either Public Benefits or Greenhouse Gas funds.

6...... si rn o l b s
Redding has offered deemed residential rebates for several years. The measures included in the Residential Rebate Program are as follows:

Water Heaters Energy Star Appliances
JJJJJ H eat P u m pJJJJ: Ce i I i ng Fa n
JJJJJ Electric Storage JJJJ: Refrigerator
JJJJ: Room Air Conditioner
HVAC& Thermostat Building Shell
JJJJJ Air Conditioner Unit JJJJ: Dual Pane Windows
JJJJJ Heat Pump Unit JJJJ: Wall Insulation
JJJJJ Whole House Fan JJJJ: Ceiling Insulation
JJJJ: Wi- Fi Enabled Thermostat
4 In FY 2020, the Residential Deemed Rebates program accounted for nearly 8% of the total energy savings.

6..... L r Irn E r
y
E fi yPr r
The Low Income Energy Efficiency Program ( LIEEP) provides free energy efficiency equipment and installation to weatherize homes. Redding currently works with Self- Help Home Improvement Project SHHIP) to implement the program. The measures include both traditional energy efficiency upgrades as well as electrification of space heating. The measures included in LIEEP are as follows:

Water Heaters Energy Star Appliances
JJJJJ H eat P u m pJJJJ: Ce i I i ng Fa n
I: YIVI I' rr., r rr GJISPIr, ri a ii i f' r, rl fr llr, a t Packet Pg. 396 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric JJJJJ Electric Storage JJJJ: Refrigerator
JJJJJ Water Heater Blankets JJJJ: Room Air Conditioner
JJJJJ Low- Flow Aerators and Shower Heads
HVAC& Thermostat Building Shell
JJJJJ Air Conditioner Unit JJJJ: Dual Pane Windows
JJJJJ Heat Pump Unit JJJJ: Wall Insulation
JJJJJ Wi- Fi Enabled Thermostat JJJJ: Ceiling Insulation JJJJ; Coil Cleaning and Refrigerant Charge
Other
JJJJ; LED Light Bulbs
JJJJJ Smart Power Strips
4 In FY 2020, LIEEP accounted for 10. 5% of the total energy savings.

6..... a r l b s
The Commercial Rebate Program offers prescriptive rebates for a variety of ineasures that work to reduce energy consumption and save customers money. The measures included in the Commercial Rebate Program are as follows:

Food Service Refrigeration
JJJJJ Ice Machine JJJJ: Auto Door Closer
JJJJJ Glass Door Refrigerators & Freezers JJJJ: Anti- Sweat Heater( ASH) Controls JJJJ; Solid Door Refrigerators & Freezers JJJJ: Electronically Commutated Evaporator JJJJ; Insulated Holding Cabinets Fan for Walk- In Cooler or Display Case JJJJ; Commercial Electric Combination Oven
HVAC& Thermostat
JJJJ; Electric Steam Cooker
JJJJJ Electric Convection Oven
JJJJ: Air Conditioner Unit
JJJJ: Heat Pum Unit
JJJJJ Electric Fryer p
JJJJ; Electric Griddle
JJJJ; Wi- Fi Enabled Thermostat
JJJJ; Vending Machine Controller
4 In FY 2020, the Commercial Deemed Rebates program accounted for< 0. 5% of the total energy savings
I: YIVI I' rr., r rn GJISPIr, ri a ii i f' r, rl fr llr, a f: l Packet Pg. 397 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric

6..... a r 6 1 s
The Commercial Custom Rebate Program offers customized rebates not covered by other REU rebates.

The program provides incentives for non- residential customers to install new, high- efficiency equipment that reduces energy consumption of a business by at least 50, 000 kWh/ year. Examples of possible equipment upgrades include upgrading a central chiller plant and HVAC system, overhauling an industrial refrigeration system, or retrofitting an existing pumping system with new pumps and controls. However, there are no limitations to the equipment type to qualify so long as it reduces energy consumption. All projects must be approved by staff prior to releasing rebate funds. 4 There were no energy savings from the Commercial Custom program in FY 2020.

6..... a r l Li f orn
The Commercial Lighting Rebate Program provides a custom rebate based on the amount of energy savings. Upgrades from older technologies can reduce energy consumption by 30- 50%. Staff uses a calculator to quantify the estimated energy savings from a project based on prescriptive information. The rebate amount is based on the total energy savings.

This program continues to be the top energy- saving program offered by Redding and is the most popular rebate.
4 In FY 2020, Commercial Lighting accounted for over 70% of Redding' s net energy savings reported to the CEC( 2. 1M kWh).

6..... 6 E r
y rris r
The Energy Advisor program is available to both Commercial and Residential customers. The program helps customers identify how much energy the property uses, identify areas where energy is being lost, and suggest changes to make the property more efficient and/ or comfortable. Customers may request a visit from an Energy Advisor to perform a walk-through in their home while providing tips and areas to save energy in their home. Customers typically request this service during a high bill inquiry. For residential customers, the program provides LED light bulbs to replace incandescent lights and a smart power strip free of charge.
4 In FY 2020, the Residential Energy Advisor program accounted for< 1. 0% of energy savings.

6..... 7 LE S r lo f pl rn
The City of Redding' s LED Streetlights program replaces High- Pressure Sodium ( HPS) and Mercury Vapor MV) bulbs in existing streetlights with LED bulbs. LEDs provide more directional light resulting in reduced light spillage and more natural white light to increase visibility. They also reduce maintenance costs since they only need to be replaced once every 15 years; in contrast, HPS and MV lights are inspected or replaced at least once every five years. REU administers and implements the program.

I: YIVI I' rr., r rn GJISPIr, ri a ii i f' r, rl fr llr, a 1.

Packet Pg. 398 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric 4 In FY 2020, the LED Streetlight Replacement program accounted for 7. 1% of energy savings. a.,, II @'; U II rrr N'" 1° m. 0 15 II, XW` yY II." 15 N'" II II m. 0 15 IV' XW II I„ m. 0" Yn IY Several studies have been performed, and initial steps have been taken to encourage increased penetration of EVs in Redding. The utility aims to assist from start to finish, including customer-facing educational materials, dealership outreach and education, purchase incentives for new EVs, charger installation assistance, and investments in public infrastructure.

6..... si rn o l El ro/ hn G b s
The utility' s residential EV Rebate Program began in August 2017. Under this program, the utility offers incentives for new vehicle purchases or leases. Additionally, incentives are also available to help offset infrastructure costs of installing a Level II EV charger at the customer' s home. To date, there have been 131 residential rebates issued for the purchase or lease of a new electric vehicle and 30 rebates issued for the purchase of, or installation of, a residential EV charger. According to DMV data, the number of electric vehicles in Redding is roughly 372 and approximately 576 in Shasta County as of January 2020.

6.... a r l El ri/ hn G b s
The utility currently offers an incentive for Commercial customers for the purchase or lease of new electric vehicles. Incentives are also available to help offset the installation costs of a commercial Level 2 vehicle charging station. To date, the City has issued seven rebates for commercial vehicle purchases and three rebates for commercial charging.

The City has completed the following projects and initiatives that assist in the overall goal of increased electric vehicle adoption and lower carbon emissions in Redding:

JJJJ: Created a dedicated webpage where customers can find information about electric vehicles and incentives along with customer- facing materials providing information on EVs and incentives.

JJJJ: Opted into the State' s Low Carbon Fuel Standards program to generate revenue through residential EV charging that is reinvested in transportation electrification.

JJJJ: The City of Redding executed a joinder to participate in the State' s Clean Fuel Reward Program to provide point-of-purchase rebates to customers when purchasing or leasing new EVs.

JJJJ: Provided funding for the City' s electric shuttle program in downtown Redding as well as the Redding Area Bus Authority for an all- electric public transport bus.

JJJJ: Installed 10 Level II fleet and employee EV charging stations at two City facilities.

JJJJ: Converted 19 fleet vehicles from gas to electric, retiring the City' s highest emitting vehicles.

I: YIVI I' rr., r rr GJISPIr, ri a ii i f' r, rl fr llr, a Packet Pg. 399 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Redding seeks to be an active participant in the area of transportation electrification. As such, the City continues to evaluate additional ways to benefit the community of both current and future EV drivers.

The City is working toward the following list of identified goals:

JJJJ: Increase customer outreach and education efforts through marketing and events.

JJJJ: Install fleet and employee charging at the City of Redding Police Department and Redding Power and continue the conversion of fleet vehicles to electric.

JJJJ: Grow the City' s public EV charging infrastructure, beginning with the installation of DC Fast Charging and Level II charging at the Sundial Bridge, with expected completion in Q4 2021.

JJJJ: Develop equity programs to primarily benefit low- income and disadvantaged communities.

JJJJ: Continue to encourage the development of EV charging rates to incentivize commercial investments in public infrastructure and fleet conversions.

JJJJ: Maintain compliance with program requirements.

6. 2 COMPARISON TO PEER POUS AND IOUS
In considering future directions for Redding' s DSM programs, comparisons to other utilities provides an opportunity for Redding to identify what changes others are making and consider whether to retain current practices or move in directions similar to other utilities. GDS has identified three " mega- trends" in demand- side management programs that suggest changes are underway in the industry in the U. S.

These trends are:

JJJJ: Reduced Emphasis on Lighting Energy Efficiency: Federal standards have reduced the incremental energy savings from LEDs. Additionally, LED lighting has been rapidly adopted by the marketplace, with increasing market saturation reducing future savings opportunities.

JJJJ: Challenges Associated with Portfolio Cost-Effectiveness: Lower avoided utility costs reduce the cost- effectiveness of energy efficiency measures. Lighting, for example, is a significant source of savings, is relatively easy to install, and provides a positive impact on the DSM portfolio' s cost- effectiveness. Any remaining opportunities increase the level of effort required to achieve additional savings while reducing DSM portfolio costeffectiveness.

JJJJ: Climate Change Policies and Electrification: With the electricity sector rapidly adopting increasing shares of renewable energy due to policy or economics, greenhouse gas emissions can be reduced by shifting loads served directly by fossil fuels, such as transportation or natural gas combustion. State policies are driving utilities to encourage I: YIVI I' rr., r rn GJISPIr, ri a ii i f' r, rl fr llr, a Packet Pg. 400 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric electrification, a 180- degree change from prior policies that sought to minimize the use of electricity.

With reduced opportunities for energy efficiency and new opportunities related to electrification, Redding has a chance to participate in these trends. While energy efficiency can still be cost- effective (depending on the cost test) and benefit customers, so too can electrification. Electrification creates an opportunity to increase revenues to offset energy efficiency-driven lost revenues while also making a substantial positive impact to help reduce overall greenhouse gas emissions.

GDS developed the following brief profiles of several California utilities — Roseville Electric, Modesto Irrigation District ( MID), SMUD, and PG& E in order to provide comparisons to Redding' s current and possible future DSM portfolios. In general, we see the above trends reflected in other utilities, most evident for the larger SMUD and PG& E programs. The types of ineasures currently being promoted by each utility are summarized in Tables 6- 1 and 6- 2.
s,.; W,,:: V. I:; i'„: u n': tiu. 11l'
As an investor-owned utility, PG& E is fundamentally different in its corporate structure than publicly owned utilities, not to mention its vastly larger scale. In their 2020 IRP 12 , PG& E notes the CPUC requirement that 60 percent of its energy efficiency portfolio be implemented by third- party administrators. As such, PG& E may lose substantial control over the measure and program delivery option of energy efficiency programs, with uncertain results in how that may frame future energy efficiency priorities. PG& E notes in its IRP that absent the inclusion of codes and standards savings credit, their expected energy efficiency portfolio will not meet its cost- effectiveness criteria.

The PG& E IRP notes a high level of engagement and support for transportation electrification through the adoption of EVs and support for infrastructure. The IRP does not directly address building electrification other than noting its presence in load forecasting. Nevertheless, PG& E has made strong public statements support building electrification. 13 The current suite of residential energy efficiency rebates cover appliances, efficient air conditioners and water heaters, thermostats, and various consumer goods, with third- party programs offering a range of other options. However, they do not currently promote fuel switching. The current C& I sector programs are comprehensive in their scope of energy efficiency. Fuel substitution/ switching does not appear to be a part of their current programs other than through transportation electrification efforts.
lz https:// www. pge. com/ pge_ global/ common/ pdfs/ for- our- business- partners/ energy- supply/ integrated- resourceplanning/ 2020- PGE- Integrated- Resource- Plan. pdf 13 https:// www. greentechmedia. com/ articles/ read/ pge- gets- on- board- with- all- electric- new- buildings- in- california I`: YIVI I' rr., r rn GJISPIr„ ri a ii i f' r„ rlfr llr„; Packet Pg. 401 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric u w,.
m
s,;° m u yu i. i 5 I, V i u i;. u II lll 5 u II lu 5 III iu 5 u 5 m° sn I, I lll III SMUD' s 2019 IRP14 provides a direct insight into the mega- trends driving utility DSM programs. Their customer- facing programs clearly emphasize electrification as a major highlight, along with programs to help manage electricity loads. Electric vehicles and the electrification of buildings or building systems are key focuses for both the residential and C& I sectors. However, SMUD is not removing energy efficiency from their program portfolio, noting the continuance of custom and prescriptive energy efficiency programs for the C& I sector and design assistance for all- electric buildings. For the residential sector, appliance energy efficiency and whole- house programs are expected to continue.

Greenhouse gas emissions reductions feature prominently as a focal point in their IRP. In addition to expanding renewable energy power supplies, SMUD notes in their plan that " energy efficiency, demand reduction, and electrification are essential to our long-term mission to reduce greenhouse gas emission— for our resource portfolio and our community." In their plan, "... increasing levels of energy efficiency are offset by new electrification loads from transportation, business, and industry..." Overall, SMUD envisions continuing energy efficiency in line with SB 350 goals but is making electrification a front-and- center focus over the coming decade.
fo I, V' m 5' III u N; 5 u i III' IG rr 5 u 5 I III III As a POU of a similar scale to Redding, MID offers a comparison that differs from SMUD or PG& E. In their 2019 IRP15 MID notes energy efficiency, demand response, transportation electrification, and energy storage as" Additional Procurement Goals" indicating a secondary importance relative to core supply- side resource goals.

MID currently offers energy efficiency rebates for homes and businesses. The residential sector offers a range of HVAC and appliance rebates, including air-conditioners and heat pumps, heat pump water heaters, and building shell improvements. For heat pumps and heat pump water heaters, customers currently using fossil fuel alternatives can participate. Additionally, MID is offering an incentive for residential EV chargers.

In the commercial sector, MID offers standard equipment rebates as well as a custom rebate option and a new construction program. Standard rebates include a wide variety of refrigeration, water heating, lighting, and HVAC measures. Interestingly, their water heater rebates require the presence of an existing electric water heater, whereas their heat pump rebates do not. C& I customers are also eligible for an EV charger rebate.

In reviewing their current programs, we see MID moving toward electrification for equipment rebates.

Their new construction support for the C& I sector has a rebate based on electricity savings, a 14 https:// www. smud. org/-/ media/ Documents/ Corporate/ Environmental- Leadership/ Integrated- ResourcePlan. ashx ls https:// www. energy. ca. gov/ filebrowser/ download/ 1937 I: YIVI I' rr., r rr GJISPIr„ ri a ii i f' r„ rl fr llr„ a 1; Packet Pg. 402 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric consideration that limits the application of fuel substitution or switching. The future of their energy efficiency programs and how they may change to more fully engage electrification is yet to be determined. w,. iu 5 III' rr, uIIIV, III IV,, 5° u lll S lullii 5 III'' rra, uIIIV! Like MID, Roseville is also a POU of a scale similar to Redding ( relative to PG& E or SMUD). The 2018 Roseville IRP16 addresses energy efficiency, electrification, and other distributed resources. For energy efficiency, the IRP envisions a continuation of prior energy efficiency programs with the addition of other measures. Demand response is treated as an emergency resource. Transportation electrification is framed as a distributed energy resource and notes the impact it may have on utility-specific greenhouse gas emissions, while noting the net reduction such electrification can bring.

The current residential rebates reflect the IRP, offering a range of appliances, HVAC, and building shell improvements. The HVAC rebates include heat pumps, suggesting a movement toward building electrification within the financial limitations of the utility' s budget. No prohibition against fuel substitution or switching is noted.

For the C& I sector, DSM programs focus on food service, HVAC, and lighting, although they also include a custom option. For C& I HVAC rebates, Roseville offers incentives for high- efficiency heat pumps, indicating a movement toward electrification— no prohibition against fuel switching is mentioned.

Roseville also offers transportation electrification programs. The residential EV program partners with CARB to offer a rebate on new EVs as well as chargers. For the C& I sector, Roseville offers incentives for electric forklifts, design assistance for interconnections, and rebates for light-duty through heavy-duty EVs.

Roseville appears to be focusing its electrification efforts primarily on transportation electrification, including the installation of public charging stations and offering substantial rebates for residential and commercial vehicles or fleets. Building electrification is present in its heat pump offers, with energy efficiency continuing to be emphasized for its residential and commercial buildings. The future of the energy efficiency portfolio is not yet determined.
w I m r W li W H m. U" Yn" Y
m
s IIR';' XW 6 , W.,., i s II R' Yn II YII II m. 0 I'° , X I u
fl°. N I` o km. Urrrlli R@' umm
In reviewing the current and future plans for the comparison IOUs, GDS developed a summary of the measures being offered by each. We found that all five utilities, including Redding, have been offering robust DSM programs covering a wide range of ineasures. No single utility offers the same mix of measures as another. However, common elements are shared across all five, such as promoting electric vehicles through transportation electrification programs. We expect that these portfolios will shift to 16 https:// www. roseville. ca. us/ UserFiles/ Servers/ Server_ 7964838/ Image/ Electric/ Electric_ IRP_ 2018_ WEB. pdf I: YIVI I' rr., r rn GJ SPIr„ ri a ii i f' r„ rl fr llr„ a I Packet Pg. 403 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric reflect the" mega-trends" noted at the top of this section— lower avoided costs, decreasing opportunities for incremental efficiency savings, and the use of electrification to address climate challenges.

The residential DSM portfolios of Redding and the comparison utilities are presented in Table 6- 1.

Common elements across all utilities are HVAC efficiency and electrification measures, along with electric vehicle incentives and smart thermostats. Redding demonstrates a similar scope for DSM measures as SMUD and PG& E, though there are differences across the range of ineasures. i i i i i, iiuiii ii i , »» i i i
l iiiiIIJ. 1 J 1 II1 Jr 1 1 JJ 1 l 1 i Ill,>>,>» 11 i 1»»» tr, t»»1l, If , , , , t1,,,,>> i»,11 111111111J1 1 1111111J 11J1111 1111r, 1J11' IllIl1J111J, J111J11J 1»>>f„,»,,, 1» 11>>>„ f: 1 , , IllIl1J111J1J, 1111J11J J11» rl i f,l f,l»11111111 111111111111111. 11111111111J111J1Jh,,», 1 r f , , J1J11J J11»>» 1» 1111 1111 1111I11I11J111>> 1111111J11J» f f,„ t»,»> r ! 1,,»> 1»1111 1 , 111111111J11J r I11I11J111J1Jll, J111 1>»»,r , ft,,11111111 11 1111111 Appliance Recycling
Appliances
Back- up Power
Building Shell
Consumer Electronics
Cooking
Demand Response
Hot Water Consumption
Fans
HVAC
Kits
Lighting
Monitoring
Other
Pools
Safety
Solar
Smart Thermostats
Trees
Tune-up
Electric Vehicles
Water Heating
ll : a lk. ll ° IG': l' 4 un, N^ iryi u a ll n,°," h I° ir..° a lliia " h a 4 ii, ir. uu° IG. r a u uaa u y A comparable pattern emerges in the commercial sector, with Redding offering a robust set of DSM measures similar in scope to Roseville and MID, shown in Table 6- 2. Measures common to all five utilities include Electric Vehicles incentives and HVAC efficiency or electrification.

Generally, more diversity is seen in program offerings across the commercial sector. The differences may be attributed to characteristics of each utility' s service territories and the types of commercial sector opportunities or other priorities in offering an expansive commercial portfolio compared to a more focused portfolio.

I: YIVI I' rr., r rn GJISPIr„ ri a ii i f' r„ rl fr llr„ a 3 7 Packet Pg. 404 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric i II i i m»» »» i i uu i i i i iu i i uuu uuu ui »» i m m uu i i i1 1 i iii 1 iii1, i i iii1 i1i i i uiu iiuu i m»»il , iii iuu i 1 JJJJJJJJJJJJJJJJJJJJ JJ JJ IIIIIIIIIIII I 1111J k J11111N 11 I J I1 1 1 1111111JJJJIJ J 1 III 1 1 l J JJJ ll II J1 J 11 J, . J JJ J J I I I 1 o. 1, I . . i r. s... o., o. o. ,:, „ . i ,... II r 7 '. ,., .,,. , . 1 II i r ,, , i i i .. i i i. , Ill>>>>>» I , tt, If „ 111111111 > > , , 1 1 1 Ill > > 1 1 1 1111 > > 1J1fIll , 1 fJ1f1111 > > i 111 1. 11, 1»»» t»»l>>J»»1,,,,>>11J111111 1111J11111111J 11J1111 1111r 1J111 IllIl1J111J»>>,»>»>„ J111J11Ja»»>>> I 1„ illlll1J111J1J 1111J11JaJ11, tf 1 J,J1 J»1» 11111J 1111JJJJ1J1111. JJ1111111111J111J1J1 J1J11JaJ11,»,>>»» r>>,»> 11111I 1111JJIJI1111J11111J111>>>,» IJJ1J11J 1111J11J»,»» t»>J1>»> J1»1111J 1J1111J11111J111J1J11>>> 1111111J11JaJ1111>>,» a» 111111111 1111111111111111. 11111 Appliances
Back- up Power
Building Shell
Controls
Custom Measures
Demand Response
Electrification
Infrastructure Upgrade
Food Service
HVAC
Irrigation
Laundry
Lighting
Multifamily Fuel
Substitution
Pools
Refrigeration
Solar
Streetlights
Smart Thermostats
Tune-up
Electric Vehicles
Water Heating
ll : a Ik. II ' :; a uu uu'^ u u u a Il n°," h ir.. a Ilii :; a uuoll a ir. uaa iry I: YIVI I' rr., r rn GJISPIr, ri a ii i f' r, rl fr llr, a Packet Pg. 405 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric I
REU staff used the ESP Cost- Effectiveness Reporting Platform (" CET/ RP") to quantify the impacts of potential measures and programs. Approximately 180 individual measures were evaluated to determine which measures aligned with the guiding principles, as indicated by the cost- effectiveness tests. Measures that did not achieve the required results were screened out, and measures that did pass the required tests were considered for inclusion in future programs. All cost tests were represented as the net present value of the benefits minus the net present value of the costs. Pass/ fail criteria for each cost test is as follows:

JJJJ: The Participant Cost Test ( PCT) indicates whether a measure is cost- effective for a participant over the estimated useful life of the measure. A positive value indicates that it is cost- effective, a negative value indicates that it is not cost- effective.

JJJJ: The Ratepayer Impact Measure ( RIM) indicates whether a measure is cost- effective for ratepayers over the estimated useful life of the measure. A positive value indicates that it is cost- effective and helps provide downward rate pressure, while a negative value indicates that it is not cost- effective and creates upward rate pressure.

JJJJ: The Carbon Impact Test ( CIT) quantifies the revenue impacts of a measure per ton of carbon offset, which can be compared to the NPV of the Carbon Credit Allowance cost forecast over the life of the measure, which is about $ 25 for a measure with a 10- year effective useful life( EUL) installed in 2021. Measures that cost more than $ 25/ MTCO2 do not cost- effectively reduce carbon emissions, and measures that cost less than 25/ MTCO2 do cost-effectively reduce carbon emissions.

7. 1 MEASURE LEVEL RESULTS
An example of the measure level results are shown in Table 7- 1, and the full results for all 180 measures are included in Appendix E. For evaluation purposes, these results do not include any REU rebates or program administration costs.

IIJ ! II 111111111111)))) II 11 UI 1 1) I IIJII 1 IUI 1 11 1 1 1111 I IIIIII I IIIIII II IIJII 1 IUI1 11 1 1 1 1 II Il1111111111111 II 1 III II 111. l , IIll 11 IIIIII IIIIIIII I 11 I1III I l1 IIIIIIIIII I I Ill I 1 11I ' 1 l1 IIII I1Il 1JDIJIl I IIU 1 ID1 IIII l I11 I IIII 1 I1 IIIIIII I I I I 1 Il ! IIII I I 111111 1 1J JJJ1)).)))) )) J11 JJJJJJJ1 ) 11)J1111 IIIIIIII IIDI1 111,)) 1 1, ll IIIlII 11111111 11 Il I11l 1 , 1))), I J , , 111, I1i 1111 111111aJ, l '1111II1 1111111i 1 , 1111 11,. 1111111111l, 1111, i 1J1J1111JJ1 1111 ' 1 111, i 1111 11 1 , 1J11 11J11111f111111, 111111, ii111J 111J 1)11,1 > > 111 1l11l 111J111 1, J1 , i 11111) i 1111111aJ1l, l 1 ll11 lilllll/, il l, 1 ; l 11111aJ1. 1j1l 11 lli111., li, f 1 1111 11lJ a) 111 1l, f1 l li1lUili, f 1 111 11, il 11 1l a 1l,1 llllllll1111111 111lflll rr 11/ 111f1 f11 11111111 , 1 1f1 1 1 11111 1111l11J1l,. 1 Il,1 AC Pkg Unit-< 5 Tons
1 Energy Efficiency Ton 3, 817 ( G, U7: p G7I 15
55kBtuh)- 15 SEER

ENERGY STAR HP
water heater, 80 gal., Water
2 Energy Efficiency located in Heater611 1, U8 GU7 10
garage/ basement
3 Building Electrification
All- Electric New Home
Home $ 11, 202 $ 5, 498 142 20
17 SEER HP 3- tons
DHW Full
Water
4 Building Electrification Electrification- Gas to 1, 201 1, 537 209 10 HP Water Heater
Heater
5 Transportation Small Light Duty Vehicle $ 2, 547 $ 2, 056 146 12 Electrification Vehicle- PHEV
ll : a lk. ll ':'°" h Illl lld n. ii; N+" n a i u ^, r ll I 1 4 Ri, ll IVIr ai rr ri: i I' rr., r rn l ii ljui a t
Packet Pg. 406 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric The results shown in Table 7- 1 demonstrate the following findings applicable to most energy efficiency measures.

JJJJ: EE measures shown will save the customer money over the life of the measures, as indicated by the positive Participant Cost Test ( PCT). For example, Measure# 2 ( HP water heater replacing an existing electric water heater) provides a net a benefit of$ 611 over the life of the measure, including the upfront cost for the more expensive heat pump water heater.

JJJJ: Energy efficiency measures create upward rate pressure, as indicated by the negative RIM test. For example, measure# 2 provides a net benefit to ratepayers of-$ 1308 over the life of the measure, and the utility will be required to recover that revenue from the customer base. This creates a revenue transfer from non- participants to participants.

JJJJ: Energy Efficiency measures are not a cost- effective way to reduce Carbon emissions. For example, measure # 2 costs $ 409 metric ton of Carbon, which significantly exceeds the present value of the allowance price forecast over the next 10 years of about$ 25/ metric ton.

The results in Table 7- 1 also demonstrate the following findings applicable to most electrification measures.

JJJJ: All measures shown will save the customer money over the life of the measures, as indicated by the positive Participant Cost Test( PCT). For example, Measure# 3( All electric new home) provides a net benefit of$ 11, 202 over the life of the measures including any differences in upfront costs to build the home with electric appliances instead of natural gas.

JJJJ: Electrification measures create downward rate pressure, as indicated by the positive RIM test. For example, measure# 3 provides a net benefit to ratepayers of$ 5, 498 over the life of the measure. This creates downward rate pressure that benefits all customers including participants and non- participants.

JJJJ: Energy Efficiency measures are a cost- effective way to reduce Carbon emissions. For example, measure # 3 costs -$ 142 per metric ton of Carbon which significantly less than the present value of the allowance price forecast over the next 10 years of about 25/ metric ton.

These results indicate that Building Electrification and Transportation Electrification programs support the guiding principles that were identified early in the planning process, whereas energy efficiency measures commonly create upward rate pressure, fund transfers from non- participants to participants, and tend not to be a cost- effective means to reduce carbon emissions.

IVIr, ai rr , ri: i I' rr., r rn l iraljial a
i[f: l
Packet Pg. 407 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric

7. 2 DSM—IRP PROGRAM LEVELRESULTS
Based on the measure level results, analysis was conducted at the program level to compare REU' s FY 2019 energy efficiency portfolio to a future Transportation and Building electrification program. Current programs are based on FY 2019 actual results, while future programs are based on measures expected to be installed in FY 2023- 2027. The programs shown in Table 7- 2 include rebates and administrative costs for fuel substitution programs.
ii iiuuuu II II III II III I I 1 111J Ilttttttllllll t 1 t 1 f I II./ ` 1 1 U ll J 1 J f J J r . . . o. „ J I „ , ,, 1111 / 11f11 11 1J 111l 11111111 l l 1 I ))), r . ,. ,
1f1 I(11J fJj f11J J i i i.,, : e „ a i I. ,, .. ., , n u„ 6.,.., . o rr Ir 1 Ilul( ilr ll l llra, lrrllrf ilrJJJ fl»l li»>I la I»fff 1l,l1 fi , , i fiul a 1 iiil ii illiiii f I f u » r I J , JJJ , I
a a 111 l1l f 11 1 I 1 1111 111 1 . 1 1 1 1 l 1 1J1,,,,, JJ,,,,,,,,, l 111 11 , . 1 1 1 Il 11 ( 1 1 1 a I1 1 j I11I l il» l>>Il1t11 1111 l1 i 1 a a i 11 1i1I111 EnergyEfficiency $
4, 090, 000 (; G,! r fc1, UUU r fcl 950, 000 r° 7ClUUU 8, 330 Rebates( FY19)
Shade Trees( FY19) $ 160, 000 ( 18cJ, UUU IC U 80, 000 1.: 1 U, UUU 240 Low Income Direct $
460, 000 ( C° 7 l, UUU rC U 500, 000 1. 8U, UUU 1, 230
Instal)( FY19)
Residentia) Energy $
Z g30, 000 (, U 1. U, UUU N/ A 3, 010, 000 0 0
Discount( FY19)
Public Streetlights
19 o 1 p' 1 zio, 000 90, 00o soo
Building
6, 860, 000 $ 1, 560, 000 70 1, 970, 000 $ 3, 530, 000 20, 780 Electrification
Transportation
1, 280, 000 $ 500, 000 110 500, 000 970, 000 7, 610
Electrification
ll : a Ik. II ' :°" h II II l Id' n. ii; N+ II l' a i, II° As shown in Table 7- 2, all programs have an initial upfront cost ( Program Cost) that includes rebates to customers and internal administrative costs. However, where energy efficiency programs negatively impact future revenue, electrification programs generate greater revenue than the upfront cost, resulting in a positive RIM test. Furthermore, the rebates offered by the utility reduce upfront costs to participants and help increase the PCT.

7. 3 CONCLUSION AND FUTURE PLANNING EFFORTS
The results from the analysis concluded that Redding should focus on Building and Transportation Electrification customer programs for the following reasons:

JJJJ: All energy efficiency measures and rate assistance fail the RIM test, indicating that these measures create a transfer of funds from non- participants to participants through increased rates.

JJJJ: Energy efficiency measures are not a cost- effective way to reduce carbon since they are significantly more expensive than the forecasted carbon credit allowance value over the measure life.

IVIr, ai rr , ri: i I' rr., r rn l iraljial a
i[ 1.

Packet Pg. 408 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric JJJJ: Energy efficiency measures are cost- effective for the customers who participate in the energy efficiency programs, as indicated by a positive participant cost test.

JJJJ: Building Electrification Measures pass the RIM test, indicating that they will provide downward rate pressure.

JJJJ: Due to Redding' s relatively low electric rates and PG& E' s relatively high natural gas rates, many customers can save money by switching from existing natural gas space heating and water heating to heat pump space and water heaters. Staff acknowledges the significance of shifting from energy efficiency to electrification programs will have on customers and further recommends developing an implementation plan to ensure a smooth transition.

Initial electrification program development is further described in the next section.

IVIr aiirr ri: i I' rr., r rr l iraljial,; i,,
Packet Pg. 409 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric II I
Redding staff recommends developing a suite of customer program measures designed to encourage electrification and fuel switching adoption. Those identified programs will fall under two categories:
building electrification or transportation electrification.

8. 1 BUILDING ELECTRIFICATION PROGRAM
To ensure the success of a new program, staff recommends a phased approach that will allow time for all stakeholders to transition from our current EE Portfolio to a new building electrification program. This allows for flexibility as new measures are introduced and allows time for participants and non- participants to become familiar with the new programs. The phased approach includes:

JJJJ: Introducing the lowest- risk, most cost- effective measures first JJJJ: Developing a robust education and outreach program to ensure that all stakeholders have a positive experience
JJJJ: Ensuring customer satisfaction is tied to the success of the program JJJJ: Adding new measures as technologies improve and/ or participation increases JJJJ: Incorporating lessons learned into a continuous program improvement process d. 11 : P III, m um, iw 5 lim. ulllll i IGIIm u i NIII!': 11,, 1° i" Ii u 5 i' yN E is orn ol rn b s
The Residential euilding Electrification — Existing euildings program provides an incentive to residential customers ( owners and tenants) who replace their natural gas equipment with electric- equivalent equipment. At the start of the program, the recommended measures eligible for replacement are water heating and clothes dryers, with a potential for further incentives for heat pump space heaters, stoves, ovens, and other technologies to be added in the future. The incentives will be based on reducing the incremental cost of converting to electric- equivalent equipment. The program details are listed in Table 8- 1.

Illllll I11 ))))))))))))))))) I 1 1 11111 I I IIIIII II I IIII I I1 1111111111111111111 III II III IIlI IIII III I 111111111111 III llI1111111111111111 1 I1 IU I I II IIII I) llllll III III III I 11III IIII II IIIIII II) 11)))) 1D 111 111111 11 111) 1111111 r r , , , r, , u , ,,, 11l>>>,>» i>> l»a»»»11 1JJ 1>> 11»» 1 J» 1 1J 1,1111 J 1 J 1>>l l>>» 1111 l>>><<«« J r lr«« 1 1 111 < < < 111 i11«<« 1 1 i 1 i1Il ll« 1 111 1111 1111J 1 11 11 > > > > > 11J1111111 1111111i11>>l>> i>> I>>»»J l»>1>»»»»»> i» l I i» I > > > 1 1»1 11 1 11 1 11 1 1 1111 1 11 ' 1 111111 Heat Pump Water Heater 1, 000 per unit
luly 1, 2022
Clothes Dryer 200 per unit
Heat Pump Space Heat
Induction Cooktops To Be Determined To Be Determined
Electric Ovens
r: llll',Yklld' ', ;: 9" II° i IIIIYV':" II1 d' 4i116':;I d' IIYl llrlkll 1 II IIII6I IIIIYI!° i Ild' V°. II Il ll r. l!"'".IIQIIIYI I" II&:" II rlVllll" , d' 1 r, 1lIIII I Ir r, P: rifir Ylr, ri I' rr., rt r i r Ur51r,; 15i ir5r p i,
Packet Pg. 410 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric I on rns r i rn b s
The Residential euilding Electrification— New Construction program incentivizes contractors to build allelectric single- family homes rather than a downstream rebate typically given to homeowners or tenants.

Contractors would qualify for a rebate by developing electric- only homes, thus eliminating the need to connect to natural gas lines and reducing the overall cost to construct the home. Additionally, REU expects an increase in revenue due to the shift in usage from natural gas to electric- equivalent equipment. In order to qualify for a rebate, contractors would need to install a heat pump water heater and a heat pump space heater. Other measures may be added in the future. ui 1 i iii iiiii i uu ui u ui ii u ui i iiii 1 1 JJJJJJJJJJJJJJJJJ IIIIIII II I I1 1111111111111111111 IIIIUIIIIII I I I 1111, JJJ1IJJJ I1111111111111111 1 1 IU I IIIlllllll II III IIIDIIIIIII I II IIIUI III1JJJJJJI 1 11 JJJJ!!!!! 11 JJJJJJJJJJJJ lllUlll 1. 1 111111111J11111, III11111 l, ) J11JJJ11JJ1JJ11l, 1) ) II, II, IIIIU11UlU 1 , , ) 1 JJJJ1J JJJ!!! r , , ,, r„ , ,, ,,, 11l>>>>>» i>> l»»>»» 11 IJ1 , 1>> 11»» 1 f» 11111 111111111JJ111111 1 1111111J 11111 11111 1 11111 1111 11 1 11 11 11111111111 11111 11 1>>l l>>» 1J1 l>><<«« J« Ir«« 1 1 11 < < < 111 i11«<« 1 1 1 1 111 1 1« 1 111 111111J1 1J 1111 J 111 11 , > > > 11J1111111i 11J1111111>> r l>> i>> l>»»J l»>» 1>»»»»»»>>>1»i I > > > 1 r 1»l l>» 1 1 111 11111 1111 1111 11111 1111 11111 . 1111111111111111.

Heat Pump Water Heater and
Heat Pump Space Heating
1, 800 per dwelling July 1, 2022
Induction Cooktops
To Be Determined To Be Determined
Electric Ovens
r: llll',Yklld' ', "° 1 d' 4i116, I d!" II" Y4 IIr,IlII II°!!` VC , Qlll" YI° i ll ll"°. II& IIYI ,. II. IIII@I IIIIYI"' . Ild' g 1 II II IIV' IV IIQIII" YI Id'"" IIQI"' Il r: llll"II'" d' 1 r!illIIII yu i yu i.° u. 0 II III i u II m u i: N III II. 5 IG u u 5 iu yN a r l b s
The Commercial euilding Electrification program provides an incentive to commercial customers ( owners and tenants) who replace their natural gas equipment with electric- equivalent equipment. Measures eligible for initial replacement are water heating and space heating, with a potential for further incentives for other technologies. The incentives will be based on reducing the incremental cost of converting to electric- equivalent equipment. Program details are listed in Table 8- 3.

III I1JI llllJJJJJJJJJJJJJ JJJJJJJJJJJJJJJJJ 1 11111 I IlllUlll IIIIII 1. II 1 I IIII I I1 1111111111111111111 11111111JJ11111, III II III11111 III l, ) IUI I III IIII 1D 111111111 IIIJ11JJJ11JJ1JJ11! J) ) ll I1111111111111111 1 I1 U I II IIIIII,I) llllllII,III IIIIU11UlU III III I D III IIII II IIIUI1 III11JJJJ11 1D JJJJ11 J 111111 11JJJ!! 111J!11 1!!! 1 l 1 , ) 11>> l>>>>>» l» a»»>»» 11 1JJ 1>> 11»» 1 J» 1 1J 1111 J 1 J J i 1>>l l>>» 1111 l>>><<«« J<< Ir«« 1 1 111 < < < 111 11«<« 1 1 1 Il1 ll«1 111 1111 1111 1 11 11 > > > > > 11J11 11111111i 1111J 1>>>>>> l>> I>>»»J l»>»> 1>»»»»»»>>l»i I > > > 1 1 1>»» I>11 1 11 1 11 1 1111 11 1 111 . 111i Heat Pump Water Heater 1, 000 per unit July 1, 2022
Heat Pump Space Heater To Be Determined To Be Determined ll : a lk. ll k, , a uu uu! ua u a ll I' ii ulln uuyM°; Il u°. ir. ii u at. ii: iryi Il o-; ir. a uuo n a iill 6 III i m u 5 i' i . 0° i n b ii S,. u° I N
One of the most significant barriers to any electrification program is a lack of knowledge and understanding of the measures, along with the program benefits, for participants and non- participants. It is imperative to develop a comprehensive education and outreach ( E& O) program to educate customers, contractors, suppliers, and other stakeholders to ensure building electrification programs are successful.

As part of program implementation, REU will need to provide E& O services for contractors and customers.

This is essential to getting the program off the ground as it is a fundamental shift in how REU currently I Ir r, P: rifir Ylr, ri I' rr., rt r i r Ur51r,; 15i ir5r p i
Packet Pg. 411 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric offers rebates. REU will work with the City' s communication and marketing team to develop a communication plan that will garner support for the program.

E& O activities would include:

JJJJ: Provide education on the pros and cons of fuel switching, the potential cost savings, and the overall benefits of building electrification
JJJJ: Educate customers on the rebate programs and how to participate in them JJJJ: Solicit feedback from customers regarding satisfaction with the programs JJJJ: Develop customer- facing marketing materials for local contractors and trade associations to support the message.

8. 2 TRANSPORTATION ELECTRIFICATION PROGRAM
CARB designed and implemented the Low Carbon Fuel Standards ( LCFS) Program to reduce greenhouse gas emissions from fuels used for transportation, including gasoline, diesel, and their alternatives. Redding has an opportunity to leverage revenue generated from the LCFS program to provide added value to the community through investments in transportation electrification initiatives benefitting current and future EV drivers. By replacing gas vehicles with electric, customers significantly reduce annual fuel costs and carbon emissions while increasing load and utility revenue, meaning the program benefits both participants and non- participants.

The development of REU' s transportation electrification programs considers the current rate of adoption of EVs in the service territory and is right- sized to create a successful program with realistic, achievable goals. These programs are designed to meet regulatory requirements, and program implementation timelines are reflective of those mandates. With that in mind, the utility plans to implement LCFS- funded programs as account reserves allow and increase program offering as additional funding becomes available through LCFS.
p,,. d. II@'' i Ilrrr; N'° 1° m. UI II, XW yY II.!' 1' N'° II II m. UI IV' XW IG Illl.!' ll";; m. Ul'.!' I° N° u m. U" Yn IP The Transportation Electrification Rebate Program is one that benefits both program participants and non- participants. The cost of fueling a gas vehicle is roughly three times that of fueling an electric vehicle in Redding. Additionally, the increased load and revenue realized from added EVs in Redding' s service territory allows the utility to reduce carbon emissions while generating increased LCFS credits.

Pr r s w s
Despite the amount of growth in the electric vehicle sector over the last five to ten years, Redding has experienced slower than average growth in EVs compared to the rest of the state. This trend has been beneficial in some ways because REU has learned from other utilities and found best practices and proven methods for increasing adoption. The programs that are the least risk and most cost- effective will be I Ir r, P: rifir Ylr, ri rr., rt r i r vr5lr,; l5i ir5r p i,
Packet Pg. 412 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric implemented initially, with oversight, continued improvement, and evaluation of the program' s health and effectiveness.

Redding plans to continue its electric vehicle rebate program that has provided incentives significant enough to drive investments and make a material impact on the adoption of electric vehicles in the utility service area.

III I1J
I llllJ JJJJJJJJJJJJJJJJJ 1 11111 I IIIIIIIII I II IIIIIUIIIIII1, 1 I I 1D III11111111 llI1111111111111111I) 1 I II I IIII I I1 111111111111111111111 !!!! I 1 1 IIIII 111 11!!!! 11 IIII I I l 111111111 II I IIIII I IIIIIII IIIII 1 I 11111111 1 1 III I 1 1111111111111 1 1' llllllll 1111111 l, ) 111) 1 1111111 111 1111111) 1111,,, 11 111111 111111 ) , , 111 „ 1111 111111 r , , „ , r i r' 11>> l>>>,>» l» a»»»11 1J1 1>> 11»> 1 f» 1 1J 11111 > > J 1 1>>,» l>> l,>>a,,I>>>>>>> l i,>> 1 > > l»> l»>1»» 1>> a i>> l>11J1111111 11J11111J1JJ 111 11111J11111 111J11J11J11 i 1>>l l>>» lII l,>»J11J111J fifl Jl1JJJ Jff,f fJlrf» f11f J rJ > > flJt f1JffJ1 1 JJ J 11>>l l»»» l>>I l»>a, l ffrtffrr f fflrf>» 1»> Residentia) and Commercia) $ 1, 000 per unit Existing LCFS EV Rebates
Electric Forklift Rebates 2, 500 per unit July 1, 2021 LCFS ll : a lk. ll k, If° 111 u a uyG4 l1.: u at. ii: iryi Il u;°. ir u u a. ii: uyi I o-°; u a uuo ':' a iill F .' @ 1t III IV' YII II.!' II @' m;: U II rrr N'" fl° m. 0 l II, XW` yY II.!' 1 N'" II II m. 0 l IV XW Il I„ u m. 0" Yn IY The low- income transportation electrification program is one that benefits both participants of the program in addition to non- participants. REU can make a significant impact in the reduction of the emissions from transportation by replacing gas vehicles with electric and promoting the use of alternative clean mobility options in low-income communities.

Pr r s w s
Redding intends to create a holistic, income- qualified electric vehicle program that provides education, resources, incentives, and accessible means for clean transportation. REU' s programs will be structured to directly impact reducing carbon emissions from transportation in the utility' s service area, ensuring income- qualified applicants have equal access to clean mobility.

As participants of the LCFS Program, the utility is obligated to meet spending requirements and reinvest funding into specific spending categories per the LCFS regulations17. The following program measures are targeted to primarily benefit income- qualified customers and meet the low-income spending requirements of the LCFS program.

III I I llll 1 11111 I II 1D III ll II I IIII I 1 IIIII 111 11 IIII I I II I IIIII I UI I II 11I.I1 1J J JJJJJJJJJJJJJJJJJ IIIIIII ll l lll II ll IIIIIUIIIIII1, 11111111 1 I I 11111111 1) 1) I1111111111111111 1111111 1 111I I) I1 111111111111111111111 !!!! 111111I 1)1 1111,,,, 11!!!! 11 l111111 111111111 l U!!!! 11! J1111111 11) 1 ,,,) 11JJ1J11JJJJ111 1)))))))))1 r , , „ , 11>> l>>>,>» l» a»»»» 11 1J1 1>> r 11»> 1f» 1 1J 11111 > > J 1 11>>,» l>> l,>>a>>,, I>>>>>>> 1>> 1 > > l»>1»» 1>>>>>a l>>11J1111111 11J11111J1JJ 111 11111J11111 111J11J11J11 1 1>>l l>>» 1II l,>»J11J111J f f1 J11 JJJ Jff,f fJlrf» f11f J rrJ > > flJt f1 JffJ1 1 JJ J, 11>>, l>>,1»11»>a» a, llff ffrt1 f fflif>» f11»> 11 1111 1 EV Rebates for Income 3, 000 per unit July 1, 2022 LCFS Low- Income Qualified Customers
To maximize benefits to income- qualified customers and materially impact barriers to adoption, the utility will endeavor to implement this as a point- of- purchase rebate, reducing the vehicle' s purchase amount rather than providing reimbursement after the fact; the feasibility of this option has yet to be determined.

Lnw.._Ca_ n 7.._F_ue.._Sta 7_ci.a ci..._Cu_r e t.._Fte. u. at._n.p7 I Ir r, P: rifir Ylr, ri I' rr., rt r i r Ur51r,; ISi irSri Y i4( S Packet Pg. 413 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric v IIi Rwr15 XW YnIP „ XW YIIYI" YII" II R II@15 I': i' XW 15 mm Pr r rn i s s rs
By providing public charging infrastructure and access to clean mobility options, the utility will increase energy loads while decreasing carbon emissions, providing health benefits for the entire Redding community through the Custom Community Projects.

Pr r F w s
REU has allocated$ 325, 000 of LCFS Low- Income funding to the Custom Community Projects. The program is designed to be a flexible resource providing support that allows the utility to act as community partners for transportation electrification projects that will benefit the community, specifically low- income residents. Some areas REU is considering for local investments or partnerships are as follows:

JJJJ: Local Transportation Agencies— As a community partner, the City of Redding would like to collaborate with local transportation agencies to support the addition of public charging infrastructure, public transit electrification, and provide funding for alternative e- mobility options targeted to benefit low-income areas where practical.

JJJJ: Grant Funding — As opportunities arise, such as the e- Bike Share program that may be coming to the Redding area, the utility may choose to provide grant funding on projects that align with the City' s transportation electrification goals and objectives.

JJJJ: Multi- Dwelling Unit Charging— REU will seek opportunities to install charging stations for low-income multi-family housing developments similar to newly constructed housing developments in the downtown area.

III i m. 0 5 i' i . 0° i n b ii 5,. u l N
Misinformation and lack of education are among the most significant barriers to increased electric vehicle adoption. Many customers are not well- informed about the cost of fueling an electric vehicle and often have misconceptions about driving and owning an EV. To overcome those obstacles, REU will develop a comprehensive, all- inclusive educational program spanning all segments of the transportation electrification program to provide information and access to resources for residential and commercial customers, including local dealerships.

To accomplish this, REU will undertake the following:

JJJJ: Electric Vehicle " Ride- and- Drives" with customers who can gain valuable knowledge and participate in a hands- on experience driving an EV without feeling pressured.

JJJJ: Increase efforts to educate customers and dealers to ensure stakeholders understand the costs of driving electric, the fuel savings over gas vehicles, and overall benefits.

I Ir r, P: rifir Ylr, ri I' rr., rt r i r Ur51r,; 15i ir5r p r Packet Pg. 414 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric JJJJ: Provide easy access to resources to ensure interested parties are more knowledgeable about applicable incentives when purchasing or leasing an electric vehicle.

JJJJ: Use various methods of communication such as in- person, radio, print, billboards, and social media to reach various population segments.

8. 3 ELECTRIFICATION PROGRAM BUDGET
Table 8- 5 shows the estimated budget available for electrification programs over the next 10 years, and Table 8- 6 shows the portion of each budget t reserved for the measures planned for FY 23- FY 27. u i I i iiiiii uuu i 11 1 i ii uui i 111 iiii1 iu i » i i iuu i u u» i» » »i »»» » i i I1 11111 111111I IIIII11111111111 J111111 1 Jl IIIIIIIIIII111I 11 1. 11 111111111111 11„1111JJJJIJJJ JJ1 J1!!!! 11„1J 1111111 !!! 1 ,. ! 11111. . 11111111J„ I 1I!!! I 11111! 11 JJJJJJJJ 1 11111. , 111 , 1. JJJJJJJ„ 1 1111111 1111111J !!! 1, 1 11 I ) 1l1111JJJ JJIJ l J, J , JJJJ 11JJJJ) l. I r , , r„ , ,» » r„ , c ,, ,» » r„ ; r,
Yi ff1 ,° Jf f
l111Jf, i if i1/ 1/ u1f111l1/ fr, 1l l ll/ll,rtil!rli l,i l , „ a a,. i,17, f iNJlJIJI,. 1 1 il111111fI1, 1 1 7» 1 , „ JJJIJJJ 1 JJ/J»11J 11iJJJ1lIl1N11111l, 1, i il» 11iiJ llullJii iiI, r J1Jk1 lil 1JJ 1 l I „ i 1, ii11J171J il li111,i , 1lJlli,Il, ldlll/! ff , ll/l1,ll111i/lff1 ll`lI/c/ l//ilJf/JI/ i/1,/1,1 J 111 111 I i I IIIII IIII llllU I IIII I' I I I IIIIIII00 11I 1 11 I II IIIIIII00 11I 111 II 1 I1D 111111111111 I IIII I I II I ,/ I ull 1 IIII11 lUV 111
r , r , „ , . 11 j 1 111111 1, I: , , ,., J IIIe „ IIIe „ II, ,,, I I , » Illllllllll l rr m l 1 l l r i i lllllllllllllllllllllllllt i r l f r i i lllllllllllllllllllllllllllll f h n l r III III IIIIIIIIII Current Balance 45, 000 45, 000
2022 165, 000 300, 000 465, 000
2023 120, 000 70, 000 300, 000 490, 000
2024 90, 000 85, 000 350, 000 525, 000
2025 65, 000 105, 000 400, 000 570, 000
2026 70, 000 115, 000 450, 000 635, 000
2027 75, 000 120, 000 500, 000 695, 000
2028 80, 000 125, 000 550, 000 755, 000
2029 85, 000 135, 000 600, 000 820, 000
2030 90, 000 145, 000 650, 000 885, 000
2031 95, 000 150, 000 700, 000 945, 000
Tota) 980, 000 1, 050, 000 4, 800, 000 6, 830, 000
ll : a Ik. II k,k°' U 11 a ir II°. ir. ii u at. ii: uyi 04 r! a iill a II II i i!°. a u a° 4 ii uu°, u° ii,, a ir iiri
IlI l1 ! 11111!!!! 1 1 1111D 1 IIIIII I 11 1111 11 1 1 1 II IIIII III 111 IIIIIIII 1 1 1 I Ill 1 JJJI J1 ) 1l11111111111 I JJl1 JJ !! 11!!! l1111 I ) 1. J1 1 I 11111111111111 1 , 1 JJJJJJJJ!!!! 1„J11 ! J 1111111 111 ! 1 1 111 I _ JII111 . 1 111111111„ 11 I 1I!!! J!))1 1 IIIIII 1 / 1 ilJ , i „ I»>J»I»>////// ll r .» .» ., 1Jl lJ1Jl» ll l>>> l tlttttrltIli tlltllll>>, t>>>, 1 1» 11Jl lJ1J1JJaJJl1J1J1JlJ1JJ1J>>» lJ l l l J I J>>>,il I»»>» 1»» a» 1l , , > > , l1»l»1»», 1 l1 l>» u»>»I 1>»> 1>>t» 1»» 1»>» I>>>>> 1» 1111II1111II 111I11111I 1 II111111 III111I11 1 1 1111, 1111JJ,,,,,,,,, ,,,,,,.,, 1 l 1 1/ll/ll/ 1, fff, r»> rrr
r »> ii iIll 1 l
ll>>i ii
l J J I ,»,, ; J . J J 1 1 11,,,,,,,IIaaa 1 a lu, 1 I I1» l 1»» »1 1 11»» 11l 1 1 1 t 1 1ll ll 1 i fff 111111Itlll f I
l. r 1 llli i, lli J1 II I I I IIIIIIIIIII IIIIIIIIIIIIIIIIIIIIII IIII I «<«««« r««<<«««««««««<< I«« ll,,,,,,,,,,,,,,,,,,,,lt 1 Beginning
Expenditure
2022
2023 65, 000 45, 000 65, 000 235, 000 410, 000
2024 67, 500 45, 000 65, 000 235, 000 412, 500
2025 67, 500 25, 000 65, 000 400, 000 557, 500
2026 67, 500 25, 000 65, 000 500, 000 657, 500
2027 67, 500 25, 000 65, 000 600, 000 757, 500
I Ir r, P: rifir Ylr, ri I' rr., rt r i r Ur51r,; ISi irSri Y i[; Packet Pg. 415 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric zozs
2029
2030
2031
Tota) 335, 000 165, 000 325, 000 1, 970, 000 2, 795, 000 ll : a Ik. II k, ' U 11 a ir II°. ir. ii u at. ii: u yi II II a iry iryi n, IG r u yi, N ii°. i, u ° i, u° u,° o u u: a ir Tables 8- 5 and 8- 6 show that the planned expenditure represents approximately 40% of the available budget over the next 10 years. As these programs mature, building codes change, and REU responds to community needs, more programs and measures will be developed, and the remaining budget will be allocated. The planned expenditure by program and budgeted measure quantities are shown in Table 8- 7. r iuu i i i 1111„ i ii l llll lll i111111 11 J
ii» i»iJ
i 1111J 111 1 J1 111 1111 1 J 1
iuuiu1 1 11 I . , J , . . , J , , I II IIII I IIIII I I II c,,., ,, ,,, r, , c , , , , ,, , „ ,,, ; , r , , i I , iiiuf ui i ,iu, tr rrlrrr r l 1 lllf 1J>> l>>>>>» I l a» a»>»>»»> 1>>»>»»»>><«« 1 > > , l>>11 1 1111 111 111 1 111111 i,1>>»>»»> l>»>>>» Il lll lll ll111 llf ll1llll»11 1 ft > > 1>>l l»»l>>Ia» 1»>1» 1 1 1>>,>»» 1 1t1 1 1,f, 1111111 i111111»1111 11l111111i111 fi 1 Residential& Commercial EV Rebates $ 246, 000 LCFS 164
Commercial Forklift Rebates 18, 000 LCFS 6
Low- Income EV Rebates 236, 000 LCFS— Low Income 59
Custom Community Projects 325, 000 LCFS— Low Income 3
Water Heater 600, 000 Public Benefits 400
Clothes Dryer 100, 000 Public Benefits 333
All Electric New Home 1, 000, 000 Public Benefits 400
Commercial Water Heater 270, 000 Public Benefits 180
ll : a Ik. II k, ° " h a 4, ii. ir ii a iryw ii ii ii u yi II ii, N^ n, u u yi Ik: II: a u yi u yi n:; N II r n iry; u ii u n,°, ii u u o u u! a ir

8. 4 ELECTRIFICATION PROGRAM IMPLEMENTATION
Staff aims to develop a suite of customer program measures encouraging adoption in electrification. The utility will use a phased approach over 12 months to transition out of energy efficiency measures and into electrification. Strategic communication with internal and external stakeholders will ensure the smooth transition to electrification and ultimately aid in the program' s overall success.

I Ir r, P: rifir Ylr, ri I' rr., rt r i r Ur51r,; ISi irSri Y ilt Packet Pg. 416 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric I
This report discussed the development of a Demand- Side Management Integrated Resource Plan and presented the results. The DSM- IRP helps support REU' s mission of providing reliable, cost- effective service by identifying an optimal Demand- Side Management plan that achieves regulatory requirements while addressing community and customer needs.

This report documents the tools, methods and assumptions that were employed to identify the best mix of programs and measures that will help ensure that REU programs are 1) cost- effective for participants, 2) fair for non- participants, and 3) are focused on achieving cost- effective GHG emissions reduction. As documented herein, electrification measures can achieve these goals, whereas classic energy efficiency programs may be unfair to non- participants and are not a cost- effective way to reduce carbon emissions.

With this in mind, REU is recommending a transition from EE programs to electrification programs.

This DSM- IRP will be updated as conditions warrant to ensure that future program offerings continue to meet the community objectives as California transitions to a zero- carbon electrical grid. f,: r, ri r, I i,. a a r, ri l; f: l
Packet Pg. 417 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric I

10. 1 APPENDIX A: AVOIDED COSTS
i iiiri iiiiiiiiiiiooioio fii , i iiiiiii i iii ir / rrr,r r r f rrrrr rrl „ri
t, l
u , ,, , jj r, , ,,, r r r f f
I
1 rr , rfJJ11r1J11 r rr111lflI l1 1 l
lf ll1fl 11/ff r
r , ,
llllll// ll // fffff.l/l
1 f/%ff , , /
fff%,,,,,,,,,,, ff,,,,,,,,,,,,,, f r,,,, i,,,,,,,,,,,,,,,,///// r,,, l1/ll/// l1, 1,,,,,,,,,,,,,,, l , 1,,,, ,,, f,,,,,,,,,, J,,,, 1,,,,1,,, J ll1lllllll lllllllll llllllllllllllllllllll, ll II, 2020 0. 0430 0. 0021 0. 0018 0. 0468
2021 0. 0430 0. 0021 0. 0018 0. 0468
2022 0. 0500 0. 0024 0. 0021 0. 0545
2023 0. 0376 0. 0018 0. 0016 0. 0037 0. 0447
2024 0. 0379 0. 0018 0. 0016 0. 0040 0. 0454
2025 0. 0390 0. 0019 0. 0016 0. 0043 0. 0468
2026 0. 0373 0. 0018 0. 0016 0. 0044 0. 0451
2027 0. 0382 0. 0019 0. 0016 0. 0047 0. 0463
2028 0. 0392 0. 0019 0. 0016 0. 0050 0. 0477
2029 0. 0399 0. 0019 0. 0017 0. 0052 0. 0487
2030 0. 0411 0. 0020 0. 0017 0. 0054 0. 0502
2031 0. 0404 0. 0020 0. 0017 0. 0054 0. 0495
2032 0. 0342 0. 0017 0. 0014 0. 0054 0. 0427
2033 0. 0530 0. 0026 0. 0022 0. 0054 0. 0632
2034 0. 0545 0. 0026 0. 0023 0. 0054 0. 0648
2035 0. 0557 0. 0027 0. 0023 0. 0054 0. 0662
2036 0. 0575 0. 0028 0. 0024 0. 0054 0. 0682
2037 0. 0591 0. 0029 0. 0025 0. 0054 0. 0699
2038 0. 0601 0. 0029 0. 0025 0. 0054 0. 0710
2039 0. 0600 0. 0029 0. 0025 0. 0054 0. 0709
2040 0. 0548 0. 0027 0. 0023 0. 0054 0. 0652
2041 0. 0479 0. 0023 0. 0020 0. 0054 0. 0576
2042 0. 0571 0. 0028 0. 0024 0. 0054 0. 0677
2043 0. 0583 0. 0028 0. 0024 0. 0054 0. 0690
2044 0. 0590 0. 0029 0. 0025 0. 0054 0. 0697
2045 0. 0596 0. 0029 0. 0025 0. 0054 0. 0704
2046 0. 0603 0. 0029 0. 0025 0. 0054 0. 0711
2047 0. 0609 0. 0030 0. 0025 0. 0054 0. 0719
2048 0. 0616 0. 0030 0. 0026 0. 0054 0. 0726
2049 0. 0623 0. 0030 0. 0026 0. 0054 0. 0733
2050 0. 0630 0. 0031 0. 0026 0. 0054 0. 0741
ll : a lk. ll U N. 04 a iin:; N n, , 4 R° II a o- u, ak4. Ik.+ , a uu ll.: uyi uyG g "° II\ II° y fkl5l5r 5i, ii. r 5 a a; 1.

Packet Pg. 418 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric ii ii
u

1.6 uu
W
u
Y l. l':
r
wuu wuw
i?.?..'q. mm u uuyy yuw umw
u' uww
uwu
y
a y , 1 C" . i: ,,,,; w, n' i
y
idi ,.: n ti" ," .,
v' .,.',^ .
t r,"
p
w ; ,; N" a° w"` ryu h' ryu
h ryw,h w.
h ti:
n w.n w, n
1, 1, . I,
o ""
u. "
IIII 11 I o1
o r o!, o1o rc 01 I a IIIIIIII I"'> Co ll¢,
t o1 I a FG` G o,
oo rc olt
fkl5l5r ii ii, r:,,, a;
Packet Pg. 419 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric

10. 2 APPENDIX B: RETAIL RATES AND OTHER COSTS
The ESP Cost- Effectiveness Tool utilizes retail rates to calculate bill savings and costs for each measure.

REU did not calculate the bill savings/ costs in previous filings of the Annual Energy Efficiency Reports.

Because bill savings and costs are a factor in the Participant Cost Test ( PCT), Redding has begun to utilize retail rates for the following energy uses: electricity, natural gas, and gasoline.

City of Redding Electricity
JJJJ: Residential ( E1)
JJJJ: Low- Income Residential ( E1LP)
JJJJ: Small Commercial ( E2)
JJJJ: Large Commercial ( E7) ( Blended Rate)
JJJJ: LED Streetlights ( COR retail costs—$ 0)
Redding does not anticipate a rise in volumetric rates as future rate increases will be applied toward the Network Access Charge ( NAC). The Federal Environmental Surcharge ( FES) and the State Regulatory Surcharge ( STATE) are also included in the rates. This study assumes the FES and STATE surcharges will remain flat; however, they may increase or decrease at any time.

The FES is allocated toward payments for REU' s wholesale costs due to the City of Redding purchases from the DOE and WAPA. The STATE 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 CEC18.

The following charts show the rates and costs that were used in analysis. 18 City of Redding Schedule of Rates— Section A 21- 22.

Ih.tt.a.:../.../.. w. nr nr.:_c t.ynf eci_ci.. p7,.: n r/ F n.p_ e Slh.n r_C n cu mr e_nt__ ci..-_22899 f l515r 5ii ii. r;5,
Packet Pg. 420 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric I i_ I r rc i m I i i u
ti
r I ,,— I d°; , ,
i,
n. i .
i : i i
r, i,,
i(
i,
iI
r, r, r, n„,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,, Fy
L` o
v , ,, v'' y r r
vllli `,1 „ l i, lti IIi,
rir, i, ,-; III,. III ',
r 1 I I I ', r: r' 1 , a; I / I ,';'+ t,, i' it'( .;
I''' i i',..I ,,,, I I, d; I ,,,; '! e ,, I
r` ..,, ,,,, i I I e I ,..;; I,;; i.. J,,:' e ,,!,,
nn
r; r;
t;!
z;,
umm Us
Y
nn oi m,,,um,,, utmm„u
f f c; uun m w o mu
z n
n
nn wm
nwom i
uyw nnoim5 mni n mi lii mroxw m u m i
a,.-
u' mi
imnm nn
iim mi I lili ........

1.. 1 1
rA
1 J
7 i , , i, Y' r "
r r ., w. ,. , ,. , ,
a r ,, r ,, a ,. a' ,. a'
v ' l' ' l ' l ' l ' l ' l , , . . ,. ,. a ro r r rnlJ/, 1I ,' ll, i f 1' ll' ll" I, , , , , ,,,,,,,, IJ/
I I , iCl' ' 1 , J'.,
I',," I I I I ` ' 1 ,! ,, VJ I f' i' r1 , , , a.,
r.5r.5r,5ri: ilr, r,5
a 1;[
Packet Pg. 421 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric A , i„ I ,,,, I / ,,,, I, I ,.,,,;%-. e,:
r. J.. 1 1
i' J.. 1 1
1 1
oomoomA
1 firS ^ 11mp 1 maa
i M
i
i t
mm^"°°
i;/ / i/ i
I i i
i i
rr
ti
r>
i n=i,' ; r r i " r r.

U v „ r' ' v i/ i ' L U i, ii ' v . U` ' i
r
irl ir Allll w ir V IIu I ir
a..
u. a.
r: A.. am° m
QJ naaa
7r...
uhaae" aae° p0 am'' iN°
i.
um o
5:::

K" 7..
neau+mamm m»tim n
7r.

G., D M.'„„w
mm mmw u"'' i
7r. muum mm
ui
n m m uommm mn¢onumm mm nmm ti
mi
7rc. mo
m mmn mnoamos
iuuuumi vnmimwiwmurwimti umm inmmnim n omo aomu
C`a' CY'
y
C"a1' CX1'
S
C"a' CX'
k
C`a''"
y
X,"' r' 9,
y.

Y
X,^
w '
9,°" X"
v
9 Y P ' b
t
r. r .. r .. r r.. . r.. r. r.. r. r.. r. r.
r r r r r u(.; rar c ro
fkl5l5r ii ii. r a a: a
Packet Pg. 422 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric

10. 3 APPENDIX C: FORMULAE USED TO CALCULATE ENERGY EFFICIENCY COSTEFFECTIVENESS TESTS This appendix provides the formulae that are used to calculate the following energy efficiency cost- effectiveness tests:
l. Participant Cost Test( PCT)

2. Total Resource Cost Test (TRC)

3. Rate Impact Measure Test( RIM)

4. Program Administrator Cost Test( PACT)

5. Societal Cost Test ( SCT)

6. Cost per lifetime kWh saved

7. Total Value Test for beneficial electrification programs Avoided costs are the costs of those electricity and gas resources that are deferred or avoided by the energy efficiency measures or programs being evaluated for cost- effectiveness. The avoided costs include cost avoided when generation, transmission and distribution infrastructure are deferred or avoided by energy efficiency measures or programs. Avoided costs are a key component of the benefits of energy efficiency resources. REU' s avoided electricity costs include the cost of carbon.

Formulae for Participant Test (PCT)
The following are the formulas for discounted payback, the net present value( NPVp) and the benefit- cost ratio ( BCRp) for the Participant Test.

NPVP Bp - Cp
NPVavp Bp - Cp)/ P
BCRp Bp / Cp
DPp Min j
such that Bj > Cj
Where:

NPVp Net present value to all participants
NPVavp Net present value to the average participant
BCRp Benefit- cost ratio to participants
DPp Discounted payback in years
Bp NPV of benefits to participants
Cp NPV of costs to participants
Bj Cumulative benefits to participants in year j
Cj Cumulative costs to participants in year j
P Number of program participants
J First year in which cumulative benefits are greater than cumulative costs.
d Interest rate( discount)
i} i} r,, r, a ac.

Packet Pg. 423 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric The Benefit( Bp) and Cost( Cp) terms are further defined as follows:

N
BRt+ TCt + INCt ' ABat + PAat
BP- (
1 + d)
c- +
t-i ( 1 + d)
cN
PCt+ BIt C=
t=1( 1 + d)
tWhere:

BRt Bill reductions in year t
Bit Bill increases in year t
TCt Tax credits in year t
INCt Incentives paid to the participant by the sponsoring utility in year t3 PCt Participant costs in year t include:

Initial capital costs, including sales tax4
Ongoing operation and maintenance costs, including fuel costs Removal costs, less salvage value
Value of the customer's time in arranging for installation, if significant
PAat Participant avoided costs in year t for alternate fuel devices ( costs of devices not chosen)
Abat Avoided bill from alternate fuel in year t
The first summation in the Bp equation should be used for conservation and load management programs. For fuel substitution programs, both the first and second summations should be used for Bp.

Note that in most cases, the customer bill impact terms ( BRt, BIt, and ABaf) are further determined by costing period to reflect load impacts and/or rate schedules, which vary substantially by time of day and season. The formulas for these variables are as follows:
r
BRt = ( EGIt x AC: Elt x Klt)+ ( DGIt x AC : Dlt x Klt) + OBRt i=1 i= 1
ABat = ( Use BRt for nula, but with rates and costing periods appropriate for the alternate fuel utility)
1 1
BIt = EGIt x AC : Elt x ( Klt — 1) + DGIt x AC : Dlt x ( Klt — 1) + OBIt 1 i= 1
WIZCI"C:
r.5r.5c 5r,: ilr, c 5 a 1;
Packet Pg. 424 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric 4EGf Reduction in gross energy use in costing period i in year t 4DG f Reduction in gross billing demand in costing period i in year t AC:E f Rate charged for energy in costing period i in year t 3 Some difference of opinion exists as to what should be called an incentive. The term can be interpreted broadly to include almost anything. Direct rebates, interest payment subsidies, and even energy audits can be called incentives. Operationally, it is necessary to restrict the term to include only dollar benefits such as rebates or rate incentives( monthly bill credits).

Information and services such as audits are not considered incentives for the purposes of these tests. If the incentive is to offset a specific participant cost, as in a rebate- type incentive, the full customer cost( before the rebate) must be included in the PCc term.

If money is borrowed by the customer to cover this cost, it may not be necessary to calculate the annual mortgage and discount this amount if the present worth of the mortgage payments equals the initial cost. This occurs when the discount rate used is equal to the interest rate of the mortgage. Ifthe two rates differ( e. g., a loan offered by the utility), then the stream of mortgage payments should be discounted by the discount rate chosen.

AC: D f Rate charged for demand in costing period i in year t K f 1 when 4EGit or 4DGit is positive( a reduction) in costing period i in year t, and zero otherwise
OBRf Other bill reductions or avoided bill payments ( e. g., customer charges, standby rates).

OBIf Other bill increases (i.e. customer charges, standby rates).

I Number of periods of participant' s participation
In load management programs such as TOU rates and air- conditioning cycling, there are often no direct customer hardware costs. However, attempts should be made to quantify indirect costs customers may incur that enable them to take advantage of TOU rates and similar programs.

If no customer hardware costs are expected or estimates of indirect costs and value of service are unavailable, it may not be possible to calculate the benefit- cost ratio and discounted payback period.

Formulae for the Ratepayer Impact Measure Test (RIM)
Formulae: The formulae for the lifecycle revenue impact( LRI RIM)' net present value NPV RIM), benefit- cost ratio ( BCR RIM), the first- year revenue impacts and annual revenue impacts are presented below:

LRIIZIM = ( CRIM - BRIM) / E
FRIIZIM = ( CRIM - BRIM)/ E for t= I
ARIIZIMt = FRIIZIM for t= I
CRIMt- BRIMt)/ Et for t= 2,..., N
NPVRIM = BRIM- CRIM
BCRRIM' = BRIM/ CRIM
i i r=,. r;5 a a
Packet Pg. 425 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Where:

LRIIZIM = Life cycle revenue impact of the program per unit of energy ( kWh or therm) or demand ( kW) ( the one- time change in rates) or per customer the change in customer bills over the life of the program). ( Note: An appropriate choice of kWh, therm, kW, and customer should be made.) FRIIZIM = First-year revenue impact of the program per unit of energy, demand, or per customer.

ARIIZIM = Stream of cumulative annual revenue impacts of the program per unit of energy, demand, or per customer. ( Note: The terms in the ARI formula are not discounted; thus they are the nominal cumulative revenue impacts.)
Discounted cumulative revenue impacts may be calculated and submitted if they are indicated as such. Note also that the sum of the discounted stream of cumulative revenue impacts does not equal the LRI RIM.

NPVRIM = Net present value levels
BCRRIM = Benefit- cost ratio for rate levels
BRIM Benefits to rate levels or customer bills
CRIM Costs to rate levels or customer bills
E Discounted stream of system energy sales ( kWh or therms) or demand sales ( kW) or first- year customers. ( See Glossary of Terms for a description of the derivation and use of this term in the LRIRIM test.) The B and C terms are further defined as follows:

N
UACt+ RGt ' UACat
BRIM=
t- 1 ( 1 + d)
t- 1
t- 1( 1 + d)
t- 1
N N
UICt + RLt + PRCt + INCt RLat
Cnl` t=
1 + d) c- i1 + d) c- i
r= 1 t=i
E._ '
Ec
1( 1 + d)
t- i
Where:
f l515r 5ii ii. r;5 a
Packet Pg. 426 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric UACt Utility avoided supply costs in year t
UICt Utility increased supply costs in year t
RGt Revenue gain from increased sales in year t
RLt Revenue loss from reduced sales in year t
PRCt Program Administrator program costs in year t
Et System sales in kWh, kW or therms in year t or first year customers UACat Utility avoided supply costs for the alternate fuel in year t Rlat Revenue loss from avoided bill payments for alternate fuel in year t( i.e., device not chosen in a fuel substitution program)
For fuel substitution programs where the utility provides electricity and natural gas services to customers, the first term in the B RIM and C RIM equations represents the sponsoring utility electric or gas), and the second term represents the alternate utility. The RIM test should be calculated separately for electric and gas and combined electric andgas. An electric-only utility, such as Redding, does not need to consider the alternate utility effects in their application of the RIM.

The utility avoided cost terms ( UACf, UICf, and UACaf) are further determined by costing period to reflect time- variant costs of supply:
r
UI Ct = ( ENIt X MC : Elt x ( Klt) + ( DNIt X MC : Dic X Kic) i=1 i= 1
UACaf = ( Use UACt formula, but with marginal costs and costing periods appropriate frthe alternate fuel utility.)
r
UI Ct ( oENlt x n rc : E t
X ( K t — 1) + ( oDNlt x n rc : D tX ( K t— 1)))
i=1 i
Where:

Only terms not previously defined are included here.]
4ENit Reduction in net energy use in costing period i in year t 4DNit Reduction in net demand in costing period i in year t MC: Eit Marginal cost of energy in costing period i in year t MC: Dit Marginal cost of demand in costing period i in year t r. r. r= r,:, r;=a s:.

Packet Pg. 427 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric The revenue impact terms ( RGf, RL,f, and RLaf) are parallel to the bill impact terms in the Participant Test. The terms are calculated exactly the same way with the exception that the net impacts are used rather than gross impacts. If a net- to- gross ratio is used to differentiategross savings from net savings, the revenue terms and the participant' s bill terms will be related as follows:

RGt BIt * ( net- to- gross ratio)
RLt BRt * ( net- to- gross ratio)
Rlat Abat * ( net- to- gross ratio)
Formulas for the TRC Test
The TRC test formulas are presented below:

NPVTRC = BTRC - CTRC
BCRTRC = BTRC/ CTRC

LCTRC LCRC/ IMP
Where:

NPVTRC = Net present value of total costs of the resource BCRTRC = Benefit- cost ratio of total costs and benefits of the resource LCTRC Levelized cost per unit of the total cost of the resource( cents per lifetime kWh for conservation programs; dollars per kW for load management programs)
BTRC Benefits of the program
CTRC Costs of the program
LCRC Total resource costs used for levelizing
IMP Total discounted load impacts of the program
The B c, C c, LCRC, and IMP terms are further defined as follows:

N N
BTRC
UACt+ T Ct + UACat + PACat
1 + d) t- 1 ( 1 + d) t- 1
r=1 t= 1
fkl5l5r 5ii ii. r;5 a 5; 1.

Packet Pg. 428 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric CTRC
N
PRCt+ PCNt+ UI Ct
t- 1
r=1 ( 1 + d)
LCRC
N
PRCt+ PCNt_ TCt
t- 1
r=1 ( 1 + d)
N lEn 1 ENit r)
IMP = t= i i+ a
t- (
Where I equals peak period)
All terms are defined in the 2001 California Standard Practice Manual.] The first summation in the BTRC equation should be used for conservation and load management programs. For fuel substitution programs, both the first and second summations should be used.

Formulas for the Program Administrator Cost Test (PACT) The PACT formulas for the net present value, the benefit- cost ratio and levelized cost are presentedbelow:

NPVpa Bpa- Cpa
BCRpa Bpa/ Cpa
LCpa LCpa/ IMP
Where:

NPVpa Net present value of Program Administrator costs
BCRpa Benefit- cost ratio of Program Administrator benefits and costs LCpa Levelized cost per unit of Program Administrator costs of the resource Bpa Benefits of the program
Cpa Costs of the program
LCpc Total Program Administrator costs used for levelizing N
UACt
N
UACat
B
pa=
t- 1( 1 + d)`-
1 t_ 1( 1 + d)`-
1 i i r=, r;5 a r.,,
Packet Pg. 429 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Cpa
N
PRCt + INCt + UICt
1 + d)
tLCp_
PRCt + INCt
r=1 ( 1 + d)
tAll variables are defined in the 2001 California Standard Practice Manual.] The first summation in the Bpa equation should be used for conservation and load management programs. For fuel substitution programs, both the first and second summations should be used.

Societal Cost Test (SCT)
The Societal Cost Test us very similar to the Total Resource Cost Test, but it examines costs and benefits from the viewpoint of Society. The Societal test considers the costs and benefits included in the TRC test, plus costs and benefits that affect society as a whole. Additional benefits considered by the Societal Cost Test include environmental benefits ( such as reduced emissions from power plants) and health and safety benefits. Additional costs are those associated with additional expenditures ( if any) required to achieve the societal benefits. It is widely accepted that the societal discount rate should be used when calculating the SCT. This is consistent with the notion of aligning the discount rate with the relevant perspective of the test.

The purpose of the SCT is to indicate whether the benefits of an EE resource will exceed its costs from the perspective of society as a whole. This test provides the most comprehensive picture of the total impacts of an EE resource. This test includes all the impacts of the TRC test, plus the additional impacts on society. Note that the CaSPM refers to the SCT as a" variation" of the TRC test( CPUC 2001). Since then, many jurisdictions and many studies have referred to the SCT as a separate test with different implications.

The SCT is useful for identifying the total universe of economic impacts of investment in EE resources. It is particularly apt for jurisdictions that have particular interest in a range of societal considerations, such as environmental or economic development concerns, in addition to an interest in minimizing utility system and efficiency program participant costs.

Formula for Calculating the Cost of Conserved Energy
The CCE is analogous to the often used levelized cost of energy or levelized cost of electricity LCOE), which is commonly used in analysis by electric utilities:
i i r=, r;5 a r.

Packet Pg. 430 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric a _
Where:
d is the discount rate or cost of capital used to value future expenses in current year dollars y) is the total financial expenditures (i.e., capital and maintenance, but not energy costs) in year y; technically these expenditures include capital, financing costs, operations, maintenance, fuel, and all costs used to generate the electricity
y) is the energy generated in year y.

Since energy efficiency represents a counterfactual amount of saved energy measured from a baseline rather than energy produced, the cost of conserved energy requires reference to a baseline. Specifically for a scenario, X, compared to a baseline B we can define:

Where the superscripts refer to the baseline or scenario being analyzed as described above.

The cost of conserved energy ( CCE) represents the lifetime cost of providing a service that otherwise would be provided by less efficient equipment in energy units [ e. g., $/ million BTU 106MMBTU, cents/ kilowatt- hour( kWh), etc.]. In the 2012 National Renewable Energy Laboratory ( NREL) report titled " A Tool to Prioritize Energy Efficiency Investments", NREL found this cost of conserved energy metric to be superior to payback time, net present value of benefits, benefit- to- cost ratio, internal rate of return, and other cost metrics because it avoids explicitly assuming future energy prices. By instead expressing the cost as an equivalent energy price, it facilitates comparison of ineasures to volatile energy prices, other measures, and local or time- dependent effects that can significantly affect the assumed energy prices.

This cost of conserved energy metric can include un- priced externalities such as carbon price, opportunity value of time, and so on if they are used in the payment stream in the above equation. Finally note that it is straightforward to approximate the payback time from CCE; if we take the measure lifetime as L and the energy price as P the payback time is:
r. r. r= r,:, r= a s
Packet Pg. 431 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric CCE
T x L
P
NREL has a publicly available tool that calculates the cost of conserved energy for energy efficiency measures. When analyzing multiple energy efficiency measures, this tool creates a staged potential estimate and ranks energy efficiency measures from lowest to highest CCE.

Ties" in the cost of conserved energy are broken by re-ranking all ties from greatest to least potential energy savings in that scenario [ i.e.,
N ( EB( y) — EX( y))]. y= o
The NREL software tool creates estimates of energy savings for an energy efficiency measure or program portfolio by progressively comparing each measure with all lower CCE measures and reducing the savings to avoid" double counting" any savings that are already attributed to lower CCE measures.

Methodology for Including Savings of Non- Electric Fuels in Cost-Effectiveness Tests
There are standard methodologies for considering savings of non- electric fuels in energy efficiency cost- effectiveness tests. Many electric energy efficiency measures save more than just electricity when they are installed and operational. Non-electric space and water heating fuels, for example, include oil, coal, natural gas, propane, kerosene and wood. These other fuel savings can sometimes represent a large portion of the savings from efficiency measures, particularly for certain programs such as home retrofit or new construction programs.

The table below lists the common energy efficiency cost- effectiveness tests and indicates when costs and benefits for savings of non- electric fuels should be included in benefit/ cost test calculations in instances where non- electric fuel savings occur.

Include Cost and Savings Relating to
Non- Electric Fuels When Such Relevant Cost for Valuing NonCost- Effectiveness Test Savings Occur In Addition to Electric Electric Fuel Sa ings Savin s
Program Administrator Non- electric fuel savings are Avoided costs Cost Test considered only for fuels that the
utility sells to customers( for example,
utilities that provide electricity and
natural gas).

Participant Test Yes, include non-electric fuel savings. Retail rates Rate Impact Measure Non- electric fuel savings are Avoided costs Test considered only for fuels that the
utility sells to customers ( for example,
utilities that provide electricity and
natural gas). The Redding Electric
Utility does not include savings of
a=,. r;5 a r.,
Packet Pg. 432 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric non- electric fuels when calculating the
RIM test.

Total Resource Cost Yes, include non-electric fuel savings. Avoided costs Test
Societal Cost Test Yes, include non- electric fuel savings. Avoided costs Cost of conserved Yes. Typically, when a measure sa es Not applicable energy( CCE) multiple fuels, the CCE can be
calculated on a cost per lifetime
MMBtu saved, and costs are allocated
to fuel types based on lifetime
MMBtu saved.

Whenever there are savings of electricity and non- electric fuels, it is important that all applicable costs and benefits be considered in the benefit/ cost ratio calculation. See Chapters 3 and 8 of the 2017 National Standard Practice Manual for a more detailed discussion of accounting for the costs and benefits due to savings of non- electric fuels.

Assessing the Cost- Effectiveness of Beneficial Electrification Programs An August 2019 Electric Power Research Institute report titled" The Total Value Test: A Framework for Evaluating the Cost- Effectiveness of Efficient Electrification" presented a costeffectiveness test for evaluating beneficial electrification program. This test, named the Total Value Test( TVT), has its roots firmly in the established cost-effectiveness tests of the California Standard Practice Manual, with an emphasis on capturing the more comprehensive sets of benefits and costs associated with efficient electrification, while also being applicable to more traditional energy efficiency pursuits. The TVT couples the Societal Cost Test' s emphasis on valuing environmental externalities with the Total Resource Cost' s approach to discounting future cost and benefit streams, while explicitly accounting for impacts on participating customers and society at- large.

The EPRI report concludes that the Total Value Test is objective and not predisposed to favor any particular type of technology based on how it is powered or fueled. The EPRI report notes that" While no cost- effectiveness metric is perfect, and there is room for constructive debate on the usefulness and challenges of the TVT, it does represent an effort to advance the discourse on cost- effectiveness in the context of new forms of energy efficiency such as efficient electrification."
This EPRI report provides a useful framework for the assessment of the cost- effectiveness of beneficial electrification programs. The analytical framework presented in this report will be helpful to utilities, regulators, third party program administrators, policy makers, and nongovernment agencies that influence public policy in the energy and environmental spheres. i i r=, r;5 a r. s
Packet Pg. 433 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric

SUMMARY OF EQUATIONS AND GLOSSARY OF SYMBOLS
Basic Ec uations
Participant Test

NPVP BP - CP
NPVavp = ( BP- CP)/ P BCRP
BP/ CP
DPP min jsuch that Bj > Cj
Ratepayer Impact Measure Test
LRIIZIM = ( CRIM - BRIM)/ E
FRIIZIM = ( CRIM - BRIM)/ E for t= 1
ARIIZIMt = FRIIZIM for t= 1
CRIMt- BRIMt)/ Et for t= 2,..., N
NPVRIM = BRIM - CRIM
BCRRIM = BRIM/ CRIM
Total Resource Cost Test
NPVTRC = BTRC- CTRC
BCRTRC = BTRC/ CTRC

LCTRC LCRC/ IMP
Program Administrator Cost Test
NPVpa Bpa- Cpa
BCRpa Bpa/ Cpa
LCpa LCpa/ IMP
Benefits and Costs
Participant Test
Bp _
BRt+ TCt + INCt + ABat+ PACat
t- 1 ( 1 + d)`-
1 Li (1 + d)`-
1 N
PCt+ B t
p (
1 + d)
t- i
r. r. r= r,:. r= a s r
Packet Pg. 434 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Ratepayer Impact Measure Test
B _
UACt+ RGt + UACat
RIM— L1 ( 1 + d)`-
1 t- 1( 1 + d)`-
1 NN
UICt + RLt + PRCt + INCt RLat
CRi` t=
1 + d) ci1 + d) ci
r=1 t=i
E._ '
Ec
1( 1 + d)
ti
Total Resource Cost Test N
UACt+
T Ct ' UACat+ PACat BTRC=
t- 1( 1 + d)
t1
t_ 1 ( 1 + d)
t1
N
PRCt+ PCNt + UI Ct CTRC=
t=1 ( 1 + d)
tN
PRCt+ PCNt - TCt
LTRC=
r= 1 ( 1 + d)
tN
DEN ) or (ODN where I = eak eriod
IMP=
L
i1
c cc
r=
1 1 + d)
tProgram Administrator Cost Test N
UACt UACat
Bpa (
1 + d)
t- +
1 + d)
tCpa N
PRCt + INCt + UICt
1 + d)
tN
PRCt + INCt
LCPA
1 + d) t1
r=1
fkl5l5r 5ii ii. r;5
aS
Packet Pg. 435 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric

GLOSSARY OF SYMBOLS
Abat Avoided bill reductions on bill from alternate fuel in year t AC:Dit Rate charged for demand in costing period i in year t AC:Eit Rate charged for energy in costing period i in year t ARIRIM Stream of cumulative annual revenue impacts ofthe program per unit of energy, demand, or per customer. Note that the terms in the ARI formula are not discounted, thus they are the nominal cumulative revenue impacts. Discounted cumulative revenue impacts may be calculated and submitted ifthey are indicated as such. Note also that the sum of the discounted stream of cumulative revenue impacts does not equal the LRIRIM.

BCRp Benefit- cost ratio to participants
BCRRIM Benefit- cost ratio for rate levels
BCRTRC Benefit- cost ratio of total benefits and costs of for the total resource BCRpa Benefit- cost ratio of program administrator and utility costs BIt Bill increases in year t
Bj Cumulative benefits to participants in yearj
Bp Benefit to participants
BRIM Benefits to rate levels or customer bills
BRt Bill reductions in year t
BTRC Benefits of the program
Bpa Benefits of the program
Cj Cumulative costs to participants in year i
Cp Costs to participants
CRIM Costs to rate levels or customer bills
CTRC Costs of the program
Cpa Costs of the program
D Discount rate
4Dgit Reduction in gross billing demand in costing period i in year t 4Dnit Reduction in net demand in costing period i in year t DPp Discounted payback in years
E Discounted stream of system energy sales-( kWh or therms) or demand sales kW) or first- year customers
4Egit Reduction in gross energy use in costing period i in year t 4Enit Reduction in net energy use in costing period i in year t Et System sales in kWh, kW or therms in year t or first year customers FRIIZIM First-year revenue impact of the program per unit of energy, demand, or per customer.

IMP Total discounted load impacts of the program
INCt Incentives paid to the participant by the sponsoring utility in year t First year in which cumulative benefits are> cumulative costs.

Kit 1 when 4EGit or 4DGit is positive( a reduction) in costing period i in year t, and zero otherwise
i i r=, r;5 a r.

Packet Pg. 436 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric LCRC Total resource costs used for levelizing
LCTRC Levelized cost per unit of the total cost of the resource LCPA Total Program Administrator costs used for levelizing Lcpa Levelized cost per unit of program administrator cost of the resource LRIRIM Lifecycle revenue impact of the program per unit of energy ( kWh or therm) or demand( kW)- the one- time change in rates- or per customer- the changein customer bills over the life of the program.

MC: Dit Marginal cost of demand in costing period i in year t MC: Eit Marginal cost of energy in costing period i in year t NPVavp Net present value to the average participant
NPVP Net present value to all participants
NPVRIM Net present value levels
NPVTRC Net present value of total costs of the resource NPVpa Net present value of program administrator costs
OBIt Other bill increases (i.e., customer charges, standby rates) OBRt Other bill reductions or avoided bill payments ( e. g., customer charges, standby rates).

P Number of program participants
PACat Participant avoided costs in year t for alternate fuel devices PCt Participant costs in year t to include:

Initial capital costs, including sales tax
Ongoing operation and maintenance costs
Removal costs, less salvage value
Value of the customer' s time in arranging for installation, if significant PRCt Program Administrator program costs in year t
PCN Net Participant Costs
RGt Revenue gain from increased sales in year t
RLat Revenue loss from avoided bill payments for alternate fuel in year t (i.e., device not chosen in a fuel substitution program)
RLt Revenue loss from reduced sales in year t
TCt Tax credits in year t
UACat Utility avoided supply costs for the alternate fuel in year t UACt Utility avoided supply costs in year t
PAt Program Administrator costs in year t
UICt Utility increased supply costs in year t
r. r. r= r,:, r;5 a r:.

Packet Pg. 437 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric

10. 4 APPENDIX D: IRP CUSTOMER SURVEY AND SURVEY RESULTS r i .''' ,
Y
J
111
1 i% j
m
r
mi wu -
u,,,''
r i' l /
io ti. , a l,
ri"! i ri'I/ ,
s, i
riioir/, ;,' x ,/
ti: a. . ii . a .... I. ., .. J/ io i l,h'i 7Y , l, 1. / yt %%%
m n
I I
i

F, , ,,
1) Are you a Redding Electric Utility ( REU) customer?
Yes
No
2) Please rank the following in terms of importance with respect to your electrical service from REU, where 1" is the most important and " 3" is the least important:

Low electric bill
Reducing carbon footprint
Electric reliability
3) The State of California mandated electric utilities to have 50% of their energy provided by renewable resources by 2030 and reduce their greenhouse gas emissions 40% below 1990 levels by 2030. Do you feel REU should:

Meet the required mandates
Exceed the required mandates
Other: please provide comments
Comment:
r.5r.5r 5r,: ilr, r 5 a 71.

Packet Pg. 438 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric 4) Renewable and carbon- free electricity may cost more than other forms of electricity. Their costs are coming down, but the future is unknown. If there is an additional cost, how much more would you be willing to pay for renewable, carbon- free electricity? Don' t know
UptoS% ofmybill
Upto10% ofmybill
More than 10% of my bill
I don' t want to pay extra

IIII IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII Inside Redding' s city limits
Inside California
Out of State
No preference
6) Choose the top three ( 3) future energy resources you prefer:

No preference
Energy efficiency
Biomass ( energy from burning plants)
Digester gas ( energy from organic waste— livestock, manure, food) Geothermal ( energy from earth' s heat)
Hydroelectric ( energyfrom water—dam or run of river)
Landfill gas ( energy from landfill waste)
Natural gas power plant
Solar( energy from sun)
Tidal ( energy from ocean)
Wind ( energy from wind—wind turbines)
r.,: c. r„ a
Packet Pg. 439 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric 7) Which of the following options do you prefer for technologies such as energy efficiency, electric vehicles, advanced meters, new renewables, etc.?
Be an early adopter of new technology
Wait for the new technology to be common practice
Wait until certain technology is mandated by law
No preference
8) REU is required to have programs that save energy. Please rank the following four (4) categories on where you think REU should focus its efforts:

Commercial energy efficiency- most cost- effective
Residential energy efficiency- help most customers
Low- income customers- most in need
Least expensive mix that meets the mandated by law
9) How did you hear about this survey?
Facebook
Flyer in the mail
Friend/ Family/ Spouse
Website
Other( Please List)

I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I Thank you for participating in the IRP survey; your feedback will help shape REU' s energy future. The survey results will be posted on our dedicated website r rr.,«« r.« r` i« and will also be shared at our next IRP Public Workshop scheduled in June 2018. If you have additional questions or concerns, feel free t0 2—CTtaII II„ I( 1iv a uuvvi. ui, r°r,.
fklilir ii i. r a
Packet Pg. 440 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric 00/// f
if
f
a ra n P'' U r
rrrrrrrrrrr ,.

NNNN ,
I, a l lla
1, :

W
A s
o i,,
1 r,,,
r
p i,%l i <., f,f//////,/////% r w i a
e
lu,
u
a ,. V f I I 1 I 1 IJ :
ao ti
Il tt tt `,. i
iMr q G
p.

I /// ..,
Y., , /„ . I i i
j..i,
u&f I '.-
Ir i . Ru, R flfiW. l „ , , . i '
A i.
x", ax Il w, I I IIIIIIII ;
w;
n I Illlf i
ry
d
r,:
p"
r
w.
i°.

Packet Pg. 441 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric

10. 5 APPENDIX E: DSM- IRP MEASURE RESULTS
JJ J J J J I r
I I , .. , .,. ,, I
I, II II . I , I , ,. , I , ,., I 1, ! 1 I ,.,. l l, l,.,.1 I , ,. .

AC Pkg Unit-< 5 Tons( 55kBtuh)-
15 SEER
10 Ton 3, 817 G, UI: p G7I 15
AC Split Unit-< 5 Tons( 55
kBtuh)- 15 SEER- ER
3 Ton 2, 235 1., 7C U Gi" C 15
AC S lit Unit-< 5 Tons 55
kBtuh)- 15 SEER- ROB
3 Ton 1, 583 1.,: p G° 7I 15
Add Insulation R8 to R38 31 1000 Sq. Ft. ( 1. I, I1. I p8,° 71!: r G f': r 20 Ceiling insulation, increase to R40 1000 Sq. Ft. $ 399, 870 C C, G' rC C C 2p 38 Ceiling insulation, R- 11 addition 2 1000 Sq. Ft. 80 1 G f C C 20 Ceiling insulation, R- 19 addition 37 1000 Sq. Ft. 3, 731 88° C° 20 Ceiling insulation, R- 30 addition 46 1000 Sq. Ft. (: 1.,° 7°7: 1. C, 1 UC C° 20 Commercial Custom Rebate1 Project r: p, 1 U: 1. C, BU G° 7I 15 HVAC FY19
Commercial Lighting Rebate FY
1 Program 843, 781 ( C C C,' r° 7 G' r° 7 10
20- Exterior
Commercial Lighting Rebate
1 Program $ 2, 250, 118 (: p, G: p G, GB: p r: p° 7 11
FY20- Interior
CommercialSolarStorage 1 Building 1, 339, 951 ( 1,° 7, C° 7C fr1C 30 Commercial SolarTrack storage 1 Building 3, 406, 437 (, U: pB, 188 GI': r 30 Commercial SolarTrack 1 Building 3, 624, 294 (, U: pB, 188 GI': r 30 CommercialSolar 1 Building 1, 364, 442 ( 1, 1. i71, 1 G fr1: 1. 30 Ductless mini- split air
conditioner, 19 SEER( after 12 Ton p, G fB p U' r' r, G C 15 1/ 1/ 15)
Ductless mini- split heat pump,
4 Ton 349 B GC G f 15
15 SEER( after 1/ 1/ 15)
Ductless mini- split heat pump,
15 Ton 5, 560 C, I7 GU° 15
16 SEER( after 1/ 1/ 15)- ER
Ductless mini- split heat pump,
46 Ton 4, 350 1. U, 8i"C G f 15
16 SEER( after 1/ 1/ 15)- ROB
ENERGY STAR ceiling fan 2 Ceiling Fan 403 C: p G 1 C 10 ENERGY STAR HP water heater,
50 gal., located in 1 Water Heater 765 1., 1! r GUI 10
garage/ basement
ENERGY STAR HP water heater,
1 Water Heater 232 IBI GU° 10
50 gal., space htg- elec
ENERGY STAR HP water heater,
80 gal., located in 1 Water Heater 611 1., U8 GU° 10
garage/ basement
ENERGY STAR HP water heater,
Z Water Heater (: p I
80 gal., space htg- elec

1., r f G GU 10
Energy Star LED Bulb A19 633 Bulb 21, 520 1!': r,° 7: p8 G: p° 15 r.5r.5r;5ri: ilrx 5 a 71;
Packet Pg. 442 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Energy Star LED Bulb B10 144 Bulb 3, 227 p, GB° G: p° 15 Energy Star LED Bulb BR30 125 Bulb 4, 250 1 G': r G: p° 15 Energy Star LED Bulb G25 106 Bulb 3, 604 p,
CC I G: p° 15
Energy Star Refrigerator 40 Refrigerator 3, 150 pl°
G U 14
Energy Star Refrigerator- CEE
3 Refrigerator 420 7 G U 14
Level II
Energy Star Refrigerator- CEE
1 Refrigerator 199 1 C': r G: p° 14
Level III
ENERGY STAR room air
conditioner, 14, 000 to 19, 9991 Room A/C 56 I':r G 1: 1. 9 Btuh
Heat pump, 15 SEER, 8.4 HSPF
Z1 Ton 8, 600 8, 1 I':r GU° 15
after 1/ 1/ 15)- ER
Heat pump, 15 SEER, 8.4 HSPF
93 Ton 14, 428 1°7 C' r' r, G f 15
after 1/ 1/ 15)- ROB
Heat pump, 16 SEER, 8.4 HSPF
10 Ton 3, 693CC I GU° 15
after 1/ 1/ 15)- ER
Heat pump, 16 SEER, 8.4 HSPF
61 Ton 8, 223 1.: p,C BC G f 15
after 1/ 1/ 15)- ROB
Home Energy Reports Existing1 Building 14 1.: 1. 8
1 Multi- Family
Home Energy Reports Existing1 Building 20 1 C f
1 Single- Family
Home Energy Reports New
Construction- Multi- Family
1 Building6 r 1 C 1
Home Energy Reports New rv
Construction- Single- Family
1 Building9 8 p7 1
HP Pkg Unit-<5 Tons( 55 kBtuh)-
15 SEER 8.5 HSPF
3 Ton 588C BU G7I 15
HP Pkg Unit5 Tons( 55- 64
5 Ton 1, 171 i7G f G° 7I 15
kBtuh)- 15 SEER 8.5 HSPF
HP Split Unit-<5 Tons( 55 rv
kBtuh)- 15 SEER
9 HSPF
4 Ton 2, 657 p, G7 G GC C 15
Package System, 14.5 SEER, 12
429 Ton 108, 374 ( 1. C,! r8° G C 15
EER or Greater
Residential Solar rooftop1 Building 19, 457 pB,: pI7 GI': r 30 Residential Solar rooftopg
rv
r
storage
1 Buildin 9, 852 pB,: pI7 30
Shade Trees FY20 947 Tree 100, 894 ( 1. U8, IC': r Gf I 20 Smart Power Strip 30 Power Strip 2, 343 p8: p BU, 5
Split- system air conditioner, 15
SEER, 12.5 EER( after 1/ 1/ 15)- 231 Ton I, 1!
r 1',
G 1: 1. G C 15
ROB
Split- system air conditioner, 15
68 Ton 7, 116 1.: p, 1:p
SEER, 12.5 EER( after 1/ 1/ 15)- ER 1 1 15
Split- system airconditioner, 16
173 Ton C, IB 1!: r, IB G C 15
SEER, 13 EER( after 1/ 1/ 15)- ROB
Split- system air conditioner, 16
78 Ton 7, 826 1 G,
C UB GUB 15
SEER, 13 EER( after 1/ 1/ 15)- ER
Split- system air conditioner, 17
3 Ton pUC p° 7' r, G C 15
SEER, 13 EER( after 1/ 1/ 15)
r.5r.5r,5ri: ilrx;5
a 7fS
Packet Pg. 443 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Split- system air conditioner, 18
11 Ton G: pU
SEER, 13 EER( after 1/ 1/ 15)- ROB 1 1, 1 p
G C 15
Split- system air conditioner, 18
SEER, 13 EER( after 1/ 1/ 15)- ER
14 Ton r': r 1.,C IU G C 15
Split- system air conditioner, 19
3 Ton 438I G G 1 G 15
SEER, 14 EER( after 1/ 1/ 15)
Variable speed residential pool
Z8 pump 25, 305 pI, I' r 7': r 10
pump
Whole house fan 14
Fan( 2, 000
6, 042 1: 1., i r' r' Cr 20
cfm)
Wi- Fi Enabled Thermostat 241 1000 Sq. Ft. $ 83, 969 p: p,U 1 G 1 UC 11 Window Replacement Energy
1 1000 Sq. Ft. rUI, 1, I' r, p88, 2p
Efficient Windows
ECM BLOWER MOTOR7 Motor 246 1.,I G
p 1. 10
EFFICIENT FAN CONTROLLER 56
Co troller
4, 086 C, IU': r
p 1. 10
FY20- Electrification- Installation
of Single Head Mini Split Heat1 Program 32, 349 18, 662 66 20 Pump
Heat Pump Water Heater
HPWH 1, 552
replacingelectricheater
p l 10

HOT WATER FLOW RESTRICTOR
FAUCET RESTRICTOR ELECTRIC 23 Restrictor 2, 816 1.,! r8: 1. pU4 10 WH ( 2)

HOT WATER FLOW RESTRICTOR
HAND- HELD LOW FLOW 38 Restrictor 550 1.,: p pU4 10
SHOWERHEAD ELECTRIC WH( 2)

HOT WATER FLOW RESTRICTOR
LOW FLOW SHOWERHEAD9 Restrictor 226 p° 7: p pU4 10

ELECTRIC WH
Installation of Single Head Mini
Head 23, 444 pC,° 7': r
p 1. 20
Split Heat Pump
LED A- Lamp, 13W 4, 638 Bulb 58, 240 C,: p: p
p 1: p 15
LED A- Lamp, 9W 44 Bulb 713 rC U
p 1: 1. 16
LED NIGHT LIGHTS 1, 301 Bulb 42, 027 p": r, I1°7
p 1: p 15
LED Screw In BR 213 Bulb 3, 089 p,C 1 G
p 1: p 15
LED Screw In Candelabra 717 Bulb 6, 477 C,'
r f
p 1: p 15
POWER STRIP, TIER2
power Strip 155B G 1° 7: 1. 5

ADVANCED

REFRIGERANT CHARGE W/ COIL
3 Cleaning 180 G' rl, 1° 7' r, 5
CLEANING5 TON

REFRIGERANT CHARGE W/ COIL
118 Cleaning C,
C
4 1. U, I8 1° 7': r 5
CLEANING,3 TON

REFRIGERANT CHARGE W/ COIL
Z3 Cleaning 82 p, BU: p 1° 7': r 5
CLEANING,4 TON

REFRIGERATOR REPLACEMENT
31 Refrigerator ( 1.: p, i"7C G, GI: p
p 1!: r 14
19 CUBIC FOOT AND BELOW( 2)

REFRIGERATOR REPLACEMENT
34 Refrigerator (: p: 1., G: p':
r G, I7U
p 1!: r 14
OVER 19 CUBIC FOOT( 2)
Residential Energy Discount1 Program0 8f':r, If':r8 01
r.5r.5r,5ri: ilrx
5 a77
Packet Pg. 444 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric

WATER HEATER BLANKET,
5 HPWH 1, 321 8:p1
ELECTRIC WH 1 p 1: 1. 15
Wi- Fi Enabled SMART
173 Thermostat ( G: 1.,! rIG 1.: p, UI7
p 1 G 11

THERMOSTAT
Window Replacement3 1000 Sq. Ft. (: p° 7: p' r' r, 1 I GIU, p 1 G, 20
All- Electric New Home 15 SEER
1 Home 11, 656 5, 833 153 20
HP 3- tons
All- Electric New Home 16 SEER
1 Home 11, 225 5, 798 152 20
HP 3- tons
All- Electric New Home 17 SEER
1 Home 11, 202 5, 498 142 20
HP 3- tons
All- Electric New Home 18 SEER
1 Home 11, 068 5, 258 133 20
HP 3- tons
Class IV Forklift1 Forklift 43, 829 15, 810 145 10
ClassV Forklift1 Forklift 48, 444 17, 556 147 10
DHW Electrification to Baseline
Fuel Substitution- Gas to ER1 Water Heater ( i:p G 3, 473 1, 325 10 Water Heater
DHW Electrification to Baseline
Fuel Substitution- Gas to ER1 Water Heater (I I 2, 956 1, 325 10 Water Heater- MF
DHW Full Electrification- Gas to
1 Water Heater $ 1, 201 1, 537 209 10
HP Water Heater
DHW Full Electrification- Gas to
1 Water Heater $ 1, 244 1, 120 166 10
HP Water Heater- MF
Ebike Bike Share per bike Light
1 E- Bike 1., U8° 62 395
Duty
Ebike Business per bike Light
1 E- Bike 1.,' r': r 32 295
Duty
Ebike Personal per bike Light
1 E- Bike 1., 8: 1. I 9 285
Duty
Electric Airport Bag Tractor1 Unit 1.,
C B: p 36, 136 6, 103 10
Electric Airport Belt Loader1 Unit 16, 897 5, 559 116 10 Electric Airport Pushback
1 Unit p,: pC 24, 638 1, 422 10
Tractor
Electrification- Average Gas and
1 Ton 299 706 90 15
A/C to Packaged HP- Grocery
Electrification- Average Gas and
A/C to Packaged HP- Lodging1 Ton 438 470 65 15
Hotel
Electrification- Average Gas and
A/C to Packaged HP- Lodging1 Ton 866 296 15
Motel
Electrification- Average Gas and
A/C to Packaged HP- Office1 Ton 1. I 1: p': r 1! rC 15 Large
Electrification- Average Gas and
A/C to Packaged HP- Office1 Ton 112 i C 15
Small
Electrification- Average Gas and
A/C to Packaged HP- Restaurant1 Ton 728 303 57 15
Fast- Food
r.5r.5r 5ri: ilrx;5
a7
Packet Pg. 445 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Electrification- Average Gas and
A/C to Packaged HP- Restaurant1 Ton 384
r f p: 1. 15
Sit- Down
Electrification- Average Gas and
A/C to Packaged HP- Retail1 Ton 239 1 1 U GC 15
Large
Electrification- Average Gas and
A/C to Packaged HP- Retail1 Ton 449 118 34 15
Small
Electrification- Average Gas and
A/C to Packaged HP- Storage1 Ton 632 578 98 15
Conditioned
Gas Clothes Dryer to Electric
1 Dryer 87:':r 884 4, 175 16
Resistance
Gas Clothes Dryer to Electric
1 Dryer 8i f':r 884 4, 175 16
Resistance- MF
Gas Clothes Dryer to HP Dryer1 Dryer 1. UU 474 839 12
Gas Clothes Dryer to HP Dryer1 Dryer 1. UU 474 839 12
MF
Gas to Electric Resistance Oven1 Oven 31 127 409 20
Gas to Electric Resistance Oven1 Oven 18 76 409 20
MF
Gas to Electric Resistance Stove1 Stove 42 381 478 20
Gas to Electric Resistance Stove1 Stove 25 229 478 20
MF
HP DHW Grocery1 Water Heater (: 1., I7I 8, 107 190 10
HP DHW Hotel1 Water Heater (, C: p 13, 208 208 10
HP DHW Motel1 Water Heater (: 1., G8i 6, 180 191 10
HP DHW Office Large1 Water Heater (: 1.,
C U: p 4, 894 206 10
HP DHW Office Small1 Water Heater 342 1, 466 166 10
HP DHW Retail Single Story
1 Water Heater ( f':r: pl 3, 472 164 10
Large
HP DHW Retail Small1 Water Heater 319 1, 530 171 10
HP Electrification to Baseline HP
Fuel Substitution- Gas& A/C to3 Ton 3, 196 2, 547 176 15 15 SEER/ 8.7 HSPF HP
HP Electrification to Baseline HP
Fuel Substitution- Gas& A/C to2 Ton 1, 554 1, 428 193 15 15 SEER/ 8.7 HSPF HP- MF
HP Full Electrification- Gas&
3 Ton 3, 320 2, 147 139 15
A/C to 16 SEER 9.0 HSPF HP
HP Full Electrification- Gas&
Z Ton 1, 513 1, 296 168 15
A/C to 16 SEER 9.0 HSPF HP- MF
HP Full Electrification- Gas&
3 Ton 3, 423 1, 760 108 15
A/C to 17 SEER 9.4 HSPF HP
HP Full Electrification- Gas&
Z Ton 1, 476 1, 161 144 15
A/C to 17 SEER 9.4 HSPF HP- MF
HP Full Electrification- Gas&
3 Ton 3, 410 1, 439 84 15
A/C to 18 SEER 9.7 HSPF HP
r.5r.5r 5ri: ilrx;5
a 7t
Packet Pg. 446 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric HP Full Electrification- Gas&
Z Ton 1, 389 1, 054 127 15
A/C to 18 SEER 9.7 HSPF HP- MF
Large Light Duty Vehicle- PHEV1 Vehicle 6, 895 3, 573 168 12 Large Light Duty Vehicle- PHEV1 Vehicle 1, 426 4, 076 191 12 COM
Light Duty Truck- BEV1 Vehicle p" r° 7°7°7 5, 060 138 12 Light Duty Truck- BEV- COM1 Vehicle f':r, I:1.: 1. 5, 772 158 12 Medium Light Duty Vehicle- BEV1 Vehicle 1., U4C 3, 869 115 12 Medium Light Duty Vehicle- BEV1 Vehicle C,
B GU 4, 413 131 12
COM
Medium Light Duty Vehicle1 Vehicle 2, 134 2, 711 152 12 PHEV
Medium Light Duty Vehicle1 Vehicle p, 8: 1. i 3, 093 173 12

PHEV- COM
Small Light Duty Vehicle- BEV1 Vehicle 9, 106 3, 130 122 12 Small Light Duty Vehicle- BEV1 Vehicle 1, 029 3, 570 139 12 COM
Small Light Duty Vehicle- PHEV1 Vehicle 2, 547 2, 056 146 12 Small Light Duty Vehicle- PHEV1 Vehicle 1., GC 4 2, 345 167 12 COM
LED Street Light Replacement1 Program pU!': r, UI: 1. 91, 637 183 10 r.5r.5r 5ri: ilr, r;5
a 1
Packet Pg. 447 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric

10. 6 APPENDIX F: 2021 POTENTIAL FORECAST STUDY GOAL COMPARISON Beginning in 2013 and every four years thereafter, Redding is required to develop an Energy Efficiency Potential Forecast ( Forecast) study, which provides a 10- year projection of achievable energy efficiency savings. The results of Redding' s 2017 Forecast were used by the California Energy Commission ( CEC) to establish energy efficiency targets related to the state' s efforts to double energy efficiency savings by 2030 under SB 350. These targets were subsequently incorporated into Redding' s 2019 Integrated Resource Plan and approved by Redding City Council and the California Energy Commission. In the updated 2021 Forecast, staff identified significantly less potential for cost-effective energy efficiency programs in Redding due to updated avoided costs, market saturation, and increasing building code standards. Staff recommended lowering the targets to match the cost- effective energy efficiency potential identified in the updated Forecast. On March 2, 2021, City Council approved the 2021 Forecast and new goals.

Methods for reporting electrification program savings relative to the energy efficiency goals are currently under development by California Publicly Owned Utilities. However, as shown in Figure 10- 1, staff estimates that the recommended plan as presented in Section 8 will fall short of the council adopted energy efficiency goals. Nevertheless, as described in Section 8, there is a sufficient budget to expand these programs if appropriate based on community needs and pending early success of the electrification programs. Once the quantification methodology has been developed, staff may return to Council with recommended changes to align the Energy Efficiency goals with the expected reportable energy savings.

II II" yl, ll d .. ^"^" ;' IIYYd II"`" '' IIV IId,!" II" YI. lu&' YilVll° i A\ d° i "° i llllll. l!"". d 6, I II°` d"°. IIYVd II;," a`" ° rrIV\\ CIIII" Yl. tt 1 % 1[ G G° f: C` C` r" f , > i' k l > G[ G rW 1
IrW l[ pWGf f ;•; G[ G;„' N
f, t`+€7 E7
f, E E
m
m
xxxxxxx, xxxx , xxxx
f, l E E) N, o 0000
000000000 n o n o noo
f, l) d l)
a« m wmo wmm mm m mm m m i 1 f) uo u uomimo
mwvvvvvvouvvvvvu f} dIEI
m,n,mnm w nm w
mmu
f.} f.} mummnuouFmunmu,n,um
l
f. f „„,,,,,,,,,,,,
f.} ,', ;
fll lfll,'i lfl I' lfl Y fllf`x lfl lfll`i lfl' 1 fl, if} lfl, if I I " x r (`')
i, l¢ 1`};/ i, 1' ir l l r: IIIIIIIIIIIIIIIIIIIIIIIIIIII i, ltl r111'};; i, r 11'] 91r, llf]' ^^ r^ r^ r^ r^ r^ r^ v(" f ltl F']/ 5 51` E7V r f, f,( 1f71' j r.5r.5r 5ri: ilr, r;5 a 1.

Packet Pg. 448 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric umuu u46! i a
ou „
r ,
w CITY OF REDDING
REPORT TO THE CITY COUNCIL r u u m m i
MEETING DATE: March 2, 2021 FROM: Daniel Beans, Director of ITEM NO. 4. 5( a) Electric Utility
APPROVED BY***
1 4/'
a ... °"
IL ai i l e i"s, L} ir c; to cti"cUtillity ry rp}a n, nt an e 2/ 2/ GJ21. dbeans@cityofredding. org btippin@cityofredding. org
SUBJECT: 4. 5( a)-- Authorization to submit Redding Electric Utility' s Energy Efficiency Potential Forecast Stud .

Recommendation
Authorize Redding Electric Utility ( REU) staff to submit the 2021 Energy Efficiency Potential Forecast to the California Energy Commission and approve the adjustment of REU' s energy efficiency goals to align with the forecasting study.

Fiscal Impact
There is no fiscal impact related to accepting this report.

Alternative Action
The City Council ( Council) could choose not to approve the report and provide further direction to staff.

Background/Analysis
Beginning in 2013 and every four years thereafter, Redding Electric Utility (REU) is required by the California Energy Commission ( CEC) to develop an Energy Efficiency Potential Forecast Study ( Forecast), which provides a 10- year proj ection of achievable energy efficiency savings.

REU staff submitted the required forecasts in March 2013 and March 2017 and the updated forecast is due in March 2021.

The results of REU' s 2017 Forecast were used by the CEC to establish energy efficiency targets related to the state' s efforts to double energy efficiency savings by 2030. These targets were incorporated into the 2019 City of Redding Integrated Resource Plan and approved by the Council and the CEC. The results of the new Forecast have identified significantly less potential for cost effective energy efficiency programs in Redding, and staff recommends updating the future energy efficiency goals to match the 2021 Forecast. It should be noted that the recommended goals do not achieve the Senate Bill ( SB) 350 targets that were assigned to REU Packet Pg. 449 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Report to Redding City Council February 22, 2021
Re: 4. 5( a)-- REU' s Energy Efficiency Potential Forecast Study Page 2 by the CEC. However, by statute, REU is required to commit to cost- effective energy efficiency, and the recommended goals more accurately quantify the cost- effective potential than the SB 350 targets.

The difference in cost effective energy efficiency potential can be attributed to three main factors:

The avoided cost of energy forecast was updated to align with current energy risk policies and methods, rather than using stipulated values that are based on PG& E avoided costs.

On an annual average basis, the updated avoided cost values are similar to the values from the 2019 Net Energy Metering 2. 0 ( NEM 2. 0) avoided cost study.

The rate of energy savings from REU' s commercial lighting program exceeded the potential identified in the 2017 Forecast due to high customer participation. This led to a reduction in potential for lighting projects in future years.

Changes in California Building Codes and standards have increased the baseline level of efficiency to which efficient alternatives are compared, making it harder to implement cost effective energy efficiency programs. REU currently includes an average of 5, 000 MWh per year of energy efficiency savings in the load forecast due to codes and standards. These savings occur absent of any utility programs.

Due to these changes, the results of the 2021 Forecast indicate that REU' s potential for costeffective energy efficiency programs is approximately one third of the potential identified in the 2017 Forecast. Staff' s recommended energy efficiency goals over the next ten years are listed in Table 1.

Table 1: Recommended Goals
Year 2021 Goals,
MWh
2022 1, 358
2023 1, 305
2024 1, 233
2025 1, 115
2026 922
2027 755
2028 581
2029 525
2030 439
2031 388
If authorized by the Council, staff will submit the CMUA Energy Efficiency Potential Forecasting Study to the CEC as required and incorporate the new goals into REU' s long term program planning efforts.

Council Priority/ City Manager Goals
Packet Pg. 450 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Report to Redding City Council February 22, 2021
Re: 4. 5( a)-- REU' s Energy Efficiency Potential Forecast Study Page 3 This agenda item is a routine operational item.

Attachments
CMUA Energy Efficiency Potential Forecasting Study
Recommendation Memo - 2021 Energy Efficiency Potential Forecast Study Results - R3 City of Redding Integrated Resource Plan ( Available Online) Packet Pg. 451 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric t mm. m m: t . 1
i ' .

Yr „, iN s c u r r
fi l i II
f s Redding Electric Utility
I° sIN' f6 GDS Associates, Inc.

I/ y"' f ll n February 5, 2021
I II n 2020 CMUA Energy Efficiency Potential Forecasting Study

INTRODUCTION
This memo provides Redding Electric Utility with the results of the California Municipal Utilities Association CMUA) Energy Efficiency ( EE) Potential Forecasting Study conducted in 2020 by GDS Associates, Inc. ( GDS).

The results described here are specific to the Redding service territory and account for unique characteristics of the service area, customer base, climate zone, economic conditions, and other relevant factors. This memo provides a summary of potential, and a description of the data provided in a detailed results spreadsheet file.

This potential study provides a roadmap for Redding Electric Utility as they develop strategies and programs for energy efficiency. The development of market potential estimates for a range of feasible measures is useful for program planning and modification purposes.

The City of Redding' s energy efficiency program target for the next 10 years( 2022 to 2031) is set at 8, 690 MWh.

This results in an average annual target of 0. 12 percent of total projected energy sales. Figure 1 provides the market potential for the residential and non- residential sectors, as well as the total incremental potential as a percentage of total sales for the 10- year period of 2022 to 2031.

FIGURE 1. NET INCREMENTAL MARKET POTENTIAL Y SECTOR ( MWH) AND PERCENT OF SALES a.,
m„,,
n,„
Nov0000000
a., t
I
a., ti,
00000000000 0
a. l'% „
A., l l l
0p0p mum Doo
r°""
r" 0p 0p0p mo
l l 1.:. l% ,,,
00 r v N
idqlpppppipppppipppppiipmmn
un osn xmn ea osmnnn ea
I
p°° os n nnonx nnmin xnen nnniro,
r
i'.} :: ::..

IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII' S OCY'' YT7' 0' ri ril"{C'' Q.'' 0' Iri IIIIIIIIIIIIIIIIIIIIIIIIIII Q. O"'' S OCI"' YT7' 0' ri ril"{C'' Q.'' 0' Iri r r r r r
ul¢ tral Vrocren7ero tral V¢ tero ti: al ras ra%¢ F I¢ tral Srales y
1 .. : I il/' 1 3F) F) F) ,) I I ' r.( f( ' , ,( U ' J I f i( 1 ' fll' tl ' I((, " IJI( iS( 1( 1 tlll(,<<! 1 ( li' li l,' IY71 W 4 uu yw
li,,% P IIW,°, u„ luu
i, , , .

Packet Pg. 452 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric I; il I; i l'/ Ill: i, 11,' i
a o u f If Q D' 6 O; rr e r r a7 0; 1I¢, i m r r¢, II^¢. Q r r r i, h¢. r r P; i r r ' i k a,(` Table 1 below includes the specific inputs used to create Figure 1. The annual energy and demand impacts are provided. The energy impacts are shown as a percentage offorecasted sector- level and total sales. Incremental annual savings range from 388 MWh to 1, 358 MWh, which corresponds to 0. 05% to 0. 19% offorecasting sales.

TA LE 1 NET INCREMENTAL MARKET POTENTIAL Y SECTOR— ENERGY AND DEMAND U W ,;%%/ ,' Ny 1J11 ° UlUpu°" Jl% 1 l U NN p u, R! r" p w . . . . ` u II II n u r, u, „ . i . I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I ifl ll6 a.` 1.' r h M r'' N16 Ih k l6 d h ll l.

II I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I...
1 , p0(G P, y, 1 u1r1 11 tr' 1, 358 1, 305 1, 233 1, 115 992 755 581 525 439 388 w 59 65 70 72 73 73 73 74 42 38
II I................................................................................................................................................................................................................................................................, IIVy IIIII
w
1 298 1, 240 1, 164 1, 043 919 681 508 451 397 350
a/)/ w , ii/iiiiiiiJiii ,,
uuu mi 1 K a ''
1 11111 IIIIU Q 0. 19°/ a 0. 18°/ a 0. 17°/ a 0. 16°/ a 0. 14°/a 0. 11°/ a 0. 08°/a 0. 07°/a 0. 06°/a 0. 05°/ a w w
IIII
Illl k f! e
o 02% 0. 02% 0. 02% 0. 02% 0. 02% 0. 02% 0. 02% 0. 02% 0. 01% 0. 01% I y, .

Illup w11 11 J
w
0 36°/a 0. 34°/ a 0. 32°/ a 0. 29°/ a 0. 25°/ a 0. 19°/ a 0. 14°/ a 0. 12°/ a 0. 11°/ a 0. 10°/a w w
i io i lllllG ii iii ii
lui Ilii l%/ p u' l l l 111,' 1 I ll 1// N ° 11111 li[ ll Upp N Nl N 1 1 N l w . I I i , I ,,. y V , ,. u , , , , p''" i n , u.,.. 1 j i. ,. , q N V r um' ihm Illiiii ihiYullllll u iu u uu illlu dlllllum w i ui 1691ulliltli wi llu i uullu lillwmihi i ulll ll 1 1 1 1 1 1 . 1 1 : 1 ' 1 1 1
205 194 180 161 142 110 87 77 66 58
w 1 1 1 1 1 1 1 1 1 1
II I................................................................................................................................................................................................................................................................, IIVy 204 193 179 160 142 110 86 77 66 58
a/)/ w , ii/iiiiiiiJiii ,,
At a glance, Redding Electric Utility' s results include:

A 2022- 2031 average annual gross savings target of 0. 18% of forecasted retail sales A 2022- 2031 average annual net savings target of 0. 12% of forecasted retail sales No claim of savings from codes and standards ( C& S)
ll;;xz; lf„ a;raiilla: arl 11' a:, r a,alhlf„, r
GDS has provided Redding with a detailed results file which includes the summary information described above, as well as additional detailed results. The results file includes the following information:
10- yr gross incremental and cumulative annual energy and demand savings 10- yr net incremental and cumulative annual energy and demand savings 20- yr cumulative annual technical, economic and market potential by sector—energy and demand 20- yr incremental annual market potential by sector—energy and demand 20- yr market potential by program
20- yr market potential by end- use
20- yr costs by program
Comprehensive measure mapping list
i! IIIIIII Vu' IIIIbG NdJ " II' MW,.....
yY
W Packet Pg. 453 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric i.y f ' d din
IC . l lll$'
Memo
From Long- Term Resources
To Energy Risk Committee
Titie Recommendation to Approve Energy Efficiency Potentiai Forecast Resuits Current Date 2/ 16/ 2021
Summarv
Beginning in 2013 and every four years thereafter, Redding is required to develop an Energy Efficiency Potentiai Forecast ( Forecast) study, which provides a 10- year projection of achievabie energy efficiency savings. Redding submitted the required forecasts in March 2013 and March 2017, and the updated forecast is due in March 2021. The resuits of Redding' s 2017 Forecast were used by the California Energy Commission CEC) to estabiish energy efficiency targets related to the state' s efforts to doubie energy efficiency savings by 2030. These targets were incorporated into Redding' s 2019 Integrated Resource Plan ( IRP) which was approved by Redding City Councii and the California Energy Commission.

The resuits of the 2021 potentiai forecast show a significant reduction in cost- effective energy efficiency potentiai between 2017 and 2021. These changes can be attributed to the foilowing:

Redding has studied and updated the avoided cost of energy forecast to align with the IRP rather than using stipulated values that are based on PG& E avoided costs. The new avoided cost is much lower and as a resuit, fewer energy efficiency measures are shown to be cost-effective. The updated avoided cost values are similar to the 2019 Net Energy Metering 2. 0 avoided cost study( NEM 2. 0).

Since 2017, Redding customers have pursued savings from the commerciai lighting program at a rate that exceeds the potentiai identified in 2017. This reduces the potentiai for lighting projects in future years.

Changes in California buiiding codes and standards have increased the baseline levei of efficiency to which efficient aiternatives are compared, making it harder to impiement cost- effective energy efficiency programs. REU currentiy inciudes an average of 5, 000 MWh per year of energy efficiency savings in the load forecast due to codes and standards. This savings occurs absent any utility programs.

Due to these changes, the resuits of the 2021 forecast indicate that Redding' s potentiai for cost- effective energy efficiency programs is approximately 1/ a of the potentiai identified in the 2017 Forecast. A comparison of the goais approved by the City Councii in the 2019 IRP vs the updated potentiai study is shown in Figure 1. The consuitant report that wiii be submitted to the CEC is attached in Appendix A.

G
1 Packet Pg. 454 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric i.y f ' d din
IC . l lll$'
Memo
mg m° ' ". mm n m° m mm"". v. m° m~ mm". n u tin: ti l" n m° mm mn r A . 1"• '.
s««
s««
z, s««
z,«««
s, s««
1,«««
s«( ,
zr zz zr z zr z zr zs zr z zr za zr z zr z< zr r zr i
IIIII fr a ly r av¢: 1 by C' a un il 2ttl1£3 ' IV rlt t E' at nti l 2ttl21 Staff recommends seeking approvai of the City Councii to submit the updated potentiai study to the CEC and adjusting Redding' s energy efficiency goals to match the updated study.

Background
The Ciean Energy and Poilution Reduction Act of 2015 ( SB 350) estabiished new ciean energy, ciean air, and greenhouse gas reduction goals. To support the state' s goal of doubling energy efficiency savings in electricity and naturai gas end uses by 2030, existing mandates were expanded to support SB 350 in the foilowing ways:

According to Pubiic Utilities Code § 9505, by March 15, 2013, and by March 15th every fourth year thereafter, Pubiiciy Owned Utilities ( POUs) shaii identify aii potentiaily achievabie cost- effective electricity efficiency savings and shaii estabiish annuai targets for energy efficiency savings and demand reduction for the next 10- year period. This is reported through the Energy Efficiency Potentiai Forecast ( Forecast) study and is traditionaily submitted with the POU' s Annual Energy Efficiency Report.

The California Energy Commission was directed to establish statewide targets to support the state' s goai to doubie energy efficiency savings by 2030. Furthermore, the resuits of the Forecast were used as the basis for targets estabiished by the CEC for each POU.

POUsl are required to submit an IRP that sets forth a pian to achieve the energy efficiency goais in SB 350 and must be approved by their respective boards by January 1, 2019, and submitted to the CEC by Apri130, 2019. This was approved by Redding City Councii ( Councii) in November 2018.

The 2017 Forecastresults served as the basis for the CEC' s POU annual energy efficiency savings target. Councii then approved to set Redding' s energy efficiency goais based on the targets set by CEC ( see Figure 2). 1 Per Public Utilities Code§ 9621, this applies to POUs with an average electrical demand exceeding 700 gigawatthours, based on a three- year average commencing January 1, 2013.

G
2 Packet Pg. 455 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric i.y f ' d din
IC . l lll$'
Memo
mg m°" ". mm n m° m mm`". 11". ll ll " n m° g& ti timmmg ll ll n v. mm m ti mmm r A
s««
A
rq
3, 5(( 1q4q
tl tl tl n, n,, n,
Q
p p ,, n, u
Qq
f f f
V
1, 5r r
m a"
aa
1,««« u
s««
zr as zr a zr aa zr a zr a< zr zr zr za zr zz zr z zr z zr zs zr z zr za zr z zr z< IIIIIIIIIIIIIIIIIIIIIIIIIII fru"Jc4I5 c4" J" JCu"JVf'&:.YJjl f.,u"JIATI' I( 1: "'" 01P1° P1° P1° P1° P1° P1° f.,Ef., c4C' f' L In coordination with the other California POUs, REU has been working ciosely with GDS Associates ( GDS) to develop the 2021 Forecast that more accurately reflects characteristics specific to Redding' s territory and conditions. The finai Forecast was submitted to REU in February 2021 and is inciuded as Attachment A to this document.

Evaluation Methodolo v
REU' s approach to evaluating energy efficiency and renewable energy programs has changed since the 2017 Forecast. Stakehoider feedback in the IRP Process was used to inform the potentiai study. To summarize, customer feedback received during the IRP process indicated the foilowing:
a) Redding customers want to keep their energy biiis as low as possibie by paying for the least expensive energy availabie so long as it maintains reliability.
b) While customers understand the importance of ineeting California environmentai mandates, they do not necessarily want to exceed them.
c) Customers generaily do not want to pay more for renewabie, carbon- free electricity that exceeds state mandates.

Those resuits were incorporated into the finai IRP report approved by Councii in November 2018 and the CEC in 2019. Since its approvai, REU has continued to use IRP as a guide for evaluating programs.

In addition to the IRP, the NEM 2. 0 study aiso prompted REU to consider how the costs of a program can affect both participating and non- participating customers. Councii estabiished a Solar Committee to recommend the highest defensibie credit rate that met the foilowing objectives:
a) Legaily defensibie
b) Fair for non- solar customers
G
3 Packet Pg. 456 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric i.y f ' d din
IC . l lll$'
Memo
c) A reasonabie return on investment for participating customers The Solar Committee recommended a solar credit rate that was fair to participating and non- participating customers and that was legaily defensibie. In December 2019, the Councii adopted the Solar Committee' s recommended $ 0. 0608/ kWh rate. REU studied the utility' s avoided cost rate using PowerSimm planning software to determine the avoided cost of energy for aii 8, 760 hours of the year for 20 years. On an annuai average, the resuits of this study reasonabiy match the avoided cost rate from the NEM 2. 0 study.

Potenrial Forecast Development
The Forecast modei was developed by GDS with input from REU' s Resources team. Resuits were developed based on Redding' s service area, customer base, climate zone, economic conditions, and other factors during the development of the Forecast. GDS aiso reviewed Redding' s current program offerings and evaluated them at a measure levei.

Forecast Assumptions
The modei considers the market saturation and increasingiy stringent buiiding codes that continue to add energy efficiency measures as the baseline, reducing the amount of incrementai energy savings Redding may ciaim in the Annuai Energy Efficiency reports. GDS and Resources worked ciosely to refine the appropriate criteria for the 2021 Forecast that wouid be practicai and achievabie. Resources used Redding' s IRP and NEM

2. 0 study as the guiding principie to develop the Forecast, inciuding:

Keeping the cost of energy as low as possibie while maintaining reliability Meet the minimum requirements of California environmentai mandates Use Redding' s avoided cost as a basis for the cost of energy rather than using stipulated costs that are higher than Redding' s true avoided cost.

Using this guide, Resources and GDS developed basic measure requirements for measures to be inciuded in the 10- year forecast. The analysis exciuded measures and programs that are pianned to be discontinued by the start of the forecast period in 2022, and measures that do not meet a Totai Resource Cost( TRC) of 1. 0. The TRC is a cost- benefit analysis test that is based on the cost of the program versus the utility' s avoided costs. It is a cost- effectiveness test used by neariy aii California utilities to evaluate the cost- effectiveness of a program or measure. In the future, Redding may choose to utilize a different cost- effectiveness test that better aligns with Redding' s stated goais.

A key component in the TRC is the avoided costs. In 2017, Redding used stipulated avoided cost to develop the Forecast. However, these avoided costs are significantly higher than Redding' s, causing many measures to appear more cost- effective than they are. To address this difference, Resources developed an avoided cost similar to the originai NEM 2. 0 study rate, which incorporated the foilowing costs components:

Transmission
Losses
Renewabie Attributes
Energy
Redding' s avoided cost was evaluated based on the costs of energy, RPS obiigation transmission, and distribution losses, and capacity. As a result, Redding' s avoided costs are 55% lower than the current version G
4 Packet Pg. 457 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric i.y f ' d din
IC . l lll$'
Memo
of the stipulated avoided cost. Using the updated avoided costs yieids resuits that are more appiicabie to the City of Redding.

Forecast Resuits
Once the modei assumptions were developed, Resources evaluated the resuits provided by GDS.

The resuits of the 2021 Forecast indicate that Redding' s energy efficiency potentiai has decreased by 65% from
the 2017 potentiai study. As seen in Tabie 1, Redding' s 2021 market potential is consistently lower than the 2017 resuits from 2022- 2027z, with an overaii reduction of 13, 000 MWh during that period. n n". mm n m° m mm
mW d W
i iii e ri eaIIII I I I I
I I"
I
I ° C i p
ia j, W
uuw. I I:'' M m . µ:"
m . i ( n . I I nd1,' i,K„ y
1 2022 3, 629 1, 358 4, 000 1,
000 2023 3, 439 1, 305 3, 000 1,
000 2024 3, 438 1, 233 3, 000 1,
000 2025 3, 352 1, 115 1 3, 000 1,
000 2026 3, 234 992 3, 000 1, 000 d? d?
b 2027 2, 695 755 3, 000 1,
000 Total 19, 787 6,
758 u¢ p' i19, 000 6, 000 u¢ p¢ p¢: p
iFigure 3shows thecurrent goais and theproposed goais based on the resuits of thepotentiai study.The originai goais are much higher because they were not based on Redding' sown avoided costs and misrepresented the amount of cost- effective energy savings in Redding. Tailoring the goais wiii provide Redding flexibility to develop and administer programs that meet the objectives set out in the IRP. It shouid be noted that the updated goais do not achieve the SB 350 Targets that were assigned to Redding by the California Energy Commission. However, by statute, Redding isrequired tocommit to cost-effective energy efficiency, and the recommended goais more accurately quantify the cost-effective potentiai than do the SB 350 Targets. mg m; ". mm n m° m mm"". v. m° m~ mm". n mm mm mm ti ti n A
A
s««
s««z,
s««
z,«««s,
s««
1,«««
s«( 1 J 1 1 1 l l I
I zt zz zt z zt z zt zs zt z zt za zt z zt z< zt t zt
a f a l y r av¢: 1 by C' a un il 2ttl1£ 3 FZ arr rrn. n¢: 1¢ 1 fr a ly zThe period of time in which both Forecasts
overlap. G
Packet Pg. 458 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric i.y f ' d din
IC . l lll$'
Memo
Conclusion and Next Stens
The Resources team recommends the City approve the potentiai forecast resuits and the recommended energy savings goais that wiii be submitted to the CEC. Once approved, REU staff wiii:
1) File the approved Forecast in the 2021 SB 1037 Energy Efficiency Report submitted by March 15, 2021. 2) Develop a Demand- Side Management Integrated Resource Pian ( DSM- IRP) that uses the Forecast resuits to develop a pian to transition from current energy efficiency offerings to programs that align with the updated goais while meeting the needs of the community.

G
6 Packet Pg. 459 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric 1 U u' V' V' u"' uVVVVVVVV uuiu P1!lfn Nly y JJ j
u
III i °°'' tll" ,, j/ ! 9
oo yui I N ' r ' 1
l'%,,,...; f
l
r o/% illl',
i
I f
i/r/' r))',! l ll i
r
piiiii I , / ' '-
i r%' iii%f//j%/ l) , II h; % ri„ „ ,
iii
iyi llf iii%
i
i f 1%.
i' ai i
i/Ol,%////%/! i/% I
IIfrIII / i; , j, J//Oi
ilp
v), 5% lrl ,,,, ii ,/%/
r,, l011b f i! l
p
r / / f
o,
I I
m /'
9 „, '
i . ..:. , .; r I .:..
r,,,, , , ? ii i,,,, ... j/ / i ,// ; r, .
1,,,.
i i,,, ::: . i .,,,, ......
a 1,.: j// i`/ „,. / ..:. ,,,, .. S,,
i J
i ii j i ;°; ........... , J
r
f////// f
11lI1 l%Ifl/' ll.' /lllii „. / i;;,,;,,, .
i, r,,. .. J/ , :... 1j/1/IJJI/J . fr / „ j
r a r m m m.: w „, , I ir% i ii.. i,rvi/ ii %, i// f i /, i , i/ i/
j////%;,, r%% i, ,,,,,,,
i ; r j/
f;/ / , i/f// , ,
u w, ., ;,
k li/i
irJ' Niyuti... .:: wi ri f' I..
l////, :/%
oy/// i/ .:/
n o , l ,,,/,,,/ t ,, / ii f/, , / i ,/,
r t// fi/ ii!:
i / io/// / il l i, ir j%l!1/ i r
N ti„ ..
a i 7y
f/ ,//,// f /%/,;/
i/,/
l/ yI IIII! I'
I
i
I
I INIG
I
i
i j f
i,,/ i,
f
r:;
c;
f
a
a
i T' ,
IF I' IG° i K IF IG I' IF IG I A° fl
I .' t 11 T' IH
i
f, r ec_. a
Illllllllllllllllllllllllllllllllllllllllllllllllllliiii...

Packet Pg. 460 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric ii° .., ii°
Acronyms, Abbreviations, and Definitions List.................................................................................... AL- 1 IRPProject Partners...................................................................................................................................... PP- 1

1. 0 Executive Summary............................................................................................................................ 1- 1

1. 1 Summary of the 20- Year Resource Plan..................................................................................... 1- 5

2. 0 Purpose and Background................................................................................................................. 2- 1

2. 1 Overview of the Integrated Resource Planning Process...................................................... 2- 1

2. 2 Methodology.......................................................................................................................................... 2- 2

2. 3 State Laws, Policy, and Regulations............................................................................................. 2- 2

2. 4 Other Relevant State Legislation and Executive Orders...................................................... 2- 9

2. 5 Federal Energy Legislation............................................................................................................ 2- 14

2. 6 Public Stakeholder Process............................................................................................................ 2- 15

3. 0 Existing Resources and System Description.............................................................................. 3- 1

3. 1 Generating Facilities........................................................................................................................... 3- 4

3. 2 Renewable Energy Resources......................................................................................................... 3- 4

3. 3 Contractual Purchases....................................................................................................................... 3- 6

3. 4 Transmission Assets and Adequacy............................................................................................. 3- 8

3. 5 Distribution Assets and Adequacy.............................................................................................. 3- 12

3. 6 Natural Gas Commodity, Transportation and Storage....................................................... 3- 16

3. 7 Wholesale Energy Trading............................................................................................................. 3- 17

4.0 Energy and Demand Forecast......................................................................................................... 4- 1

4. 1 Historical Energy Use and Peak Demand................................................................................... 4- 1

4. 2 Forecast Methodology and Assumptions................................................................................... 4- 3

4. 3 Forecast Results.................................................................................................................................... 4- 6

4. 4 Comparison to CEC Forecast........................................................................................................... 4- 7

5. 0 Customer Programs, Energy Efficiency and Demand Response Resources................... 5- 1

5. 1 Energy Efficiency Program Background.................................................................................... 5- 1

5. 2 Current Energy Efficiency Initiatives........................................................................................... 5- 2

5. 3 Commercial Rebates........................................................................................................................... 5- 4

5. 4 Additional Programs........................................................................................................................... 5- 4

5. 5 Demand Response Programs.......................................................................................................... 5- 6

5. 6 Transportation Electrification........................................................................................................ 5- 8

6.0 The Need for Additional Resources and Resource Options................................................. 6- 1

6. 1 Existing System Capacity Balance................................................................................................. 6- 1

6. 2 Existing System Scenario Energy Requirements and Renewable Energy levels.......................................................................................................................................................... 6- 3

6. 3 Supply Side Resource Technology Costs and Characteristics........................................... 6- 8

6. 4 Energy Efficiency................................................................................................................................ 6- 16

6. 5 Energy Storage.................................................................................................................................... 6- 17 I 151r 5 f t r ri' YrSr p,; n. n.

Packet Pg. 461 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric

7. 0 Modeling Assumptions, Tools, and Methodology.................................................................... 7- 1

7. 1 Modeling Assumptions...................................................................................................................... 7- 1

7. 2 Ascend Analytics Planning Suite- Tools for Modern Resource Planning....................7- 4

8. 0 Evaluation and Results...................................................................................................................... 8- 1

8. 1 Economic Evaluation Framework................................................................................................. 8- 1

8. 2 Scenario Analysis................................................................................................................................. 8- 2

8. 3 Consolidated Results.......................................................................................................................... 8- 5

8. 4 Detailed Results of the Preferred Expansion Plan................................................................. 8- 8

8. 5 Sensitivity Cases................................................................................................................................. 8- 17

8. 6 Retail Rates and the Preferred Expansion Plan..................................................................... 8- 17

8. 7 The preferred Plan in consideration of Future Conditions and risks........................... 8- 19

8. 8 The preferred Plan with consideration of Localized Air Pollutants and Disadvantaged Communities........................................................................................................ 8- 21

9. 0 Conclusions and Recommended Expansion Plan.................................................................... 9- 1 Appendix A. CEC Standardized Tables for the Adopted Resource Scenario.............................A- 1 Appendix B. Stakeholder Feedback Form Results............................................................................. B- 1 Appendix C. Intermittency Analysis........................................................................................................ C- 1 Attachment A: Solar Project Generation Data.......................................................................... C- 3 Attachment B: Stochastic Model Results.................................................................................... C- 5 Appendix D. Ascend Analytics Methodology........................................................................................ D- 1 Appendix E. RPS Compliance and Enforcement Document............................................................ E- 1 Appendix F. Energy Storage Compliance Plan..................................................................................... F- 1 LI S" " LE S
Table 1- 1 Summary of Key IRP Filing Requirements and Location in IRP....................................... 1- 3 Table 1- 2 Projects Considered in the IRP Expansion Plans ( All Capacities are the Maximum Rated and Not Firm Capacities) ............................................................................... 1- 6 Table 1- 3 Projects in the Expansion Plan Scenarios Modeled ( All Capacities are the Maximum Rated and Not Firm Capacities) ............................................................................... 1- 7 Table 1- 4 Heat Diagram of Scenario CPWC and RE Results.................................................................. 1- 12 Table 1- 5 Detailed CPWC Results for the Preferred Expansion Plan, Scenario H........................ 1- 13 Table 1- 6 Renewable Energy and REC Adequacy in the Preferred Expansion Plan, ScenarioH............................................................................................................................................. 1- 14 Table 2- 1 Estimated 2030 GHG Emissions by Sector ( MMTCOZe).......................................................2- 5 Table 2- 2 POU Share ( in 1, 000 MTCOZe) of 2030 GHG Emissions Projected by CARB............... 2- 5 Table 2- 3 Summary of Key IRP Filing Requirements and Location in IRP.......................................2- 8 Table 3- 1 Power Supply Resources ( Calendar Year 2017)..................................................................... 3- 2 Table 3- 2 Current( Calendar Year 2017) Zero Carbon and Renewable Energy Resources................................................................................................................................................ 3- 5 Table 3- 3 Historic Deliveries from WAPA CVP............................................................................................ 3- 7 I 151r 5 f t r ri' YrSri Y; l..n. n. n.

Packet Pg. 462 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Table 3- 4 WAPA Transmission Service Summary Information.......................................................... 3- 11 Table 3- 5 Natural Gas Purchase Obligations, Fixed Price Hedges...................................................... 3- 17 Table 4- 1 Historic Customer, Sales, and Demand Data............................................................................. 4- 2 Table 4- 2 Load Forecast Assumptions and Input Considerations....................................................... 4- 4 Table 4- 3 Projected Net Energy Requirements, Peak Demand Forecast, and Load Factor........................................................................................................................................................ 4- 7 Table 6- 1 Existing System Energy Sufficiency.............................................................................................. 6- 4 Table 6- 2 Solar Systems and Modeled Performance................................................................................. 6- 9 Table 6- 3 Wind Systems and Modeled Performance............................................................................... 6- 10 Table 6- 4 2020 Cost Assumptions for Solar SAT Systems ( Nominal$)............................................ 6- 11 Table 6- 5 2020 CostAssumptions for Wind Systems ( Nominal$)..................................................... 6- 11 Table 6- 6 2030 Cost Assumptions for Solar SAT Systems ( Nominal$)............................................ 6- 12 Table 6- 7 2030 CostAssumptions for Wind Systems ( Nominal$)..................................................... 6- 12 Table 6- 8 Assumed Federal and State Income Tax Rates...................................................................... 6- 13 Table 6- 9 Tax Credit Assumptions.................................................................................................................. 6- 14 Table 6- 10 Cost of Capital Assumptions for Solar and Wind.................................................................. 6- 14 Table 6- 11 Renewable Energy Projects LCOE ( Nominal$) 2020 COD................................................ 6- 15 Table 6- 12 Renewable Energy Projects LCOE ( Nominal$) 2030 COD................................................ 6- 15 Table 6- 13 Project Nominal LCOE 2020 to 2030......................................................................................... 6- 16 Table 6- 14 Representative Performance Parameters for Lithium Ion Battery Systems.............6- 18 Table 7- 1 Natural Gas and Market Energy Prices Assumed in the IRP.............................................. 7- 1 Table 8- 1 RPS Project Definitions...................................................................................................................... 8- 3 Table 8- 2 IRP Scenario and Projects................................................................................................................. 8- 4 Table 8- 3 Heat Diagram of Scenario CPWC and RE Results.................................................................... 8- 7 Table 8- 4 Energy Balance in the Preferred Expansion Plan, Scenario H......................................... 8- 11 Table 8- 5 Detailed CPWC Results for the Preferred Expansion Plan, Scenario H........................ 8- 16 LI Sl F I S
Figure1- 1 IRP Objectives........................................................................................................................................ 1- 2 Figure 1- 2 GHG Emissions in the Preferred Plan, Scenario H................................................................ 1- 10 Figure1- 3 Renewable Outlook........................................................................................................................... 1- 10 Figure 2- 1 COR' s Energy Demand and Supply............................................................................................... 2- 1 Figure 2- 2 COR' s Integrated Resource Planning Process.......................................................................... 2- 1 Figure 2- 3 Timeline of Key State Legislative Actions Impacting IRP Planning.................................2- 3 Figure 2- 4 Stakeholder Integration Process................................................................................................. 2- 15 Figure 2- 5 First Stakeholder Meeting February 23, 2018.................................................................... 2- 16 Figure 2- 6 Stakeholder Engagement Participants...................................................................................... 2- 16 Figure 3- 1 Power Resource Locations ( Self- Owned and PPA Resources)..........................................3- 3 Figure 3- 2 Mix of Energy Production by Generation Type, 2017 ( Calendar Year).........................3- 3 Figure3- 3 Transmission......................................................................................................................................... 3- 8 I 151r 5 f t r ri' YrSr p,; n. v
Packet Pg. 463 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Figure 3- 4 Balancing Area of Northern California ( BANC) Members................................................. 3- 10 Figure 3- 5 Electric Distribution System.......................................................................................................... 3- 13 Figure 3- 6 Reliability Comparison.................................................................................................................... 3- 14 Figure 4- 1 5- Year Average Monthly Energy Sales and Peak Demand ( 2013- 2017)......................4- 1 Figure 4- 2 Projected Solar Installations vs ITC Tax Credit....................................................................... 4- 4 Figure 4- 3 Projected Electric Vehicles - COR Service Territory............................................................. 4- 5 Figure 4- 4 Energy Requirements Comparison: COR Forecast vs. CEC Forecast for COR............. 4- 8 Figure 5- 1 Comparison of Energy Efficiency Targets and Historical Achievements......................5- 2 Figure 5- 2 Annual EE Portfolio Market Potential by End Use.................................................................5- 5 Figure 6- 1 Capacity Sufficiency for the " Existing System" Scenario, 2018- 2037............................6- 2 Figure 6- 2 Energy Balance for the Existing System, Scenario G............................................................. 6- 5 Figure 6- 3 REC Adequacy in Existing System Scenario.............................................................................. 6- 6 Figure 6- 4 Existing System Scenario Projected GHG Emissions............................................................. 6- 7 Figure 6- 5 Location of Renewable Resource Project Candidate Units in the IRP..........................6- 10 Figure 7- 1 Power Forward Price......................................................................................................................... 7- 2 Figure7- 2 Gas Forward Price............................................................................................................................... 7- 3 Figure 7- 3 Carbon Allowance Forward Price................................................................................................. 7- 3 Figure 8- 1 Capacity Balance in the Preferred Expansion Plan, Scenario H........................................ 8- 9 Figure 8- 2 Loads and Resources Balance in the Preferred Expansion Plan, Scenario H............ 8- 10 Figure 8- 3 Renewable Energy and REC Adequacy in the Preferred Expansion Plan, ScenarioH............................................................................................................................................. 8- 14 Figure 8- 4 GHG Emissions in the Preferred Expansion Plan, Scenario H......................................... 8- 15 Figure8- 5 Renewable Outlook........................................................................................................................... 8- 15 Figure 8- 6 Budget Categories by type in Fiscal Year 2019..................................................................... 8- 18 Figure 8- 7 Cost of the Preferred Expansion Plan, Scenario H................................................................ 8- 18 Figure 8- 8 Cal Enviro Disadvantaged Communities Map........................................................................ 8- 22 I 151r 5 f t r ri' YrSr p,;
Packet Pg. 464 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric iir ii ii , iir.., iii ° iii ii, ii iii ii iii° iii ii iii° AAEE Additional Achievable Energy Efficiency
AAGR Annual Average Growth Rate
AB Assembly Bill
AC Alternating Current
AMI Advanced Metering Infrastructure
BANC Balancing Authority of Northern California
Barriers Study Low- Income Barriers Study, Part A: Overcoming Barriers to Energy Efficiency and Renewables for Low- Income Customers and Small Business Contracting Opportunities in Disadvantaged Communities
BESS Battery Energy Storage System
BPA Bonneville Power Administration
CAISO California lndependent System Operator
CaIEPA California Environmental Protection Agency
California lSO California lndependent System Operator, also CAISO CAPEX Capital Expenditures
CARB California Air Resources Board
Carbon Allowance The amount of carbon allowed to be emitted as authorized by the government; an allowance is commonly one ton of carbon dioxide CEC California Energy Commission ( also Energy Commission) CEC Guidelines The CEC document, Publically Owned Utility Integrated Resource Plan Submission and Review Guidelines( July 2017)
CO Carbon Monoxide
COz Carbon Dioxide
COze Carbon Dioxide Equivalent
COD Commercial Operation Date
Combined Cycle A combined- cycle power plant uses both a gas and steam turbine together to produce more electricity from the same fuel COR City of Redding
COSL City of Shasta Lake
COTP California- Oregon Transmission Project
CPUC California Public Utilities Commission
CPWC Cumulative Present Worth Cost
CRAT Capacity Resource Accounting Table ( CEC Standardized Table) CSD Community Service and Development
CV Central Valley
d: u• i tuui a d dlli. uo il u ui, au aal I a. uu• iu il u ui I u il AI..,..' 1 Packet Pg. 465 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric CVP Central Valley Project
DC Direct Current
Decatherm ( Dth) Measurement of heat equivalent to one MMBTU DOE Department of Energy
DSM Demand- Side Management; refers to initiatives that encourage consumers to optimize energy usage
Dth/ day Decatherm per Day
EBT Energy Balance Table ( CEC Standardized Table)
EIA U. S. Energy Information Administration
Energy Commission California Energy Commission ( also CEC) EPA U. S. Environmental Protection Agency
ES Energy Storage
ESA Energy Savings Assistance
EV Electric Vehicle
FERC Federal Energy Regulatory Commission
FY Fiscal Year ( July 1- June 30 for Redding; October 1- September 30 for the US Government)
GEAT GHG Emissions Accounting Table ( CEC Standardized Table) GHG Greenhouse Gas
GWSA Global Warming Solutions Act
HSC Health and Safety Code
ICE Intercontinental Exchange
IEPR Integrated Energy Policy Report
IPP Independent Power Producer
IRP Integrated Resource Plan
IRP Filing POU Adopted IRP Accompanied By The Required Supporting Information
JPA Joint Powers Agency
LCOE Levelized Cost of Energy
LD PEV Light- Duty Plug- In Electric Vehicle
LIEEP Low- Income Energy Efficiency Program
LMP Locational Marginal Pricing
Load Factor A load factor is a measure of the variability in utility load over time MACRS Modified Accelerated Cost Recovery System- the current tax depreciation system in the US
MMBTU One Million British Thermal Units ( 1, 000, 000 BTU) d: u• i tuui a d dlli. uo il u ui, au aal I a. uu• iu il u ui I u il AI..,..

Packet Pg. 466 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric MMT Millions of inetric tons
M- S- R PPA California Joint Powers Agency, M- S- R Public Power Agency, of which the City of Redding is a member along with Modesto Irrigation District and they City of Santa Clara
M- S- R EA M- S- R Energy Authority
MT Metric Ton
MW Megawatt
MWh Megawatt- hour
NCPA Northern California Power Agency
NEM Net Energy Metering
NERC North American Electric Reliability Corporation
NOX Nitrogen Oxide
OASIS Open Access Same- Time Information System
OH Overhead
PEV Plug- In Electric Vehicle
POU Publicly- Owned Utility
PPA Power Purchase Agreement
PRC Public Resources Code
PUC Public Utilities Code
PV Photovoltaic ( solar)
RE Renewable Energy
REC Renewable Energy Credit( 1MWh renewable energy= 1 REC) is a tradable, non- tangible energy commodity representing proof that 1 megawatt-hour (MWh) of electricity was generated from an eligible renewable energy resource
RPS Renewables Portfolio Standard
RPT RPS Procurement Table
SAE Statistically Adjusted End Use
SB Senate Bill
SB 350 Senate Bi11350 ( De Le6n, Chapter 547, Statutes of 2015) Scenario Eight expansion plans developed and compared
SOTP South of Tesla Principles
TAC Transmission Access Charge
TANC Transmission Agency of Northern California
UG Under Ground
VAR Volt- ampere reactive; voltage& current out of phase on AC system d: u• i tuui a d dlli. uo il u ui, au aal I a. uu• iu il u ui I u il AI..,..3 Packet Pg. 467 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric WAPA Western Area Power Administration, ( also Western) WECC Western Electricity Coordinating Council
WREGIS Western Renewable Energy Generation Information System ZEV Zero Emission Vehicle
ZNE Zero Net Energy
d: u• i tuui a d dlli. uo il u ui, au aal I a. uu• iu il u ui I u il AI..,..

Packet Pg. 468 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric iir
a ... °
iir° ii .., iir
Ascend Analytics Modeling software company
PowerSimm Software developed by Ascend Analytics used to evaluate scenarios for load, resources, cost, risk, and environmental mandates
Curve Developer Software developed by Ascend Analytics to forecast market gas and power prices
Black& Veatch Consultant who aided in IRP development ensuring all mandates were met
Itron Consultant who developed the load forecast
Il d: v. v
a il 6' v; ilui¢ I
rFr..'1
Packet Pg. 469 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric iii .., ii ii iir
This report( Report) presents the Integrated Resource Plan ( IRP) for the City of Redding ( COR), owner of a non- profit, vertically integrated utility providing electric service to approximately 44, 000 customers in and near Redding, California within a service area that covers approximately 61 square miles. COR' s vision is to benefit and create value for its electric customers served in the Redding community and to deliver exceptional services through the strength and dedication of its employees. This overarching objective is achieved by providing reliable and safe service at low cost- conscious) rates, while complying with state and environmental mandates and regulations.

An IRP is a long-term, comprehensive plan developed to help ensure that the COR can meet its customers' annual peak energy needs over the planning horizon in a cost- effective manner, while also meeting system reliability needs, state policy goals, and other targets established for the community. This is not intended as a procurement document, rather, a blueprint for future resource requirements needed to comply with state mandates. Acquisitions will be vetted in the normal course and the standard procurement process will be followed.

As demonstrated in this document, the IRP provides an assessment of the future energy needs of customers over the next 20 years ( from 2018 through 2037) and summarizes the preferred plan for meeting those needs in a safe, reliable, cost- effective, and environmentally responsible manner2.

This IRP was developed in response to the Clean Energy and Pollution Reduction Act of 2015 California Senate Bi11350; herein SB 350), which established new clean energy, clean air, and greenhouse gas ( GHG) reduction goals, and established a number of requirements for publicly owned utilities (POUs). The most far-reaching goals and requirements include:

An increase in the procurement of energy from renewable electricity sources, from 33 percent by 2020 to 50 percent by 2030
Consideration of programs that will help the state double energy efficiency savings in electricity and natural gas end uses by 2030
A reduction in GHG emissions consistent with the targets set forth by the California Air Resources Board ( CARB) in its July 2018 reportl
POUs must develop an IRP that sets forth the plan to achieve the above goals and other objectives such as those related to reliability and cost-effectiveness. The IRP is to be approved by the respective boards by January 1, 2019, and submitted to the California Energy Commission ( CEC) by Apri130, 2019
This IRP addresses each of the applicable requirements and targets. The recommended plan meets the 2030 renewable energy( RE) target as well as the intermediate targets; the load forecast reflects a continuation of COR' s long history of encouraging energy efficiency and demand reduction; and the recommended plan fits within the CARB' s 2030 targets for GHG emissions. 1 California Air Resources Board, Staff Report: Senate Bi113501ntegrated Resource Planning Electricity Sector Greenhouse Gas Planning Targets, July 2018; SB 350 required CARB to develop recommendations based on the goal of achieving a 40% reduction in GHG by 2030.
z SB 350 is reflected in Public Utilities Code( PUC) Section 9621, which applies to POU' s with an average electrical demand exceeding 700 gigawatt- hours, based on a three- year average commencing January 1, 2013.

I :¢: u. uilu:" u. uu• uiuui r 1..' 1
Packet Pg. 470 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric The 2019 IRP was developed through extensive analysis and benefited from coordination among internal and external parrners and stakeholders. This Report, and the accompanying appendices, describes the analyses conducted and the underlying assumptions used to produce a 20- year plan to meet customers' energy needs through 2037. While the IRP is only required to extend to 2030, the CEC encouraged POUs to consider time periods extending beyond 2030 in its Commission Guidelines. 3 Incorporated into the IRP are anticipated changes to the utility industry and California over the planning period.

Although significant changes within the electric utility industry are anticipated to occur over the 20- year planning horizon for the IRP, COR must plan for sufficient supplies of electricity while also maintaining competitive prices and achieving safety, environmental, operational, and reliability goals. During the preparation of the IRP, a wide variety of alternatives that could meet these many supply and demand- side objectives were considered. The IRP process has also taken into consideration the need to establish a plan that will allow flexibility to respond to uncertainty regarding technological and future regulatory change. Goals established to guide development of the IRP are presented in Figure 1- 1.

Cn m u n
ty va ues P rnv cie re al e anv re r
Exce at n 7a se rv ce M 7 z.e nuta es 8R
E3a a 7ce cnsts a 7ci I e nef ts se rv ce 7te r ru at n 7s C ve rse an rtfn n vv tlh
va r ety nf re nevval e
resnu rces
w "
I
W
uuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuu IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII iiiiiiiiiil
Illll t IIIIIII
i,,,,,,, ,,,,,,,, ,,,,,,,,;,.

L t futu re ccrst 7c reases Ccr a y v r tlh c 7a 7 7
Kee a 7 a r ces as crv r a 7ci
j; ; Ca fcr r n a re u at cr 7s
affcr rcial e as reas r 7al y Meet tlhe mr a 7ciates crf p
rss I e S C 3 5C
L t r slks
Figure 1- 1 IRP Objectives
3 Vidaver David, Garry O' Neill- Mariscal, Melissa Jones, Paul Deaver, and Robert Kennedy, 2018, Publically Owned Utility Integrated Resource Plan Submission and Review Guidelines, California Energy Commission. Publication Number: CEC- 200- 2018- 004- CMD, 2" d Edition, p. 4.

I :¢: u. uilu:" u. uu• uiuui r 1..

Packet Pg. 471 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric A summary of the 20- Year Resource Plan is provided in Section 1. 1. Supporting information, including studies, data, analyses and results, plus associated exhibits for the IRP analysis is provided in the following sections ofthe Report:

Section 2. 0 Purpose and Background
Section 3. 0 Existing Resources and System Description
Section 4.0 Energy and Demand Forecast
Section 5. 0 Customer Programs, Energy Efficiency and Demand Response Resources Section 6. 0 The Need for Additional Resources and Resource Options Section 7. 0 Modeling Assumptions, Tools, and Methodology Section 8. 0 Evaluation and Results
Section 9. 0 Conclusions and Recommended Scenario
Standardized tables requested by the CEC are located in Appendix A followed by discussion in Appendix B- F. The organization and contents of this IRP reflect the requirements established in the CEC IRP Guidelines. The major requirements set forth in these guidelines and the primary section in which the required information is provided is shown in Table 1- 1.

Table 1- 1 Summary of Key IRP Filing Requirements and Location in IRP im
II
i ii ii ii ii

I I II I I IIII
A. Planning adopt an IRP that ensures the utility achieves the specific goals and Section 8 Horizon and targets by 2030, including...greenhouse gas emissions reductions of 40 Objective of percent below 19901evels, and... at least 50 percent of eligible Expansion Plan renewable resources... The minimum planning horizon...begins no later than January 1 of the year that the POU' s governing board adopts the plan and ends no earlier than December 31, 2030... POUs are encouraged to undertake and present analysis.... that addresses the post- 2030 period"
B. Scenarios IRP Filings.... must meet the requirements of PUC Section 9621. POUs Section 8 and Sensitivity are encouraged to also evaluate other scenarios and sensitivity analyses Analysis to consider the feasibility and cost- effectiveness( and rate impacts) of alternative resource options."
C. Standardized " POUs must submit the following four Standardized Tables... Appendix A Tables Capacity Resource Accounting Table( CRAT)
Energy Balance Table( EBT)
RPS Procurement Table( RPT)
GHG Emissions Accounting Table( GEAT)"
D. Supporting "( 1) analyses, studies, data, and work papers, or other material that the Section 4, Information POU used or relied upon( including inputs and assumptions) in creating 5, 6; all the IRP... and( 2) additional information required by these guidelines. Appendices Supporting Information supplements the data submitted in the Standardized Tables."
I :¢: u. uilu:" u. uu• uiuui r 1.. 3
Packet Pg. 472 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric im
II
i ii ii ii ii

I I II I I IIII
E. Demand 1. Reporting Requirements... annual forecasted peak demand( MV in Section 4, Forecast the CRAT and annual forecasted retaii sales, other loads, and net energy Appendix A for load in the EBT...

2. Demand Forecast Methodology and Assumptions.

3. Demand Forecast- Other Regions. If the POU uses system modeling... the IRP Filing must include the demand forecast assumptions for regions outside the POU jurisdiction."
F. Resource the mix of resources... in the IRP [ as]... reported on the CRAT, EBT, Section 4, Procurement and GEAT, and RPS procurement must also be reported on the RPT 5, 8, Plan along with] all inputs, assumptions, and methodologies ... The IRP Filing Appendix A must address[:]

1. Diversified Procurement Portfolio

2. RPS Planning Requirements

3. Energy Efficiency and Demand Response Resources

4. Energy Storage

5. Transportation Electrification"
G. System and " Filing POUs [ must] adopt an IRP to... meets the goal of ensuring system Section 4 Local Reliability and local reliability...[ and report]:

1. Reliability Criteria... the planning reserve margin and how it was determined.

2. Local Reliability Area. The IRP Filing must identify any local transmission constrained areas in the POU service territory..." H. Greenhouse " POUs must report in the GEAT estimated emissions intensities( in Section 8, Gas Emissions metric tons of carbon dioxide equivalent[ COze] per megawatt hour... for Appendix A each supply resource reported in the EBT:'
I. Retaii Rates "... the IRP Filing must include, as Supporting Information, a report or Section 8 study on rate impacts under the IRP scenario, if that report or study was considered by the local governing authority as part of its IRP planning." J. T& D Systems "... adopt and IRP [ that] achieves the goal of strengthening the diversity, Section 3 sustainability, and resilience of the bulk transmission and distribution systems, and local communities."
K. Localized Air "... adopt IRPs to...[ achieve] the goal of minimizing localized air Section 8 Poliutants and poilutants and other GHG emissions, with eariy priority on Disadvantaged disadvantaged communities...[ discuss] how current programs and Communities policies in place... address local air pollution...[ and] how programs assist and prioritize disadvantaged communities."
Summarized from Chapter 2 of Vidaver David, Melissa Jones, Paul Deaver, and Robert Kennedy. zoi8. Publicly Owned Utility Integrated Resource Plan Submission and Reuiew Guidelines.

California Energy Commission. Publication Number: CEC- 2oo- 2oi8-oo4.

I :¢: u. uilu:" u. uu• uiuui r 1..

Packet Pg. 473 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric

1. 1 SUMMARY OF THE 20-YEAR RESOURCE PLAN
The IRP, described herein, was based on the load forecast developed by Itron further described in Section 4. The competing expansion plans ( Scenarios) were designed to meet the load requirements and other planning objectives stated herein, and each Scenario was rated on various measures to define the preferred Scenario.

Section 6 of this report explains that COR has sufficient generating capacity to meet energy needs through the 2037 planning period; however, an Existing System Scenario is not acceptable as it would fall short ofineeting renewable generation and environmental mandates. As a result, several Scenarios were developed that provide additional renewable resources and were evaluated based on the cost and characteristics of select solar and wind options described in Section 6. Centered on these characteristics, as well as additional assumptions and methods described in Section 7, the long-term cumulative present worth cost( CPWC) of eight competing Scenarios were developed and are presented in Section 8. The CPWC includes all incremental costs of the planning period stated on a present worth basis.

The eight Scenarios evaluated each differ in terms of the additional solar and wind resources that comprise the plan. Solar and wind were the only projects evaluated for future resources due to the desires of COR and its customers. The list of projects considered for inclusion in the Scenarios is shown in Table 1- 2. The eight Scenarios developed around these projects are shown in Table 1- 3.

Each of these Scenarios, other than the Existing System Scenario, include the 2021 addition of the 10 MW( Project 1) Solar Project now in Phase II of development— this Phase includes site recommendation, site screening, preliminary development, and early project development and financing.

I :¢: u. uilu:" u. uu• uiuui r 1..

Packet Pg. 474 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Table 1- 2 Projects Considered in the IRP Scenarios( All Capacities are the Maximum Rated and Not Firm Capacities)
ii l iiiriu, iii91 iii ii " Umliii91 iii ii
iiiU
iii i i '
iii
l
i
iiiU
iii i i
I
iii iii i m iii91 iii ii " „ ,
Name Local PV NorCal/ OR AZ PV CV PV 1 CV PV 2 NorCal/ OR AZ Wind w/ Batt PV Wind
Location Local OR/ NorCal Arizona Central Central OR/ NorCal Arizona Valley Valley
Type PV PV PV PV PV Wind Wind
Capacity( MW) 10 100 100 20 100 100 200
Scalable No Yes Yes No Yes Yes Yes
AC Capacity 27.9% 27. 0% 33. 1% 30.6% 29. 8% 30. 0% 30.0% Factor(%)
Annual Energy 24,440 236, 520 289, 956 53, 611 261, 048 262, 800 525, 600 MWh)
Annual 0. 70% 0. 70% 0. 70% 0. 70% 0. 70% 0.00% 0. 00%
Degradation(%)
Energy Storage? Yes Not Not Not Not Not Not
Yes/ No/ Maybe) included included included included included included ES Capacity( MV1 2. 50 Not Not Not Not Not Not
included included included included included included
ES Duration( Hrs) 4 Not Not Not Not Not Not
included included included included included included
Transmission None To COTP, To CAISO, NP26, To CAISO, To COTP, To CAISO, Requirements WAPA WAPA WAPA WAPA WAPA WAPA
LMP Market NP15 NP15 Palo Verde ZP26 SP15 NP15 Palo Verde Location( To
Value)
Transmission 0.000 2. 258 3. 137 0.000 0. 000 2.258 3. 137 Access Charge
TAC) Costs
2018-$/ kW/ mo)
Transmission 0.000 0. 000 11. 221 $ 11. 221 $ 11. 221 0.000 11. 221 Costs( 2018-
MWh)
Transmission 5. 00% 4. 00% 4. 00% 4. 00% 5. 00% 4.00%
Escalation Rate
There are two methods of accounting for transmission costs: volumetric charges($/ MWh) used by California lndependent System Operator, and demand($/ kw- mo). Depending on the location of the project and transmission path, it will be one or the other, or both; the model accommodates both.

I :¢: u. uilu:" u. uu• uiuui r r 1.. 6
Packet Pg. 475 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Table 1- 3 Projects in the Scenarios Modeled ( All Capacities are the Maximum Rated and Not Firm Capacities)
iiiii iiiii iiiii iiiii iiiii iiiii iiiii iiiii iiiii iiiii iiiii iiiii iiiii iiiii b
A
I i l
I I I I „ I
li m" li m
A) Base Case MW: 10
Start: 2021
MWh r:
24,440
LCOE:$ 58
B) Balanced MW: 10 MW: 30 MW: 20 MW: 70
Mix Start: 2021 Start: 2028 Start: 2026 Start: 2032
MWh r: MWh r: MWh r: MWh r:
24,440 86,987 53, 611 183, 960
LCOE:$ 58 LCOE:$ 57 LCOE:$ 71 LCOE:$ 76
C) Balanced MW: 10 MW: 30 MW: 25 MW: 70
Mix- Alternate Start: 2021 Start: 2029 Start: 2026 Start: 2032 MWh r: MWh r: MWh r: MWh r:
24,440 70, 956 65, 262 183, 960
LCOE:$ 58 LCOE:$ 73 LCOE:$ 68 LCOE:$ 72
D) Heavy MW: 10 MW: 85
Wind Start: 2021 Start: 2026
MWh r: MWh r:
24,440 223, 380
LCOE:$ 58 LCOE:$ 68
E) Heavy MW: 10 MW: 85
Wind- Start: 2021 Start: 2026
Alternate
MWh r: MWh r:
24,440 223,380
LCOE:$ 58 LCOE:$ 72
F) Heavy MW: 10 MW: 90
Solar Start: 2021 Start: 2026
MWh r: MWh r:
24,440 212, 868
LCOE:$ 58 LCOE:$ 70
G) Existing
System
H) Optimized MW: 10 MW: 60 MW: 65
Balanced Mix Start: 2021 Start: 2026 Start: 2034
MWh r: MWh r: MWh r:
24,440 156,629 170, 820
LCOE:$ 58 LCOE:$ 68 LCOE:$ 77
The levelized cost of energy, in$/ MWh( LCOE), is measured at the plant and does not include transmission charges.

Transmission charges are estimated in Table 1- 2
I :¢: u. uilu:" u. uu• uiuui r 1.. 7
Packet Pg. 476 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric The results of the Scenario analysis are reported in Section 8 and are also summarized in Table 1- 4.

In this table, the consolidated CPWC results and other key results for the Scenarios evaluated are presented as a" heat map" in which the best Scenario results are shown in green and least favorable results are in red, with varying shades in between. This map clearly illustrates the inadequacies of some Scenarios and highlights those that meet the measured standards. Some plans had a favorable CPWC, but didn' t meet requirements for a balanced renewable portfolio, and alternatively, other Scenarios had a favorable balance of renewable resources, but were considerably higher in cost.

The Base Case Scenario, in which 10 MW of local solar is added in 2021, is listed first in Table 1- 4.

This Scenario is important as it reflects the addition of the currently- planned Solar Project that is in the second phase of development( See Section 7. 0). There are two key conclusions related to the Base Case Scenario.

First, by comparing the Base Case CPWC with the Existing System Scenario ( Scenario G) CPWC, it is clear that the Base Case has a lower CPWC. This helps to highlight why adding the 10 MW solar project( Project 1 from Table 1- 2) provides an added benefit from a cost perspective, and by adding RE benefits over the Existing System case. This comparison helps to illustrate the reason for selecting the 10 MW Solar Project in 2021 as the next resource addition and why this is considered to be the Base Case rather than Scenario G.

A second, very important conclusion about the Base Case Scenario is that, even though it achieves a higher RE percentage than Scenario G, it still falls short of ineeting the 2030 RE target of 50 percent.

In fact, it achieves only a 33 percent level in 2030. Moreover, the Base Case Scenario is still very heavily reliant on wind energy( 71 percent of all RE) even with the addition of Project 1 in 2021.

Due to these results, the Base Case is understood to contain the next project to be undertaken, but it is not the final recommended mix of resources over the entire planning horizon. The need for additional renewable resources beyond 2021 solar addition led to the development of the remaining Scenarios in Table 1- 3. With the exception of Scenario G, all Scenarios involved the 2021 solar project, but also included additional RE resources after 2021. o," ; maru u u t unn,. r° maru
The various modeled Scenarios were rated based on the adopted objectives of maintaining low cost, exceptional reliability, a diverse portfolio, and environmental responsibility. Of the Scenarios modeled, Scenario H is the recommended plan in this IRP as this plan offers the best combination of COR' s goals and includes the practical balance of RE resources ( between wind and solar) and the requirements established for POUs by the state. Scenario H calls for the addition of 10 MW maximum rated capacity, not firm) of new solar purchases in 2021, followed by 60 MW( rated) of solar purchases in 2026 and 65 MW( rated) of wind purchases in 2034. The four detailed tables required by the CEC Guidelines are provided in Appendix A for this preferred Scenario. This IRP, and the recommendation of Scenario H as the preferred plan, was adopted by the Redding City Council ( Council) in October 2018.
o, o^ ii' IV^"' II II" u .
dr'" u"° II a;:' Y II II. dr
The portfolio plan of Scenario H has sufficient generation capacity to meet energy needs throughout the planning horizon, ending with 41 MW of surplus capacity in 2037. While there is a capacity surplus, the IRP must meet requirements for both capacity and energy, particularly eligible RE requirements, simultaneously( see Section 6 for further details outlining this requirement). The plan associated with Scenario H contains three renewable projects additions. At the top right of Table 1- 5, the following information about the new renewable project additions are shown:

I :¢: u. uilu:" u. uu• uiuui r l f
Packet Pg. 477 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric 10 MW local Solar PV project( 3. 5 MW is considered firm capacity), added in 2021 ( common to all plans except the Existing System Scenario),
60 MW Solar PV project in 2026 ( planned to have a firm output of 21 MV, and 65 MW wind project( firm output of 7 MW) added in 2034.

COR' s energy requirements are met under the plan associated with Scenario H. Under Scenario H, the 1x1 and 2x1 combined cycle ( a combined- cycle power station uses both a gas and steam turbine together to produce more electricity from the same fuel) projects are the only two units at the Redding Power Station ( Station) generating a significant amount of energy, while all RE projects are actively producing energy consumed by customers or sold into the market. The addition ofthe three RE projects allows compliance with Renewable Portfolio Standard ( RPS) requirements.

Details regarding the above mentioned merits of Scenario H as a preferred plan are contained in Section 8.

Scenario H results in a 2030 RE percentage of 54 percent in 2030, exceeding the target of 50 percent. Under this plan, there would be an estimated carbon emissions level of 72, 405 MTCOZe in 2030. This level of emissions is well below the high target of 101, 000 MTCOZe in the CARB staff recommendations for COR( although it is above the 57, 000 MTCOZe set as the lower end of the targeted range). In subsequent years, the MTCOZe in Scenario H falls below the 20301eve1 and ends with 73, 713 MTCOZe of emissions in 2037. Details of the cost and revenue projection contributing to the overall CPWC for Scenario H of about$ 581 million through 2037 are shown year by year in Table 1- 5.

Scenario H is quite flexible in that, following the first resource addition in 2021 ( common to all plans), projects are layered in over a 20- year period; the next project is expected to be operational in 2026, which brings the following benefits:

The period between resource additions allows the continued assessment of industry events and system developments in order to adjust the specifics of Scenario H if conditions warrant;
It provides the ability to increase or decrease the size ofthe selected RE projects as necessary;
With the pliability this plan offers, staff can better match resources to comply with any future applicable in- state versus out- of- state requirements, such as those of the California Independent System Operator ( CAISO); and
The plan provides the ability to delay or accelerate the in- service date of the project based on a number of factors such as future legislation and market conditions While Scenario D may appear to be a less costly option, it offers less flexibility in that, beyond the 2021 solar addition that is also added in Scenario H, the plan consists of only an 85 MW wind addition in 2026. Although it may be economical to add this large wind project, the plan results in an unbalanced mix of solar and wind generation as indicated by the 84 percent wind, 6 percent solar mix of RE for Scenario D indicated in Table 1- 4.

Scenario H is within the limit of MTCOZe recommended by the CARB staff for COR in 2030 ( 101, 000 MTCOZe) and meets the RE targets as is seen in Table 1- 6 below. By relying on annual RECs and I :¢: u. uilu:" u. uu• uiuui r l..d
Packet Pg. 478 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric banked RECs, the plan meets the 2030 RE target of 50 percent and never incurs a negative REC bank balance during the 2018- 2037 planning period.

REDDING POWER

GREENHOUSE GAS OUTLOOK

SCENARIO H
140, 000
120, 000
N
u u,, 1,
F
80, 000
60, 000
0 y 40, 000
W 20,000
0 2022 2023 2024 2025 2026 2027 2028 2029 2030
Year
TotalEmissions ^^ Goal
Figure 1- 2 GHG Emissions in the Preferred Plan, Scenario H

RENEWABLE OUTLOOK
6o io
r--,
50% muumuumuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuu
immuumuu
40%
r. 30%
C
CC 20%
a
cC
10%
0/0 o
2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Year
Requirement Preferred Plan Base Case
Figure 1- 3 Renewable Outlook
I :¢: u. uilu:" u. uu• uiuui r r..'1
Packet Pg. 479 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric o . o m I II Ma 7IIV" u°".' W . dr m l S':° II Ilna° 7°` IVCt, @""° u""' IV` nn 7II II.' W Scenario H is the only Scenario identified in Table 1- 4 as having green or light green shading in all categories. The plan is within 2. 8 percent of the least cost plan; it achieves a 54 percent RE mix in 2030; it achieves all intermediate RE milestones ( by relying on banked RECs in some years) and has a reasonably balanced mix of RE contributions from wind ( 53 percent) and solar ( 36 percent).

Based on the global objective of balancing economic, reliability, and environmental objectives, Scenario H is the best overall plan in the 2019 IRP. Further details about Scenario H are provided in the next Section 8.

In terms of lowest CPWC, Scenario D may appear to be the best overall plan and it also is very good in terms of the 2030 RE level of 65 percent. However, the area where this plan falls short is its lack of resource diversity—the plan is very heavily reliant on wind energy( 84 percent of all RE) and contains little solar energy( 6 percent). As a result, this plan receives low marks for its inability to achieve a balanced RE portfolio. This assessment is reflective of the preference that several Stakeholders expressed for solar energy and is consistent with the emphasis on a balanced RE portfolio. Relying heavily on one resource can create a reliability issue both with power generation and transmission.

Scenario C also achieves a very high percentage of RE in 2030 ( 65 percent) but is not economical and also suffers from a high reliance on wind energy. Scenario F is economically competitive and achieves 61 percent RE contribution, but the scenario is over-reliant on wind energy resources.

Scenario E achieves the best overall balance of RE production, with 42 percent coming from wind energy and 47 percent coming from solar energy projects. This plan also achieves all RE milestones and reaches 65 percent in 2030. Nevertheless, the drawback of Scenario E is one of economics— it achieves the favorable RE characteristics at a cost that is 6. 5 percent higher than the least cost Scenario D. As a result, it can be concluded that the RE benefits of Scenario E are obtained at a significantly higher cost than the plan having the lowest CPWC ( Scenario D). The issue, therefore, is whether a plan could be developed that better balanced cost and environmental benefits. The plan meeting these aims is Scenario H.

I :¢: u. uilu:" u. uu• uiuui r r..'1'1
Packet Pg. 480 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric O
o00000000
00 c- I c- I OO c- I c- I 61 c- I U
w = -

I - I - I - I - I - I - I - I - I C
l0
l0
m
O
WD `~
C
N
N
a
f
o
r%
0o
o o ' 4'
o
rn
o'°
oo t ,; , i t-+
Q
f
M M , '` d' '!''
ON
a- N ''
l0 N
4J
w
G
ULL
1 O I Q B O O O O N ) W C'A', / 1 (' Oj,
N
4J ' I c1 ri 1„ L7"ti M
a-. [!} lfJ ;- tl'f tf') \ N
o
iiiiii!;
ON
4JL
o
t
Q%/ Q. // N O
A ch
i tp tn ' f ,
p N

CJ Z ' J
C
3 o
l c- I , % GJ
r
p
M
f 00 t 111
O
OC
U
p
M 1
N tn i N
W O f cn
d ( Y).: ,
f
N cI
l c- I "
CN7 U
lf')`
I l0
i l0 ' t0 ^ O
C cV
a
t
X X
a-.

C O O
L o
a
vo
o = o =
v
O a a
U O
i
O > • N > Q N O O
v
0 0 a- J ( 0
Ni
U
O I m
m
c ,
v
N
o
X
i N 7 0 C + J
r.
oC
O J
O Q >
MO
U > i
Q qA dj
f6
N
Wcn 0 .
3 C ( 0 =
N C
N
Q
N
N
m O qp
O
Q
m > N
O
N
cn
N
a x —
co
U
N
w
v2
m
w' ta c4,
a
Q
m
U
p
w _
vv
0 0
00 0 ,
o
0 0 0 r is
C L
L L
L
L L '
L ' L
L f,u0"
p
o o o o o
o o
a +
M
v
a
a
i
aiai
ai
aiai Q
c oe°:. m n n n n n O
a
tir
i,.A
Packet Pg. 481 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric qy, ' ,
q ' ' , -
W a
u"- " ` r
m'„' k ' m P r 14 u a Xa 4 '. r e r d^^ rro" h alw% r 1 + n h u r"^r
q
wa
ry
a^`rc ppa a1 y w r, ro u , 1 re
ry„"
a """
wr 9 d
pf1b. Yd"W V p', tl

4."
fi.' tl i" W" g^, w.I P I" tl" 1::% Y' X .

M'
I qP"
q,"' 6 I tl dd y; 1; W;:
a I
w o
p
q re re ru'
p,. ;,-
re u u F W u qy^ ua u
r
o u F p '
p i f
M:< w' ' ' i, d' I il w N ro u^ "' f i , " F`',' ' Y'.': a' E , : .. v a„ ^ urf u,' M °°-^ r^' ` r k o^ : i' ° a'` r 4 r. u„ 3 : a ma MW" ro° r vti r` V p

4. n„ "^
m, NA.. MY1 d' r P.' 0 zgyro` 4. F d r° N W R N: 4" I w` t' d G"* 0 ' X r 1' r v' q g a '
l N+** ll, 4 d" a
i . i : r. j : i
y ^ q, I "
odU i", kd
a a d au B: L M Mt' k4 a ' ' P 0.' 9+' ""$' A rv, I ub° u hrv r°" 4 ' ri d S„`u i w r v u° i , ' aw i G u , P r
a b
N
7 y
m - : u , u s, ' w'
F
R 6 ux q ti', P ° r a
r w i fa W ra? d ra a. w 4° u : y ,,
row r^ m Q a+. d^ i wro o n '+ a pr' r i'b m` m.,. vm a s° tl.. r°, *;,, a' a i S ao;
Q Mr f: , u ° w d r"` d r
i a e, a r' i u . b i w 1" v y r wmp M r
i ; p " r
w y'
r 8 N s". y
r- q ° '° b r r ^ N d
N,, W
µd , ,'; ` Ca' ' u
w,,, I' „, u n p.^ b; rd a u, um re rw
r a a' n+; r s •, ud w;' " `""; p° ` d G awar
u
0 r tw
fi i
m , d '
y
r w ; ,
r3ad^ q " w,+ u a d rv, N. V urto rwi , y b w t ' I a
r w q
p '
G . w p y p y I
n" , " " GM" v & m '. N '$° Y P i t , a, IY J rt M - P" 8 4 tl , 4' o u R h
ti d ` dl d° ,;„ " q» o .
r;` P " r Yr a row ° a
s s '^ r a: a ^ i a rh I i n Y. Md
t,,. gg p
w„
a f+ a ;^ w; s p.. wa^ .., M i , p , p u ' b` " ti^ r »; " f a r` r p,w¢ . . r h .•.« 4 mamb r ' W r' Eb. r, y r t ' ' N u : b p
mo- r,
ypy. 4,"' A p 4#" N:
r a^M r p:,'," u
c''+
M' iiq. p d pd r R M d I
i^r
4 bi R di;. Y" G" P
g,,.,
y t w M P ' g b, y 4"' j " p 4 '
I p, i .. an W a^ o '" I P 9 ^' 4 u" V 4 ' , , 1" u ` n 5, @ i 4 q L u r u S; d a aP w E mr° , p
w
f6 i' G ;- r$ +. r -,' p
i , *
p „
t:
rX
a g , u C o v s u e mi a " w r , ; h ^- a ..
a
n n.

C
p
p'" wz a r•' r a aaV rcm tl° u tl aar, R 1 '"
f6 "
N,' „ a1 ,,'
a, u ,
N r g a"' ,' q"
ta d a :' o " e : x
d ' k"'"' m a 7 P tl7u; u^7 e :" o " bro ' i
C" pk h, ro "- rro d p % w o i j• q '
i
i i
y m i w ru vV e tl &' eu k I s, a, '
v Y °
r i V i '
a w"" ,": a: i ; ,`` I; M°`,; c
v
s
t,. ee
q I
fiAu
y^,
4 l S w'° I4. 0 NpJ" kd ww, , .
q' !
4A1 dv
w,
A I 0 MJ° k
p
W, : p " ' w"" O k. , U tl"' Y• f
p
fl.. q a w µw: t d 9^ 1 ". a ,' rir;" ' i cd rp• rw I r i w,. r^N , r.
a f "
Cm.

M d . 1 „ b ,' N^? (' uk" nd
1^
M„` ,, ' ' tlb wu p„ 4
OC
p' °
y ry ' u w i r ro d p M '' u , i4 ^' M i i ^ a "` '
p„ ^, p ara a y sm a W° w ry da ar m{ mr i k; °„
v
1 P t
r H ^ X. u^ M X 4 rr * r l v
di r w, n w^ V V'
V II i`,l"W
I
w
p p
GJ C" „ rY r^
Nu
v^ e y" 4
Y w N ut" o
tld q
P
3" y d a " p
arc^ + ; q a w . a ar h ret a^ M Gu °¢ a
i
a u p ww• r
c rti
yq m y,, q^ py,, a mw! y a' y o- p r p^ N r °"
N, a
ry'
4,
µA I 8, Y` d %" M } i"" A, F' qMtl
I
N`, 4' M YN' R f"' I" 11, p q` N" " e' rY.

I
p'y, rrw' : fl
Q Xrv..
m ,. i . ,.... ,
u.... . '.. ^ T
k b
am,w" 4' ' 6 ' :, r" v ur" H: Jd C+ m w^ E" h 9`' N4 i ' d1 I ""-'"' p.. m t d
u.
i ti a¢,. r x' W: w u
i: u k C r ; ce n" bE,. u „ i
tl q„ P"' d" ' ' a' 6 " a y° 9" " &^ w" 0g
1 y
@ P fl ' " d" 1 q n w; A e" t. r u, "
f
m
n ° W d', a p y Q p a w . w • p... a r m
I
t ;
y,
r-I y„:.
a a-¢ d a , m* di , m d y r
i u
a a :
ryi
a e
d w 9i u 9 H a r vl ,"^ 4; µ"' Y" W + S
t a'";r- M u
ut
I— aa '« S' d ' s '
9!
r
Packet Pg. 482 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric u i ;: IIIIIIuIU vC] w
C, 1 IIUc r
G'a r C", r,' IIIINN
t•i r—W

II II ,,,,
I'. LA'
7 NI'
7 C'$
Ill lllIryI,,,,.

Illl lllupIIpII, IuIlIIII
4 4GJ L' til
ir. r
ivn p
nC . IIIIIIIVIpµ e1
m.: r'A Ma
h
f

IIVIIIV
hr1 .-+ Y19
III, IHry!
lk
rwie i
w ,-
7p" [. L'
3 7'7m

IVIIIVIIIG
wC e, i "' '
d5'
iy r " . u
C7 eti] +,„
a r-.a
lu l rr
m r-i ,"AM,

II II I III
VV 1IryI III III
M4
A A'. I „"" IN,
pttll 1l '
U
P" 7 ("1 r- 1 W
A
IIIQ
i- uN3 An L* Ta *" y N
U U p Q I U I
4 II' li, ,`
j
IIIIIIIIIpII
UII IIuI
l. LMY C'.] Cw7

UIIIPIIIPI
p
II P
CJ7' 3
W4"]
l rM '" t.
1'1
v
r,r e. l
C_'' ° i' I IXS ri li

IVIIIV,
J

IIVIIIVI'
Illll u
w Ullug
a "' u r d i uuu u i
u -.

L .
ti r u, ' .
q
C+,7 P..1 ,.
a
i. ei. [-. ur5 r r.
aP7e i(i
III nVI Illllulll , IIIIV
yy. .
5 C

LI'' WJ
q
T
e J
I'nI"
III C 7 A'. I
rl
U
IIIflIIlII., '.. '
4 IM"1 C]
UI
flIl
ro IV WN $'
r.r
IV I ll l G br e.. r
Ln c. r..
n r.a
O III InVllll y
C+
7 C,
l
Y`)
II
ln. + 11'
7 C!'A 1" J ;

IPIIIIIII , IIIIIIIIIII
m.: h.:

J 5M` i , e IFA ' i
1j
r3 If3 1f" ,^ d 1 „' U '"' . 9 w 1 i.. 7' 7a' 7 r'+3 '
p,,ry,
N

III I VIII I
y
Illllll
C " `'". k ., "
et r e `
L,,,n,, '
m"
IN' e' Ln
v ,,; WS,
a .° IIVII@I III VI
II II . I I
M - '. ' . -
M n„
u Al U I I 1 I III a
v
tie ,
w,
uu
ou' ; ' ;; „
a
S
m'
ry
n7 r,:i
II II,,, "
s: d : Y" w, r
IIIVIIIVI',,. I lu, "'
y ,
II I
w ,
q
1y, m' ,
T
w''
V
3 C-.YC 4 I{ufl
T wLJ

III/ JI
III II
II I I I 3
VUN r- II I
rt.t,.7 wrs
kC7 ri' .-. r ,
V r
i, n. - Y" in .,
a
1 L",. W n`
J
f7 f'+"I f"*d r ' lR(rtn(

Q I N II I IIIV
c. IIppU, , IIIII W
G ° e
C
7 el r° ' . ni0,
v Lr3 . y... ,. i!. ( d
y- e ,-
r
M I U „ III I f o .,
Ty
ral omll° , s,
ur a . rw "
II N, II I W m, bx7 `'' C+ C'J C+ Q r- r
VI II
y
i^+
7 blllqi MSJ Cy5 f"+
7 4V "%
IWN#N I ,... ,.'
h IWN#
N
3 M
rW
GG IAi 7 "+ C'='
i u"+ i, ib !a C"+
C M b aqq,

VI,,, ,
er rw iwa rw
I',,.

II':°; III IV r
i m; ` rn iiu"
x i
I;. W I I
r,r
ui"S - Ilu
u
r
1 ' a..
7 v i iu,
f6 p ! I'' ..

X
R_gq
ri i '
err,.
r;w
F, w, w"
d M1. f". pIINh, + 6,,
r K:.
f F,"
r
M 1 i i r, 1,.
4 Packet Pg. 483 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric iirll .., ii iir ii
This section provides an overview of the IRP process— a summary of relevant regulatory policies that guide development ofthe IRP, including legislation and related regulatory requirements established by the CEC. A summary-level description of the methodology used to perform study evaluations is also provided; the methodology is further described in Section 8. 0 of this Report.

This section also describes the public stakeholder process conducted to welcome input from consumers into the IRP process.

2. 1 OVERVIEW OF THE INTEGRATED RESOURCE PLANNING PROCESS Integrated resource planning is a process undertaken by utilities to identify the long- term plan that provides adequate resources to meet future peak demand and energy needs, while also achieving other utility goals. These additional goals include maintaining a targeted reserve margin to help ensure system reliability and achieving a reasonable balance between fiscal responsibility and environmental stewardship. In this manner, effective resource planning offers economic benefits to consumers while minimizing environmental impacts. An effective resource plan should also provide the utility with flexibility to accommodate uncertainties and risks related to future conditions, including commodity pricing risk, technological change, and regulatory change.

IRPs require the use of sophisticated analytical tools that allow comparisons of the costs, risk, and benefits among alternative supply-side and demand- side resource options that, together, may constitute a long-term plan. Most commonly, detailed computer models that simulate utility operation on an hour-by-hour basis are used to develop the long-term costs ofvarious Scenarios.

Eight Scenarios are developed and compared in an IRP analysis to determine the best long-range planfortheutility. Supply-sideoptionstypicallyincludetheevaluationofconventionalresources, RE resources, and distributed energy resources; however, in the IRP, only RE resources were evaluated based on the RE targets and sufficiency of existingthermal( natural gas-fired) generation.

Demand- side options, such as those shown in
a
a a
u u
u a
IIVIb
r m;
w, a , a ^
a e
a IIIU a
I' iarr.5r, r i i: i I" . rr, i. ari: i 1E
Packet Pg. 484 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Figure 2- 1, can include demand response programs, energy efficiency programs, and other" behind the meter" options, all of which can serve to reduce the overall utility load.

I' iarr.5r, r i i: i I" . rr, i. ari: i 1
Packet Pg. 485 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Figure 2- 1 COR' s Energy Demand and Supply
The key steps of IRP development undertaken are shown in Figure 2- 2. These steps were performed over a period of more than one year and were structured to address all regulatory and legislative requirements. Internal IRP approval by the Council is scheduled to occur in October 2018.

ESTABLISH GOALS AND OBJECTIVES
d atuby th aau n 6' th' t k ala ac c a u nac/• at, • 1aak 1 a ad 6' i xak 1 u 1y, ulat• yc u rz laa ac, ava• au rz ata1 c a: ud• atu a, a ad talz h ld• a av lv u rz at,

INVOLVE REU CUSTOMERS AND STAKEHOLDERS W IRP PROCESS AT ONSET lz a adavadual a ad;• u vvh hav a a a at• t a a th 6' utu•• u• c 1a a Q talz h ld•) a ad+ r 1c u rz th a• a• tucu atu a, 1: aduct' uk lac W11• lz h d# 1., EPV" 1[° 1F 1P 2QDQ:] ESSIES Q: QDPVS" 1[° PV" 1[° S SS UIt 1P" 1[° QDPVS 7 1 '• c that u rz t• qua• d ' ch dul a ad c at at
d atuby d taal d•; ulat• y
a ad th•• qua• u rz at Q1 g1, ',• 1aak alaty ta•; t, tc,) d atuby talz h ld• a av lv u rz at• c a ad valuat k
j
ctuv/ c ac• a
d atuby a a ut a uu rz tu a a d d 6'• d taal d u rz d la a;; d v l a a ut Illlll lllil l' llllll" III" IIIil IIIVIII"; Illil Illil llf:il lll m G' wl wl[" 1' N1C1' g w I l w N4 drVQ1.. 14 d1" wQ" rV°. f1 „ V1' gQ 1"? w wQ 1' kdlf" C1' gQ• 1• w1 k11 w1' gl„ VN If" w"` 4 dYM1" Q;!? i illllp •
1' g
T/ tI, VII NN'
Q: YMC1" w1' N1' 1' gl°` ` Q". V d1g° 11" rVC' I[ gl° rV rV1' Q°` 1 V
4 d C1' gQ" 1""? 1' N1 w1' glrV 1
w°` 4 dYb: 1f" Q" w°` u., l uw w
w gi° Ilms„ i gi: N uI w N iy iy

IDENTIFY RESOURCE OPTIONS AND PORTFOLIOS
Identify resource options to be evaluated and develop cost/ performance characteristics
Consider combinations of resource o tions ortfolios to be evaluated 1P1E 21FQD tIt PV 1L S S QD1F QD1P" 1[° QDPVS ] EPV" 1[° 1F 1P 21E1F1E 2 21E 1P1L PV A, aaly• u• c t 1a Q c• aa a;, d taal d qua at tat v, • qualatat v valuatu a) 6'• rz a
tuvaty aaaly: t a•• rza ac u ad•• a a; 6' t atual u rza• lz t a ad a adu t•y c adatu a,
III^ il; lllil ll[ m"" 0"^ il; llllll lll. llf lllil lll" m IIII""" III"" Ilfil lll " IIIIIIIII" IIIV IIIIII IIIV I' IIIIII" Ilf III III"; III

III II C
C
urgi. ; ga b i I bll• s N v' r°N N C
N wN Na w u° C` w wa Ilmw u N C`° w, r u. C° i uN 1 a Na t. v a. wa i uNi r, u° ia
III III" III^ II[, 0" III^ IIIIII" III III IIIVI III^ I"„ mlll^; III„ VIII" III^ IIII" III^ III" 0„ R O III III"" O R, u mIIlVlll l,,; III „"„
I wv w1 C iN w Iltl" a. b w
w
t:,`
K wi f' w wa ll• s u N f'° w 9
w° g uN u ga wxi w° g uN . b, ! w b° w
w uC C° v uN f'° w ; b. g N u ga. bll• s w t g u:° a u g w, r i N ° w, bN ui: u. .. wa. b. i° w w w t.

Figure 2- 2 COR' s Integrated Resource Planning Process I' iarr.5r, r i i: i I" . rr, i. ari: i 1
Packet Pg. 486 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric

2. 2 METHODOLOGY
In order to compare the economic and other merits of different resource options and portfolios, IRPs utilize various tools and methodologies to conduct detailed modeling of a power system. Such modeling allows the cost of alternative scenarios to be quantified in terms of present value cost as well as the tracking of whether a portfolio achieves other targets such as GHG and RE goals. It is possible that the least cost portfolio may not be selected if other objectives are not met, or if a slightly more costly portfolio does much better with regard to other goals.

The supply- side evaluations of generating unit alternatives were primarily performed using economic analysis tools developed by Ascend Analytics. The primary tool used in the analysis was PowerSimm, a dispatch optimization and production cost tool that allows the determination of the net cost to serve COR' s energy load and tracking of objectives such as RE and emission targets while also considering the volatility of key variables such as fuel price, power price, variability in energy production, outages, weather, and load. Additional detail about PowerSimm and the methodology utilized is provided in Section 7.

2. 3 STATE LAWS, POLICY, AND REGULATIONS
Electric utilities are subject to ongoing regulation that can arise from federal, state, and local laws and regulations. This section explains various California laws and regulatory requirements passed in recent years that apply to POUs and is summarized in Figure 2- 3. The emphasis will be on legislation, laws, and instructions directly addressing IRP preparation, primarily SB 350, PUC 9621, and the CEC guidelines to POUs for IRP preparation. This is followed by a chronological discussion of other laws, policies, and regulations that also impact long- range planning and influence culminated in the SB 350 and PUB 9621 requirements.

I' iarr.5r, r i i: i I" . rr, i. ari: i
Packet Pg. 487 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric SB338 Clean peak
AB2021 REU 10- yr
energy standard
Forecast
Requirement Filed
SB32 40% reduction
in GHG by 2030
CARB Cap and Trade
amendments
G.

SB350 Clean Energy
4" D.'m Pollution
Reduction Act
G.

CARB Cap and Trade
implemented
SBX1-2 California
Renewable Energy , 4..

Resources Act, 2011
G. G G G
AB32 GHG Global
Warming Solutions """""
Act SB1368 GHG 4 4 iiIIIIIIIIIVu
Emissions
Performance
SB1 California Solar
Standards
j ,
G G
Initiative
SB1037and AB2021
4 4' m Energy Efficiency
Standards

G G G G
SB1078 Renewable
4 4, Energy Portfolio
Standard, 2002
G G.

Figure 2-
3 Timeline of Key State Legislative Actions Impacting IRP Planning I' iarr.5r, r i i: i I" . rr, i. ari: i 3
Packet Pg. 488 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric o,'" o° o . u " NN ° nn !";; R w"":.

This Report is filed in accordance with the mandates of SB 350 ( de Leon, Chapter 547, Statutes of 2015) and associated changes to Public Utilities Code ( PUC) Section 9621. SB 350, the" Clean Energy and Pollution Reduction Act of 2015," was signed into law by Governor Brown in October 2015 and required POUs with a three- year ( 2013- 2016) average annual energy requirement of greater than 700 GWh to submit an IRP to the CEC— COR is the smallest utility required to file an IRP.

SB 350 requires POUs to file an IRP consistent with PUC 9621, with the CEC to review and determine IRP consistency. IRPs must be approved by POUs by January 1, 2019, and filed with the Energy Commission by Apri130, 2019. The IRP is to be updated at least once every five years thereafter.

PUC 9621 established several targets that affect future resource additions. These include:

Achieving a statewide target that doubles energy efficiency savings in electricity and natural gas end uses by 2030 to the extent it is cost-effective, feasible, and does not adversely impact public health and safety.

The development of IRPs that achieve GHG emissions reduction targets established by the CARB, in coordination with the CPUC and the Energy Commission that result in GHG emission reductions of 40 percent from 19901evels by 2030.

NOTE: In July 2018 the CARB staff, in coordination with the CEC and CPUC staff, issued targets that were developed around an economy-wide, 260 million metric tons of carbon dioxide equivalent( MMTCOZe) as the mass- based GHG target for the state in 2030. 4 The achievement of this target is spread across all GHG- contributing sectors, with the electric sector targeted to account for a 51 percent to 72 percent reduction from the 1990 GHG emission level of 108 MMTCOZe. This goal is shown in Table 2- 1.

Achieving a renewable resource level of at least 50 percent by 2030 for the amount of electricity generated and sold to retail customers. PUC 9621 also requires compliance with the interim renewable targets in the California Renewables Portfolio Standard Program; for periods beyond the 2018 date of this IRP, the interim targets are 33 percent by the end of 2020, 40 percent by the end of 2024, and 45 percent by the end of 2027.5 Annual updates must be submitted by the POU.

These objectives are to be met while also complying with the goals in PUC 454. 52 related to serving customers at just and reasonable rates, minimizing ratepayer impacts, ensuring reliability, strengthening the transmission and distribution system, enhance demand- side management, and minimizing pollutants with early priority on disadvantaged communities., 4 California Air Resources Board, Staff Report: Senate Bi113501ntegrated Resource Planning Electricity Sector Greenhouse Gas Planning Targets, July 2018.
5 PUC Division 1, Part 1, Chapter 23, Article 16, 399. 11- 399. 32, the interim requirements are( isted in 399. 15( b. 2. B) and 339. 30( c, 2).

I' iarr.5r, r i i: i I" . rr, i. ari: i
Packet Pg. 489 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Table 2- 1 Estimated 2030 GHG Emissions by Sector( MMTCOZe) I
iiir,,,,,i,,,,,,, i, ii,,, i iyqii ri iiiiiiiiii
IIII IIIIIII IIIII IIII IIII III II IIIIII II III IIII II ¶ I IIIII IIIIIIIIIIII uQi II „ III
r
iii IIIIII il II III uQi
u
W IIIIIIIIIIIIII III IIII ryryry I_ I4I I
lV

IIIIIIIIII IIIIIIIII
II
I
I I
II
I. II I YIII
Electric Power 108 30- 53 72 to- 51
Agriculture 26 24- 25 8 to- 4
Residential and 44 38- 40 14 to- 9
Commercial
High GWP 3 8- 11 267 to 367
Industrial 98 83- 90 15 to- 8
Recycling and Waste 7 8- 9 14 to 29
Transportation 152 103- 111 32 to- 27
Natural Working 7 TBD TBD
Lands Net Sink
Subtotal 431 294- 339 32 to- 21
Cap- and- Trade n/ a 34- 79 n/ a
Program
Total 431 260 40
CARB, Staff Report: SB 350 Integrated Resource Planning Electricity Sector Greenhouse Gas Planning Targets, July 2018, p. 23.

The CARB document also set forth proposed GHG targets for the individual POUs. These targets are shown in Table 2- 2 and include a targeted 2030 range of between 57, 000 and 101, 000 MTCOZe for COR; this amounts to 0. 191 percent of the 2030 electricity sector emissions. CARB has proposed to update these targets on a 5- year basis to coincide with the IRP filing requirements.

Table 2- 2 POU Share( in 1, 000 MTCOZe) of 2030 GHG Emissions Projected by CARB im IC IC ° IIII
I I
m @b u I . a u @ u
o'
u
0 I °
i '
u w s
IIII I
II, I
IIII
II I
J
III
I,I,U I,I,I„ I,I,I„ I,I,I, I; I,I,I,p0111„ I,I,I,I,II„ I,I,UNI; IIII
City of Redding 0. 191 57, 000 101, 000
City of Burbank 0. 430 129, 000 228, 000
City of San Francisco 0. 041 12, 000 22, 000
CityofAnaheim 1. 015 305, 000 538, 000
City of Palo Alto 0. 174 52, 000 92, 000
City of Pasadena 0. 426 128, 000 226, 000
City of Riverside 0. 918 275, 000 487, 000
I' iarr.5r, r i i: i I" . rr, i. ari: i
Packet Pg. 490 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric 1IIIIIIIIIIIpII IpI I
pI I
i
IIII
ii '
li'
li
i
l IIII IIIII 117111111111y llll III IIIIII II IlUllll IIIII Illlylll( IIUIII
i ii
d P..................... 8...... .. 9.... 9.............. Q........... 9. d w
City of Vernon 0. 497 149, 000 263, 000
City of Glendale 0. 396 119, 000 210, 000
ImperialIrrigation 1. 745 524, 000 925, 000
District
L.A. Dept. of Water& 8. 851 2, 655, 000 4, 691, 000
Power
Modesto Irrigation 1. 055 317, 000 559, 000
District
City of Roseviile 0. 452 136, 000 240, 000
Silicon Valley Power 0. 915 275, 000 485, 000
SMUD 3. 621 1, 086, 000 1, 919, 000
Turlock Irrigation 0. 629 189, 000 333, 000
District
Low target based on 30 MMTCOze for the sector; high target based on 53 MMTCOze for the sector. Emission targets for each utility are rounded to the nearest 1, 000 MTCOze.

CARB, Staff Report: Senate Bi11350 Integrated Resource Planning Electricity Sector Greenhouse Gas Planning Targets, July 2018, p. 30.

E I P d a, 00 li s
To facilitate IRP preparation and submittal, the CEC developed IRP guidelines for the state POUs.

The guideline document, entitled Publicly Owned Utility Integrated Resource Plan Submission and Review Guidelines, was issued in July 2017 ( updated in August and September 2018) and established a number of requirements to be included in the IRP Filing. These requirements include the following:

POUs must submit the four Standardized Tables to the CEC as part of the IRP Filing. These tables consist ofthe following:

1. Capacity Resource Accounting Table ( CRAT): Annual peak capacity demand in each year and the contribution of each energy resource ( capacity) in the POU' s portfolio to meet that demand.

2. Energy Balance Table ( EBT): Annual total energy demand and annual estimates for energy supply from various resources.

3. GHG Emissions Accounting Table ( GEAT): Annual GHG emissions associated with each resource in the POU' s portfolio to demonstrate compliance with the GHG emissions reduction targets established by CARB.

I' iarr.5r, r i i: i I" . rr, i. ari: i E
Packet Pg. 491 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric

4. RPS Procurement Table ( RPT): A detailed summary of a POU resource plan to meet the RPS requirements.

The four Standardized Tables for the preferred Scenario are presented in Appendix A 8.

The minimum planning period begins January 1 ofthe year that the POU' s Council adopts the IRP ( scheduled for 2018) and must go through 2030, although longer planning periods are encouraged.

POUs are encouraged to evaluate alternative resource options through various scenarios and sensitivity analyses.

The IRP Filing must include supporting information used to develop the Standardized Tables and other studies, data, analyses used or relied upon in developing the IRP.

POUs are required to report the forecasted peak demand, forecasted retail sales, other loads, and net energy for load in the EBT. The IRP must explain the demand forecast method and assumptions utilized. The CEC encourages alternative demand forecast scenarios to be part of the IRP.

The IRP must report the mix of resources in the required tables; this includes RPS procurement information in the RPT. The mix of resources refers to short-term and longterm electricity, electricity- related, and demand response products. RPS information provided must demonstrate the achievement ofthe RPS target by listing the RPC procurement targets— the projection of renewables as contained in a RPS procurement plan. The reporting of resource mix must also include the impacts of energy efficiency and demand response resources. Energy storage ( ES) and transportation electrification should also be addressed in the IRP and included in the required tables, as appropriate.

The IRP should address system reliability. This includes explaining how the planning reserve margin was established and a discussion of any local, transmission- constrained areas.

GHG emission intensities must be reported in metric tons of carbon dioxide equivalent per MWh for each supply resource reported in the EBT.

The IRP should be consistent with the goal of achieving just and reasonable rates and must include, as Supporting Information, a report on rate impacts under the IRP plan if that report was considered in the IRP planning process.

The IRP should report on the contribution of the IRP to increasing the diversity, sustainability, and resilience of the transmission and distribution system.

The IRP should be consistent with minimizing localized air pollutants and other GHG emissions with early priority on disadvantaged communities.

Table 2- 3lists the IRP Filing requirements as listed in the CEC guidelines document and indicates where in this IRP the corresponding information is provided. This table is also provided after the IRP Project Partners table at the beginning of this IRP document.

I' iarr.5r, r i i: i I" . rr, i. ari: i 7
Packet Pg. 492 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Table 2- 3 Summary of Key IRP Filing Requirements and Location in IRP iii iiiiiiiiiiii iii iiiiiiiiiiiiiiiiii'i'i'i iii ii iii'i'i'iidii" iii iiiiiiii iiiiii iii iii iiiii i ii ii ii iiiiiiiii iiiiiiiiii iii iiii iiiiiiiiiii iiiiiiiiiiiiiiii iiiiiiiiiii A. Planning adopt an IRP that ensures the utility achieves the specific goals and Section 8 Horizon and targets by 2030, including... greenhouse gas emissions reductions of 40 Objective of percent below 19901evels, and... at least 50 percent of eligible Expansion Plan renewable resources... The minimum planning horizon... begins no later than January 1 of the year that the POU' s governing board adopts the plan and ends no earlier than December 31, 2030... POUs are encouraged to undertake and present analysis.... that addresses the post- 2030 period"
B. Scenarios IRP Filings.... must meet the requirements of PUC Section 9621. POUs Section 8 and Sensitivity are encouraged to also evaluate other scenarios and sensitivity analyses Analysis to consider the feasibility and cost- effectiveness( and rate impacts) of alternative resource options."
C. Standardized " POUs must submit the following four Standardized Tables... Appendix A Tables Capacity Resource Accounting Table( CRAT)
Energy Balance Table( EBT)
RPS Procurement Table( RPT)
GHG Emissions Accounting Table( GEAT)"
D. Supporting "( 1) analyses, studies, data, and work papers, or other material that the Section 4, Information POU used or relied upon( including inputs and assumptions) in creating 5, 7; all the IRP... and( 2) additional information required by these guidelines. Appendices Supporting Information supplements the data submitted in the Standardized Tables."
E. Demand 1. Reporting Requirements... annual forecasted peak demand( MV in Section 4, Forecast the CRAT and annual forecasted retaii sales, other loads, and net energy Appendix A for load in the EBT...

2. Demand Forecast Methodology and Assumptions.

3. Demand Forecast- Other Regions. If the POU uses system modeling... the IRP Filing must include the demand forecast assumptions for regions outside the POU jurisdiction."
F. Resource the mix of resources... in the IRP [ as]... reported on the CRAT, EBT, Section 8, Procurement and GEAT, and RPS procurement must also be reported on the RPT Appendix A Plan along with] all inputs, assumptions, and methodologies ... The IRP Filing must address[:]

1. Diversified Procurement Portfolio

2. RPS Planning Requirements

3. Energy Efficiency and Demand Response Resources

4. Energy Storage

5. Transportation Electrification"
I' iarr.5r, r i i: i I" . rr, i. ari: i f
Packet Pg. 493 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric iii
iii iiiiiiiiiiii iii iiiiiiiiiiiiiiiiii'i'i'i iii ii iii'i'i'iidii" iii iiiiiiii iiiiii iii iii iiiii i ii ii ii iiiiiiiii iiiiiiiiii iii iiii iiiiiiiiiii iiiiiiiiiiiiiiii iiiiiiiiiii G. System and " Filing POUs [ must] adopt an IRP to... meets the goal of ensuring system Section 4 Local Reliability and local reliability...[ and report]:

1. Reliability Criteria...the planning reserve margin and how it was determined.

2. Local Reliability Area. The IRP Filing must identify any local transmission constrained areas in the POU service territory..." H. Greenhouse " POUs must report in the GEAT estimated emissions intensities ( in Section 8, Gas Emissions metric tons of carbon dioxide equivalent[ COze] per megawatt hour... for Appendix A each supply resource reported in the EBT."
I. Retaii Rates "... the IRP Filing must include, as Supporting Information, a report or Section 8 study on rate impacts under the IRP scenario, if that report or study was considered by the local governing authority as part of its IRP planning." J. T& D Systems "... adopt and IRP [ that] achieves the goal of strengthening the diversity, Section 3 sustainability, and resilience of the bulk transmission and distribution systems, and local communities."
K. Localized Air "... adopt IRPs to...[ achieve] the goal of minimizing localized air Section 8 Poliutants and poilutants and other GHG emissions, with eariy priority on Disadvantaged disadvantaged communities...[ discuss] how current programs and Communities policies in place... address local air pollution...[ and] how programs assist and prioritize disadvantaged communities."
Summarized from Chapter 2 of Vidaver David, Melissa Jones, Paul Deaver, and Robert Kennedy. zoi8. Publicly Owned Utility Integrated Resource Plan Submission and Reuiew Guidelines.

California Energy Commission. Publication Number: CEC- 2oo- 2oi- oo4.

2. 4 OTHER RELEVANT STATE LEGISLATION AND EXECUTIVE ORDERS SB 350 and PUC 9621 are, in many ways, the outgrowth of several preceding bills or executive orders affecting the electric utility industry. In general, these bills and orders had the effect of regulating GHG and increasing investment in energy efficiency and environmentally friendly generation and storage alternatives. These objectives were achieved principally through more stringent renewable RPS requirements. The following is a brief summary of key bills and orders, arranged chronologically within the categories of GHG emissions, energy efficiency, RE, and solar power.
o^" o" o,. u16"°"° Ilnll ii drp" u° Uo-°:'" u II IYIV.' W" ull drll.' W d r rn6 s d s E ssi rns..... d l b l r rn S I o rns (
On January 1, 2007, Assembly Bi1132 ( AB 32), the Global Warming Solutions Act of 2006 ( the GWSA) took effect, prescribing a statewide cap on global warming pollution with a goal of returning to 1990 GHG emission levels by 2020. The law required utilities to report GHG emissions to the CARB, and allowed the CARB to adopt specific regulations for reducing GHG emissions.

On October 20, 2011, the CARB adopted a regulation implementing a Cap- and- Trade Program which became effective on January 1, 2012. The program, which was implemented in phases, covers emissions from electricity generators, electricity importers, large industrial sources, and transportation fuels. The cap on emissions was established in 2013, and was designed to decline I' iarr.5r, r i i: i I" . rr, i. ari: i
d
Packet Pg. 494 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric every year consistent with reaching the 1990 emission levels by 2020. To achieve the goal, carbon allowances are distributed annually in amounts equal to the cap for that year. Some allowances are given freely, and others are auctioned off. Allowance owners may use allowances to emit carbon or sell the allowances on the secondary market.

CARB held an October 2, 2015 workshop to begin the development of 2016 Cap- and- Trade Program amendments. CARB stated four objectives: ( i) to e end the program beyond 2020; ( ii) to improve programmatic efficiencies ( covering auctions and data reporting); ( iii) to better reflect the latest technical data on global warming potential and experiences with other emissions trading programs; and ( iv) to maintain the environmental and market integrity of California' s program.

The resource plan must ultimately conform to the California GHG emission requirements stated in AB 32. The AB 32 scoping plan regulations require certain economic sectors of California to reduce GHG emissions to 19901evels by 2020 through a Cap- and- Trade Emissions Reduction Program. As part of this Program, COR must submit" allowances" for its emissions from the Station, as well as a portion of the electricity brought into California over its transmission assets. An allowance represents one metric ton of GHG emissions. The allowances are administered by the CARB.

CARB has provided a set number of" free allowances" each year in order to offset the expected cost burden of the Cap- and-Trade Program. COR has reduced its GHG emissions profile through the following actions:

Procuring carbon-free energy and making energy purchases that are low in GHG emissions; Stepping out of San Juan Coal, which makes Redding 100% coal free; Executing a contract with Big Horn before renewables were required; Increasing our largest carbon- free asset, WAPA; and,
Upgrading the Station units 5 and 6 with dual- function catalysts which reduced emissions and increased efficiency
As a result of these emissions reduction efforts, COR has been able to sell a portion of its free allowances in the Cap- and- Trade auction process with total revenues of over$ 18 million as of March 2018. These funds have been held as restricted reserves, and any revenue received from the sale of these free allowances must be used exclusively for the benefit ofthe electric utility's ratepayers, consistent with the GHG reduction goals of AB 32. Approximately$ 10. 8 million of these revenues have subsequently been allocated toward funding GHG efforts such as energy efficiency and electric vehicle ( E programs, as further described in Section 5 of this report. d r rn6 s d s E ssi rns..... E ssi rns P r r 5 r ( S . 6 Senate Bill 1368 ( SB 1368) became law on January 1, 2007. The bill provides for an emission performance standard ( EPS), which restricts new investments in baseload fossil fuel electric generating resources that exceed the rate of GHG emissions for existing combined- cycle natural gas baseload generation. SB 1368 allows the CEC to establish a regulatory framework to enforce the EPS for POUs. The CEC regulations prohibit any investment in baseload generation that does not meet the EPS of 1, 100 pounds of carbon dioxide ( COZ) per MWh of electricity produced, with limited exceptions for routine maintenance, requirements of pre-existing contractual commitments, or threat of significant financial harm.

I' iarr.5r, r i i: i I" . rr, i. ari: i 1
Packet Pg. 495 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric d r rn6 s d s E ssi rns: S . 97
SB 32, which was implemented on January 1, 2017, requires the CARB ( the designated state agency charged with monitoring and regulating sources of GHG emissions), to ensure that statewide GHG emissions are reduced by at least 40 percent below the 19901eve1 no later than December 31, 2030.

Companion legislation, Assembly Bill 197 ( AB 197), also implemented on January 1, 2017, increases legislative oversight of the CARB. In addition, AB 197 requires that the CARB, if adopting rules and regulations to achieve emissions reductions beyond the statewide GHG emissions limit, protect the State' s most impacted and disadvantaged communities, follow specified requirements, consider the social costs of the emissions of GHG, and prioritize emission reduction rules and regulations that achieve specified results.
o, o^ ";"' IV n"°\\ 11q a;. 7 I II"° II!"' II ir
z.. z.. p r s ( s a s . o
In response to the adoption of Senate Bill 1078 in 2002, a bill establishing the California Renewables Portfolio Standard ( RPS) Program, COR first formally adopted a RPS in 2003, which stated that it would meet or exceed a standard of 20 percent of the annual energy needs to be provided by state- qualified renewable resources by 2017. In response to the development by the CARB of a Renewable Energy Standard, the RPS policy was updated in 2011 to include a 33 percent target by 2020. In accordance with the California Renewable Energy Resources Act, enacted in 2011 as Senate Bill X1- 2 ( SB X1- 2), COR was required to complete the following:
i) Develop and implement a renewable energy resource plan that provides a specified average of the Electric System' s retail sales from eligible renewable energy resources. More specifically:
the first compliance period was from January 1, 2011 to December 31, 2013, during which an average of 20 percent of the Electric System' s retail sales were required to be procured from eligible renewable energy resources.
ii) During the second compliance period, from January 1, 2014 to December 31, 2016, the Electric System is required to make reasonable progress each year toward a December 31, 2016 goal of 25 percent of retail sales from eligible renewable energy resources. iii) During the third compliance period, from January 1, 2017 to December 31, 2020, with the adoption by the CEC of regulations to enforce SBX1- 2, the Electric System is required to procure eligible renewable energy resources for 27 percent of its 2017 retail sales, 29 percent of its 2018 retail sales, 31 percent of its 2019 retail sales, and 33 percent of its 2020 retail sales. iv) Legislation enacted in 2015, Senate Bi11350 (" SB 350"), requires that electricity generated each year from eligible renewable energy resources be at least 50 percent by December 31, 2030. rn r bl s P r li 5 ( 5.-
SBX1- 2, the" California Renewable Energy Resources Act," was signed into law by Governor Brown on April 12, 2011. SBX1- 2 codifies the RPS target for retail electricity sellers to serve 33 percent of their loads with eligible RE resources by 2020. As enacted, SBX1- 2 makes the requirements ofthe RPS program applicable to POUs.

SBX1- 2 requires each POU to adopt and implement a RE resource procurement plan involving the procurement of at least the following amounts of electricity products from eligible RE resources, which may include RE certificates ( RECs), as a proportion oftotal kilowatt hours sold to the utility's retail end- use customers:

I' iarr.5r, r i i: i I" . rr, i. ari: i 1'1
Packet Pg. 496 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric i) over the 2011- 2013 compliance period, an average of 20 percent of retail sales from January 1, 2011 to December 31, 2013, inclusive;
ii) over the 2014- 2016 compliance period, a total equal to 20 percent of 2014 retail sales, 20 percent of 2015 retail sales, and 25 percent of 2016 retail sales; and iii) over the 2017- 2020 compliance period, a total equal to 27 percent of 2017 retail sales, 29 percent of 2018 retail sales, 31 percent of 2019 retail sales, and 33 percent of 2020 retail sales.

More recently, SB 350 increased the statewide RPS to 50 percent by 2030.) In addition to meeting the RE percent procurement target, the RPS established certain Portfolio Content Categories ( PCC) that further divided the eligible RE resources to be procured and established certain limits. The PCCs essentially classify renewable resources into one of four categories based on location of the interconnection and other factors as follows:

PCC1: products must be bundled and the POU may not resell the energy; the resource' s first point of interconnection must be to a distribution system serving end- users within a California balancing authority area; RE products having a first point of interconnection outside of a California balancing authority area must be scheduled hourly into the area without substituting electricity from another source.

PCC2: products must be bundled and interconnected to a network within WECC; the electricity must be scheduled into a California balancing authority area; the products must have a first point of interconnection outside of a California balancing authority area, and the electricity must not be in the portfolio ofthe POU prior to the date of contract or ownership agreement; the electricity must be scheduled into the California balancing authority area within the same calendar year that the electricity is generated, and the energy may not be sold back by the POU.

PCC3: unbundled RE credits and products that do not meet the requirements of PCC1 or PCC2.

PCCO: RE under contract prior to June 1, 2010, provided that the resource meets the RPS eligibility requirements in effect when the procurement agreement was executed; subsequent amendments do not increase the capacity or production, or substitute a different resource ( any such change would be classified into PCC1, 2, or 3 and follow the portfolio balance requirements); and the duration ofthe contract may be extended ifthe original contract was for 15 years or more.

For the 2017- 2020 period, a minimum of 75 percent of the RE must be classified as a PCC1 resource and a maximum of 10 percent can be a PCC3 resource.

To meet the RPS requirements, the Council passed Resolution 2011- 197" Resolution of the City Council of the City of Redding to Revise the Renewable Portfolio Standard for the City of Redding' s Electric System" on December 20, 2011. The resolution adopted RPS targets of 20 percent averaged) from 2011- 2013; 25 percent in 2016, and 33 percent in 2020 and thereafter. 6 In meeting these targets, COR is allowed to apply Excess Procurement( see Appendix E; Optimal Compliance Measures) from one compliance period to subsequent periods and the Council adopted a Cost Limitation such that the annual RPS expenditure should not require rate increases of more than 1. 5 percent per year at any time during the life of the considered RPS procurement, and the 6 RPS Policies& Procedures, RPS- 001 Renewables Portfolio Standard Procurement and Enforcement Plan ( Version 3) REU Resources Division, June 5, 2018, pp. 3- 12.

I' iarr.5r, r i i: i I" . rr, i. ari: i 1
Packet Pg. 497 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric kWh cost of RPS procurement( including delivery, firming, shaping, or storage) should not exceed 75 percent of COR' s current kWh retail residential energy charge.

Resolution 2011- 197 also adopted the following Enforcement Policies:

A. COR will make a reasonable effort in the context of Good Utility Practice to be in compliance with the requirements of SBX1- 2.

B. COR will report annually to the City Council on its status of compliance with SBX1- 2.

C. COR will notify the City Council of any potential for lack of compliance with the requirements of SBX1- 2.

D. COR will explain to the City Council the reason for any noncompliance with SBX1- 2 and submit a plan of corrective action.

E. At such time,the City Council will direct staff on its recommended course of action.
o," o" o ! u u ru:; uu!
z.... s p ( s . y
On August 21, 2006, Governor Schwarzenegger signed into law California Senate Bi111 ( also known as the" California Solar Initiative"). This legislation requires POUs to establish a program supporting the SB 1 goal to insta113, 000 MW of photovoltaic energy in California. POUs are also required to establish eligibility criteria in collaboration with the CEC for the funding of solar energy systems receiving ratepayer- funded incentives. The legislation gives a POU the choice of selecting an incentive based on the installed capacity or based on the energy produced by the solar energy system, measured in kilowatt- hours. Incentives would be required to decrease at a minimum average rate of 7 percent per year. POUs also have to meet certain reporting requirements regarding the installed capacity, the number of installed systems, number of applicants, the amount of awarded incentives, and the contribution toward the program' s goals.

In response to SB 1, the Council implemented a Solar Rebate Program in 2008. The program was to offer rebates and incentives over a 10- year period beginning in 2008. This program was to be paid for through a rate surcharge of$ 0. 00125 per kWh starting in October, 2007. Aggressive solar rebates were offered through September 30, 2010. In 2010, the Council approved a 700 kW project at the municipal airport and, combined with several other scalable sized projects, effectively exhausted funds available to incentivize solar photovoltaic projects with rebates through July, 2014. In August, 2014, the rebate program reopened with $ 700, 000 in funding; those funds were exhausted in less than two business days through 105 applications with a total installed capacity of

1. 3 MW.

Since that time, growth in installed PV systems has continued. On September 13, 2016, the solar rebate program again re- opened, this time providing a $ 0. 50/ watt rebate, up to maximum of 5, 000. After meeting the goals of SB 1, the new program was closed for new applications on October 31, 2017, with approximately$ 10. 1 million in rebates having been provided over the life of I' iarr.5r, r i i: i I" . rr, i. ari: i 13
Packet Pg. 498 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric the program which helped to provide more than 8 MW of installed capacity at over 800 customer locations.

As defined by SB 1, COR is fast approaching the 5% net energy metering ( NEM) ( 1. 0) cap of 12. 7MW and it is anticipated that cap will be reached around the 3rd quarter of 2020. Prior to hitting the cap, a successor policy will be developed and submitted to Council for approval and early adoption to ensure a smooth transition.
z... z y y ( s . o; zoz. y
Senate Bill 1037 ( SB 1037) was signed by then Governor Schwarzenegger on September 29, 2005.

California Assembly Bi112021 ( AB 2021), signed by then Governor Schwarzenegger on September 29, 2006, requires that POUs establish, report, and explain the basis of the annual energy efficiency and demand reduction targets by June 1, 2007, and every three years thereafter, covering a ten-year future horizon. A subsequent bill has changed the time interval for establishing annual targets to every four years. Reporting requirements under AB 2021 include: ( i) the identification of sources of funding for the investment in energy efficiency and demand reduction programs; (ii) the methodologies and input assumptions used to determine cost- effectiveness; and iii) the results of an independent evaluation to measure and verify energy efficiency savings and demand reduction program impacts.

E r
y E i 6 rn y 56 rn
In addition to the impact on demand from solar power, COR has several ongoing EE and DSM programs that help manage demand on the COR system. These efforts are described in detail in Section 5. 0.
z... p k ( s
SB 338, passed by the California Senate on September 6, 2017 and approved by the Governor on September 30, 2017, requires the PUC Commission and the governing boards of local publiclyowned electric utilities to consider how energy storage, energy efficiency strategies, and distributed energy resources can help utilities meet peak demand electricity needs while reducing the need for new electricity generation and transmission facilities. COR has seen a reduction in peak demand over the last several years and forecasts very little growth from these levels during the planning horizon. As a result, COR currently possesses the required level of resources ( including energy storage and energy efficiency programs) to meet future expected peak demand requirements.

2. 5 FEDERAL ENERGY LEGISLATION
Currently, the state requirements described above dictate the renewable and emission standards for POUs in California. It is possible that in the future, more restrictive requirements could be mandated at the federal level resulting from new laws or regulations implemented by the U.S.

Environmental Protection Agency( EPA).

City of Redding Report to Redding City Council, 4. 5( bJ— Adopt Resolutions to Terminate SolarSurcharge, November 7, 2017.

I' iarr.5r, r i i: i I" . rr, i. ari: i 1
Packet Pg. 499 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric In 2009, the EPA issued an" endangerment finding" that, it argued, allowed it to regulate emissions of GHG under existing law. This finding, and other findings and proposed rules, were challenged in court. Ultimately, it was found that the EPA had the authority to regulate GHG emissions from sources that were already covered under other emissions programs. Meanwhile, the EPA developed a set of rules and regulations called the Clean Power Plan(" CPP"), which outlined specific emissions reductions targets for every state and required states to develop their own plans to achieve the targets. The CPP was also challenged in courts, with the result that a" stay," delayed implementation while the CPP worked its way through the courts. Before a decision was reached on the legality of the CPP, the EPA, under the administration of President Trump, announced it would repeal the CPP and replace it with other regulations. The repeal is still at the proposal phase as of the publication of this Report.

GHG regulation at the federal level remains uncertain and, therefore, it is difficult to predict the extent to which future federal policy on the subject could impact operations. This IRP was prepared assuming that California GHG emission reduction requirements would be the most stringent applicable requirements.

2. 6 PUBLIC STAKEHOLDER PROCESS
This IRP benefited from the public input process. The stakeholder process involved seeking groups who have an interest in future resource plan (Stakeholders) and inviting their participation such that all relevant issues were identified and addressed. Through this process outlined in Figure 2- 4, participants were engaged and involved early in the development. The end result was that the concerns and perspectives of all Stakeholders were considered, with the resulting resource plan achieving what is considered to be an appropriate balance of utility and Stakeholder objectives.

I Y Yd E M Jksrs r t se st G srs ders vwe a apact?
pao a; o a wo Ir1 wao°Ey 9, t st, rs ders a t us?
I' 0 Y O Y tirsw vw Yl t s s rs ap vrs ve asve t a a?
i Illllllm
1IIIIIfPPPP+frfrfrff+ r r+rrr,-,,,, i y U
J IIIII I°. i
1 1111, 11
I JJ I ll.l I I I I 111 1 I
u
llllll,,,,,,,,,,,
rraqi 1`u
l uit„ i,ll,l il) 1
iiiii
u
IIIII
luwvu P u° au opa uouw Sa a uuw VauVu y
o a u uwa I s/; ouw u° uw Ecouwou u F uVau u y
v Vopa auouw PV uw
a11 ,, „»»
l1 L V I' 6ou° V; ouw ud u° uouw
ou u a uwu auouw PV uw al au; ouw ud u° uouw
Figure 2- 4 Stakeholder Integration Process
In seeking Stakeholders, COR actively sought input and participation from several types of constituents. Actions taken to reach out to potential Stakeholders included a dedicated web page on the COR web site that included information about the process, FAQs, presentations, flyers, feedback forms, surveys and survey results, as well as live recordings of stakeholder meetings.

I' iarr.5r, r i i: i I" . rr, i. ari: i 1
Packet Pg. 500 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Stand- alone flyers, bill inserts, radio spots, and social media announcements were used to reach out to customers. A dedicated e- mail was created for customers to contact the IRP team directly.

Participants who joined the stakeholder planning process illustrated in included those involved with economic development and commerce, customers, developers, governmental agencies, consultants, and other interested parties. Stakeholders participated in meetings held in February and June of 2018. Each meeting addressed different aspects of IRP planning. At the first meeting, pictured below in Figure 2- 5, the primary objectives included:

Increasing Stakeholders' understanding ofthe IRP process, key assumptions, and challenges Understanding Stakeholder concerns and perceptions
Providing a forum for productive Stakeholder feedback at key points in the IRP process to inform decision- making
Explaining the need to comply with Commission rules and requirements i
i, 4
r
i,, IM
r'%/ J' ",. 1, , d' l
J
i f
r; i
uy,, x r i
r«` i
W ti , ,,,,, r °
i
I i
i da
r
i
i/
r"
i;
Figure 2- 5 First Stakeholder Meeting February 23, 2018 At the second meeting, Stakeholders listed in Figure 2- 6 responded to the modeling results and overall preference of planning scenarios. In both meetings, there were valuable contributions made by the participants. As part of the public process, a Stakeholder Feedback Form was presented to all participants. The results of these forms were tallied and are included in Appendix B. u w
u u
Figure 2- 6 Stakeholder Engagement Participants
I' iarr.5r, r i i: i I" . rr, i. ari: i 1E
Packet Pg. 501 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric iii° iii ii ... iir ... ii ii iiriii II° iii ii
The city of Redding is rural area located at the northern end of the Sacramento Valley, approximately 160 miles north of Sacramento and 230 miles northeast of San Francisco. As the county seat of Shasta County( County), Redding is the major trade and commerce center for the northern central and northeastern portion of California. The city is situated in the midst of a vast recreational area that includes nine national forests, six wilderness areas, two state parks and one national park. Redding experiences hot summers and mild winters with an annual precipitation of approximately 34.2 inches. Elevation within the area varies from 400 feet above sea level to 10,466 feet at Lassen Park, just outside of the County.

Since 1921, the City of Redding Electric Department has provided electric service to its community, and now serves a population of approximately 92, 000 through the efforts of 187 employees. The legal responsibilities and powers of COR' s Electric Department, including the establishment of rates and charges, are exercised through the five-member Council that is elected City-wide for staggered 4- year terms.

The electric system ( Electric System) includes generation, transmission, and distribution assets.

COR also purchases electric power and transmission services from others. For the Fiscal Year ended June 30, 2017, approximately 44, 200 customer accounts were served, with a total sales of 746, 000 MWh, and realized a peak demand of 231 MW.

The electric resources used to meet the power requirements of customers include generation supply resources, RE resources, contractual power purchases, transmission assets, and natural gas supply facilities. A summary ofthe power supply resources and the percentage of total energy supplied by each during the calendar year ended 2017, are presented in Table 3- 1. Figure 3- 1 shows the location of existing resources and Figure 3- 2 shows the mix of energy production in 2017.

I > I a f: I i, I r a r, i i r, a ri: i 7 ca P r 5 rr I r a r,r r.5 Y r, ri 3..'1
Packet Pg. 502 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Table 3- 1 Power Supply Resources( Calendar Year 2017)
IIII III III IIIIIII d
u
j
ii iii ii ii iiiiiiiiiiiiii iiiiiiii
w I II
IIII III III III II IIIIIIIIII IIIIIIIIIIII lu ii iii Im i IIIII I nl lll ll llllllllll Illlllll lllllllll III
m m , m
m W IIIIIII IIII IIII IIIIIIIIIIIIIIII IIIIIIIIIIIIIIIIIIIIIIIII III IIII IIIII II IIIII Irllll Redding Power Station z ( U1- U6) 183. 1 186 25%
Whiskeytown ( U9) 3. 5 26 3. 5%
M- S- R PPA/ San Juan 3( Now expired) 0 0 0%
Total Generated Power l 186. 6 212 28. 5%
w
uuilllll ui ui uu iuui uu uu uinui uu iuui uu ui uu iuu ui u liuu uui911 WAPA Base Resource 4 128. 5 369 49. 5%
M- S- R PPA/ Big Horn I Wind Project 23. 0 164 22%
Total Purchased Power l 151. 5 533 71. 5
I m w w
uum
l.. . @ „ m W W W m 0
I IIII IIIII IIII Illlnlll IIII Ilm IIIIIIII IIII IIII IIIIIIIIIII IIII Ill lll llli llll lllllllllll Illlnlll IIII IIIIIIII III IIII IIIIIIIIIIIIIII IIIIIII IIIIIIIIII II II IIIIII Illl lllu IIIIIIIII IIIIIII IIIIIIIII II IIIIIIII IIIIIIIIIIIIIIIIIIII IIIIIIIII IIIIIIIIIIIIIIIIIII IIIIIII II IIIII III IIIII l Totals may not add due to rounding.
z Capacity listed is nameplate capacity( EIA860 defined) for Redding Power Station. 3 The City' s interest in San Juan Unit No 4 was terminated effective December 31, 2017. 4 The hydro- based contract with WAPA is for 128. 5 MW, but the average summer capability is 88 MW.

Source: City of Redding
I > I a f: lii, I r ar, ii. r, a ri: i 7 caPrSrn I r ar, rir.S Ylr, ri 3..

Packet Pg. 503 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Fa e/...__............... ...„ .....,..,.,.,.,. ..._.... .......,. ,.,.,.,.,.,.,.,.,....._.._.._ io
i(e
uafli . .

It ..,
IP(A 141NI1 i{1'N
Er, r. i r ., i, i, IVIJI IAtd
v'
4 r(} Ariy1
fe ";
r bl,/
t
In e
io
1, 1,., i, zn... ail
C u9mna AJI„ I i iiiYRiG:

QI) I 1 4CIIId I/1
4 IUrtFi',
aJ l 1 iuMl
LVe L" y . .
ff
9k JA
RJl'.` IAILet
rnr .. ..

U
IIi YiX f .

Ya
U ¢/
u Yif va s.
n
m
n I fil Id l , ,,
i5. . . i
19iWnufl rl I Yku41'
x hl lA. qh fA . I MiW:.
m,
ph 4 . l,.
4 Figure 3-
1 Power Resource Locations( Self- Owned and PPA Resources) o a f i jft(
l lll,ii i ra
p ul ul
rrrr,;
Figure 3-
2 Mix of Energy Production by Generation Type, 2017( Calendar Year) I > I a f: lii, I r ar„ ii. r,
a ri: i 7 caPrSrn I r ar, rir.

S Ylr„ ri 3..
3 Packet Pg. 504 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric

3. 1 GENERATING FACILITIES
o . o, n IIII,„ ar IV u n r IV uII
The Station is the primary local generation resource, with a total station nameplate capacity of 183. 1 MW. The Station is comprised of: (1) a two- on- one combined cycle power generating station with two Siemens SGT- 800 gas turbines ( with nameplate capacities of 42. 5 MW and 40 MW, respectively) coupled to a 26.8 MW nameplate capacity GE steam turbine, and three GE Frame 5 simple cycle combustion turbines, with a combined nameplate capacity of 73. 8 MW.

The first SGT- 800 gas turbine ( Unit 5) was placed into commercial operation in June 2002. The second SGT- 800 gas turbine ( Unit 6) was placed into commercial operation in August 2011. The Frame 5 combustion turbines were placed into commercial operation in 1996 ( Units 1, 2, and 3).

All units are currently natural- gas fired only.

The initial steam unit( Unit 4) was acquired and converted from biomass fuel to gas in 1991. Both generator Units 5 and 6 can operate in combined- cycle mode to provide steam to Unit 4. When Unit 6 was placed in service, the original fired steam boilers were retired.

On February 9, 2018, testing and verification of a newly installed SCR Dual-function NOX/ CO catalyst system was completed for Units 5 and 6, replacing the previously installed SCONOX emissions control system. The catalyst system lowers emissions and increases efficiency. The Station has a cooling tower fed by City water to meet its cooling needs. o . 00," \ IV u^ II° f
ar u ' uar. fr.

COR owns and operates a 3. 5 MW hydroelectric generating plant located at the U. S. Bureau of Reclamation Whiskeytown Dam near Redding. This project was completed in 1986 and has produced an average of approximately 26 GWh annually since that time. In some years, temporarily high flow releases have been captured by the flexibility ofthe dual runners installed in the unit and additional energy has been generated. Under minimum flow release restrictions, it is estimated the facility could produce approximately 10 GWh per year.

COR has received full CEC certification for the Whiskeytown facility as a California RPS Eligible renewable resource. The facility has been registered with the Western Renewable Energy Generation Information System ( WREGIS), and the associated renewable energy credits ( RECs) will either be retained for RPS compliance purposes or utilized for wholesale sales.

3. 2 RENEWABLE ENERGY RESOURCES
Since 2003, COR has aggressively pursued cost-effective and self-owned or purchased renewable resources through adopted RPS targets. The initial RPS target, in response to SB 1078, was 20 percent of annual energy needs by 2017. Based on the CEC' s subsequent Renewable Energy Standard and SBX1- 2, the target was modified in 2011 to be 33 percent by 2020 with intermediate targets including 27 percent in 2017, 29 percent in 2018, and 31 percent in 2019. Four years later in 2015, a 50 percent RE target was adopted for the end of 2030 in response to SB 350. Currently, COR has a diversified renewable portfolio comprised of the following resources:

Hydroelectric resources ( owned)
Hydroelectric resources ( purchases)
I > I a f: lii, I r ar, ii. r, a ri: i 7 ca lr5rn r ar,rir.S Ylr, ri 3...

Packet Pg. 505 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Wind power ( purchases)
Local solar projects ( customer-owned does not qualify) Current zero carbon and renewable resources are summarized in Table 3- 2. The WAPA large hydro does not qualify as a RE resource but is considered a zero carbon resource. Behind-the-meter solar does not qualify for utility RE. In calendar year 2017, approximately 75 percent of retail sales were supplied from zero carbon resources, in part due to a prolific year for hydropower resources. The current RPS targets under SB 350 are expected to be satisfied for the remaining compliance periods through 2020. With the inclusion of the above- described projects and contracts, current projections indicate that it has sufficient renewable resources to meet the current minimum RE procurement targets mandated by state law through 2024.

Table 3- 2 Current ( Calendar Year 2017) Zero Carbon and Renewable Energy Resources d

IC IC IC C C
IIII I II III III II IIIIIIIIII IIIII III III IIIIII ulll IIII
I Im
II
I i II IIIIIIIII II III IIII IIIII II II IIIIIIIIIIIIIIIIII III
i : @ : .. sw M : IIIIIIIIIIIIIIIIIIII IIIIIIIIII IIII II I IIII III III IIIII IIIIIII IIII IIII III IIIII IIIIIII IIIIIIIIII IIIII II IIIII IIIIIII IIIIII Whiskeytown Dam Hydroelectric 3. 5 26 3. 5%
Owned)
M- S- R PPA/ Big Horn I Wind Wind 22. 0 164 22%
Project Purchase) firmed and
shaped MV1
WAPA Base Resource Hydroelectric 7. 6 1%
Small Hydro) Purchase)
IIIIIIIII """` IIIIII
ar M

IIIIIIIIII IIIIII IIII IIIIIII IIIIIIII III III IIII I III IIIIII IIII IIII IIII IIII III IIIII IIIIIII IIIIIIIIII IIIII II IIIII IIIII WAPA Base Resource Hydroelectric 128. 5 361 48. 0%
Largo Hydro) Purchase)
Local Solar Projects ( Zero Solar PV 10. 2 89. 4 NA( behind the Carbon Resource meter)
Total 165. 2 640 75%
As explained in Section 2, the solar initiative program was adopted in 2007 designed to meet SB 1 requirements for the promotion of solar photovoltaic projects through rebates and incentives. Over the last several years, more than 800 solar PV projects have been installed with a combined capacity of over 10 MW. The projects range from 1 kW to 700 kW and are located on City- owned and customer- owned facilities throughout COR' s service area and as such, those project have fulfilled the SB 1 requirements.

I > I a f: lii, I r ar, ii. r, a ri: i 7 caPrSrn I r ar, rir.S Ylr, ri 3..

Packet Pg. 506 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric

3. 3 CONTRACTUAL PURCHASES
In addition to owning and operating generating facilities, energy needs are supplemented through contractual purchases, as further described below.
o° o N, ru° u \ uu:; un i', u.. rr.

The Big Horn I Wind Energy Project( Big Horn) is a 199. 5 MW( nameplate capacity) wind project comprised of 133- 1. 5 MW GE wind turbines, located near the town of Bickleton, in Klickitat County, Washington. COR participates in the purchase of a 35 percent share of the output from the Big Horn I Project through a power purchase agreement( PPA) with the M- S- R Public Power Agency the M- S- R PPA), a Joint Powers Agency( JPA) of which COR is a member along with Modesto Irrigation District and the City of Santa Clara.

COR' s share of Big Horn wind energy equates to approximately 70 MW( 22 MW firm capacity through a firming and shaping agreement) of the output. Power deliveries commenced on October 1, 2006, and will continue through September 30, 2026, although a five- year extension is possible.

Ifthe Big Horn I Project is extended, the M- S- R PPA will have a right of first offer to negotiate a longterm power purchase for such repowered project.

Big Horn interconnects with a high voltage transmission grid through an 11- mile transmission line at Bonneville Power Administration' s ( BPA) Spring Creek Substation. Through the shaping and firming agreement between M- S- R PPA and Avangrid Renewables, Inc. (Avangrid is an intermediate contracting entity that purchases energy from Big Horn and provides it to M- S- R PPA), Avangrid receives energy from the Big Horn, as generated, and delivers flat energy product to M- S- R PPA at the California- Oregon border pursuant to firm pre-established delivery schedules. A portion ofthe California- Oregon Transmission Project( COTP) transfer capability ( discussed below) is used to provide for transmission ofthe output from Big Horn from the California- Oregon border to COR.

The Big Horn Project is operated within the BPA balancing authority area. On October 1, 2009, BPA began imposing a wind integration charge for the purpose of recovering its costs to provide withinhour generation balancing services for wind generators. The wind integration charge is currently embodied in BPA's variable energy resource balancing service and the currently applicable wind integration charge is set at$ 1. 48/ kW- month. M- S- R PPA has entered into a series of amendments of the PPA with Avangrid whereby M- S- R PPA has agreed to pay, subject to certain caps and limitations, the first$ 1. 20/ kW-month of any wind integration charge imposed by BPA, Avangrid has agreed to pay the next$ 1. 20/ kW-month, and M- S- R PPA and Avangrid will equally split any wind integration charge exceeding$ 2. 40 per/ kW- month.

Through a collaborative effort between Avangrid and M- S- R PPA, Big Horn has obtained California RPS certification as an" Eligible" renewable resource by the CEC. Big Horn has been registered with the WREGIS by Avangrid with BPA acting as the Qualified Reporting Entity. The RECs are transferred from Avangrid, the originator, to M- S- R PPA, and finally to the members of M- S- R PPA, for either retirement or wholesale sales by such members. o° oo," \! 1' 1 n,: r^. . arii, u: N n, ar ll. 0 um ' o u° COR receives a significant portion ofits power supply from the Central Valley Project( CVP) pursuant to a contract with the Western Area Power Administration ( WAPA). The CVP, for which WAPA serves as marketing agency, is a series of federal hydroelectric facilities in Northern California operated by the U. S. Bureau of Reclamation. Service under the current agreement with I > I a f: lii, I r ar„ ii r, a ri: i 7 caPrSrn I r ar, rir.S Ylr„ ri 3.. E Packet Pg. 507 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric WAPA began on January 1, 2005, and continues through 2024 ( an extension beyond 2024 currently in process). As of January 1, 2015, WAPA revised its allocation percentages, and the current allocation of energy available from WAPA is 8. 159%. In calendar year 2017, 336. 1 GWH of energy were received from WAPA.

Delivery of purchased power from WAPA is made at two interconnection points with WAPA: the Keswick Dam Switchyard— a WAPA facility located approximately 0. 5 miles from COR— and at the Airport Substation, located in the southeastern part of the service territory. Power is transmitted to distribution substations over COR' s 115 kV distribution lines.

Energy made available for delivery under its agreement with WAPA is on a pay-and-take basis and is subject to the annual hydrology of the CVP. For planning purposes, WAPA provides estimates of projected deliveries based upon WAPA' s assessment of current and expected hydrologic conditions.

As a result of recent drought conditions in California, deliveries in recent years declined before strongly rebounding in the 2016- 2017 Fiscal year.

COR' s contract with WAPA includes power from numerous hydroelectric plants around the Sierra Nevada Region, some of which ( Nimbus, Stampede, and Lewiston) qualify as a California RPS Eligible" renewable resource. A contract is in place to receive the RECs from WAPA for the qualifying hydroelectric projects. These RECs aid in meeting RPS targets.

I w f
In an average water year, approximately 32 percent of COR' s power supply resources are derived from hydroelectric generation, including the Whiskeytown Project and power purchased from WAPA. Hydrology in California can be highly variable from year to year. Table 3- 3 indicates, for example, that during four consecutive years of drought, generation received from the WAPA CVP was significantly reduced.

Table 3- 3 Historic Deliveries from WAPA CVP
I
IIII
III II II II IIIIIIIIII IIII IIIIIIIII IIIIIII III Im i Ym iii 2012- 13 244
2013- 14 178
2014- 15 158
2015- 16 170
2016- 17 338
Estimated 2017- 2018 237
Source: City of Redding, Fiscai Year, July 1- June 30
Note: COR' s allocation increased from 7. 74% to 8.20% on Jan 1, 2015.

In the event of reduced hydroelectric generation, it is necessary to generate additional energy or to purchase additional energy on the wholesale market to meet its retail sales and load obligations, and such actions can significantly increase costs. This is a consideration when planning for future resources and when assessing the risk of RE production from hydro versus other renewable resources such as solar or wind. However, there has been shown to be a direct correlation between the pressure systems that build along the West coast during a drought and the output from wind I > I a f: lii, I r ar„ ii. r, a ri: i 7 caPrSrn I r ar, rir.S Ylr„ ri 3.. 7 Packet Pg. 508 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric farms located in the Pacific Northwest. Thus, the impact of drought conditions in the Pacific Northwest tends to also result in decreased wind generation from COR' s share of Big Horn. During such periods, there is sometimes a need to purchase replacement energy from the wholesale market or generate replacement energy at an additional cost. o° o° ,;". I,
COR is a member of the Northern California Power Agency( NCPA), which owns certain electric generating projects. COR participates in NCPA' s state and federal legislative and regulatory efforts and is currently moving toward participation in a near-term solar project that is anticipated to be in- service in 2021— this project is further described in Section 7. 0.

3. 4 TRANSMISSION ASSETS AND ADEQUACY
The transmission facilities owned or contracted for are described in this section. Owned transmission facilities are shown in Figure 3- 3.

I I U ' ll` r rl is ic r1 w 1 j,1'
o%/"/%iiio/! i/%%%/%/%%% /- ,/, O////////// O%///%////////////,/////////////,///,%% j ti ,./ r% j
aesc direction ... a aG duectio a Ca aci
i i„ / ji.'.. ., . .,/ i,,. I
W P. p. h".. ..,.
a I r ms 1 o st r io
j
B SC3TP I ... N to S ... 3.9 S t[ r N...... 31..
g
CUP I ImPpd 1$ 7 Ex{ rod 139
q4inda .._'„...
r... .

PACI __. NtdS. /,........ .............. Stohd...... .. ._.. .. r
A .

V . / `
NP iS
d Y
f// i
i
f,
i
Figure 3- 3 Transmission
o" o,. A! 1' 1 II" i°. run^. u i^.^. u., ru ;, u u runn ' 1o m, COR is a customer of WAPA, who provides access to WAPA' s high voltage transmission via an interconnection with the system. Through a transmission service contract, electricity needs that are not met by generation assets within the service area imported. The transmission agreement, signed August 1995, is effective for 40 years, though either party can opt out after giving a 5- year notice. The contract specifies that WAPA will provide, on a firm basis, both Long-Term Firm Transmission Service and Short- Term Firm COTP Transmission Service, detailed in Table 3- 4. The details of the contracts are summarized in Figure 3- 4. The WAPA transmission system is part of the I > I a f: lii, I r ar, ii. r, a ri: i 7 caPrSrn I r ar, rir.S Ylr, ri 3.. f Packet Pg. 509 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Balancing Authority of Northern California ( BANC) balancing authority area ( BAA) and interconnects with the California lndependent System Operators ( CAISO) BAA.

COR is also a member of BANC, a joint powers authority with members that also include the Sacramento Municipal Utility District( SMUD), Modesto Irrigation District( MID), Roseville Electric, Trinity Public Utility District, and the City of Shasta Lake ( COSL). BANC began its operations on May 1, 2011, and is now the third largest balancing authority in California, serving a peak load of approximately 5, 000 MW and 763, 000 retail customers. BANC' s operations extend from the California- Oregon border to Modesto, California, covering most of the larger utilities in the Central Valley region north of Modesto.

I > I a f: lii, I r ar, ii. r, a ri: i 7 caPr Srr I r ar, rir.S Ylr, ri 3.. d Packet Pg. 510 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric i
tJ r „
r d, / ` t ,/
r i;
1 r % l '' ff', ' j r
r . l
v
f i 1%
f l ii4,/ G G
l
td6 1 H / ri" r l ' i i"
rGrr
s n
7i/ si,.,, J1 1 0,. , ' i.. i ,,,, 9 r
y
t p
1V, N t
t Jr,
bP"
i u N w
j ,,,, ,, u
r
w ,
l/
r4" l,r
i
t
r,
j `
n,/'
li fr l g r 1f f l, a l i JFT j
h
r l lJ ii`
1, // l r y
iri1 U „ i
r
u y d
i l J f` I
y1/ u b( i
Ui o i o r i 6
h r gi/ N e w
a1 r ar
h
a 1
a/ r
f 0(
i
i6 J ill' j .
1%` 1 ' , t,( , y I
f' u%
r
i' yJu I ij `/ 6'
o , d r; //, p
jf , N i
y i ( ''
r/ P1n i1 ' 117i i,
n r
ii I / r, l r ... i h i ( 6
Y / 1' i
r , i % // ; N° i
il y /
t
f ! l
v
9iY
i i ir i
l Y+
t` 1' i i'/ i1
r. r yj %
t fi/ , f
r
1r,'
I ,
I.(y r j
ll ld/ i i
ir / f fr/ li` / IV j
iJl r w% va °
i l
r
i i i""
ri"'" l
y/ f J l yrf/ lY '%` d /% c Ul!/ J
f rr i
q 1 / r' i j JNl l` y,`/ 3o r%/ i , d' I/ i il if °%id i T
i' i!'
f
rh%, I W w i 1 i ir ir// rr i / iv oc % Jt
Jlf' r
d pr ri /, f 1/?? ill % (/ JJ'' rOlJllii, r, r i
r ,;
i +"/ i
f,!a r / f
1 i i i
f/
i r // / //
a 1y, v
lI'.

Hi v` I/li%l
p
r Nll%I ar1 o i %/f;j
d r
ii , ,,, J^
r ,
HN: i i/// /
yr
frl 1J i
l/
A
i/r/ i// i( ( r %
f, x
yii
f
i/ i : f,
yi rd r( 0 ' l
y ); ; 4
F
y
9 r ui ii i' 1 i l/J
1 i/. rf(r` Oli i
y
i Ir/ l
i% .
r/ N `
oi "
lii i / 1( " s
J., / % % 1- 11/'
1;! 1//yl'9 y j,.', ; ( l
H
F , r
0'/ I9ij ' HYlilyi 11,9!
i il1, i I
i,11, j
r, nrJ r% ,° fn Ja y
i iryn , a r,,
iNl (// / G h% 0 j %'1
F
f
i /,'/ p '
i i r, r;` i fr i ,, j/
fi, yl/ yr,,(fff UJ
nlJ f j
i/!/ f A i/ , yfe a , " , 4,
I rery I p ry
J1/ . roi% H". r r r n
f iY I ', v / i
o' l°" 1,; W w, ry' m' i^ ' lYlu Y.. n f
i f p, l : Dr /
J
I "/?
iJ..
p.//'//
H / li ,
J1 / jl /
fji
il iWjr ra r 1
r` ffJ
r
i
1 1 y J n
l j1 k // f, /,' r I fi
y
l µ! 1 d/' lr;. vk r/
J
Ij
y a/ k ,%
iy /r
f rtft,
H / i
r, J re,
r a
i/ , V ,/
y n
r i(
l` / H J, 1
iAri 1F r r r
i
y i yi V / r
n /
lf ``y
yy;<//
i %
fy If f ial -/
i y $ ir),
k /9'"z, l
rN// 9`/ if l'"/ p r i
1 '/r, X
rrr Y / i
Ili /
P
q n; i JJ/ nif I jf, i i d
y / J, m' j``( ( r r t / l „ r ti ir i` i l ! G d ""
r i Iv iaY'
J 5 N' I '
t f J Nl4l r f/ Gl ( 1 ' Y
d^ i°'
a n y
r
s, i I
if i
r l i ' r
d``
i( 1 i9 i ' r A l
ii7 / r
1 r " H
4i ' A
1 rJ r
f'
c 1
e ir i f a i i% e,
r r
4R' r yr, y ,, ,,,, ry lr ki a
r, r / l
y /
i/ t J .)
i
J
iil G i% G/ 1 i"
ii Y '`hP"
1 G' y ' N /, y' i
r„'
r
r r % l
f I
pl t; i
d
I 9
I mul I" I' ,
o/ t r! i
yysx r
J
r7r
u
II , „ 1" N kdV` ' o
I i
y
I
ir i r a/ r . / f / ll , ai //,' /
l
ai
a%f
i
fl i, i"'';° i
1 it e,%(r/" f 7
ji
r
c
y( I
I
y 1% l i, q
y
r i 0
i ..'/; 1'
li, a r" A"
i L, rU t`/ l' '"//% jii
f
n ,;
F iG 1'
r , '^
J a i"""//' l" il
f 1» W l oi j' t
r/
s
a „„ irr f` y 1 , /,/ i
N1r
tl, V rj fC ii(
i , i: ,' / I%/
k;,/ rr/
it/
o
ry`%.:. M. f' fr e
j n!%I/(
i p7t i,
ii i, r/ ...
i '
i ' ff
yfS 1
iiio i r r /
U1 bNW
I
ly
rb / / /
iri. Y l 1 /iy f4JNW/ i
u
y
r %
r; j if/ i/ r
io s
r„ % 1r 1 A /i/ l
i b `
m r
i i / i i //i
l
r6 y
f
f'
i
a/ o / V ri %
ir,,
i ' 6
li i f/ / li . . j ' OrO/
l N6 n
k'„ fP ii !°I ii/. u/
l/ / r// r
j i% r,
rg
Jiru' r r
f 1!,' G ` l '
r
y a ' ff,` i n/r'
1: I', r'
l,' r //,rti
y. i'
r p; h
IM'', , -, f, i
1A, jdy
i
a, 1 ii 1 y'/'
u
i
r r'
l / Ur
A Yu
ir t',!
r,,,,f y ,`/ f / i II°r
v/
y / i/i al 11
H/
i id,,,
i '
1 Q, l u% ti,''° r
s Figure 3- 4 Balancing Area of Northern California ( BANC) Members Asamember of BANC, COR isresponsible for matching customer usage andresources on a moment- by-moment basis. However, BANC operates thetransmission system,monitoring power lines to target their operation within the reliable limits of the system, and coordinates operations with neighboring balancing
authorities. I > I a f: lii, I r i. ii r, a ri: i 7caPr Srr I r ar,rir. S Ylr, ri 3..'
Packet Pg. 511 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric SMUD acts as the balancing authority operator and performs balancing authority functions on behalf of BANC. Benefits of being under BANC include direct scheduling of energy transactions over the COTP within the BANC balancing authority area, free of a CAISO tariff or charges, and free from related congestion and encumbrances.

BANC operates under the principle of maximizing consumer value and compliance with reliability standards. The structure provides flexibility to expand and allows members to benefit from potential future savings through the sharing of facility costs.

Table 3- 4 WAPA Transmission Service Summary Information UIII

IIII I II
I

I IIII I
I
III
I I I
III
p I I„ III III IC III 1 ul ui ,,,„'
IIIII III II II IIIII III IIIII III IIII IIII IIIIII IIIIII IIII IIII II III III IIIIII Im i Im i IIII IIIII IIIIIIII IIIIIIII II II i III I ,"' I '!
IIIIIIII II IU m N W I ou N m I ar „ „, u ll ou m m I . m N m m ouh ... uuuuuuuuuuuuuuuuuumum uuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuui Contract 1 2035 136. 8 230 Olinda, Tracy, Elverta, Airport, Keswick 115 k
Contract 2 2035 47. 2 230
Delivery: Tracy, Cottonwood
Receipt: Airport, Keswick( 115 k

IIIIII IIIII IIIIIIIII IIII I
f" m I ou m m ou m m I I , ,, ar w IV, u ou. m m m m l ... uuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuuu Contract 1 By request By request 230- 500
California- Oregon Border, Southern
Terminus ( 500 k; Olinda, Tracy( 230 k
Delivery point capacity( after losses)
Source: WAPA/ CVP Contract for Transmission Service to the City of Redding, California o^
r
I ° 711 1i„ . 7II11'"' drll IInIVo-.° 111"° iri drl i II II. 711YM.' uIl lYll". u", ulV drlln II':`."°'': COR, along with fourteen other northern California cities, utility districts, and one rural electric cooperative, are members or associate members of a California Joint Power Agency( JPA) known as the Transmission Agency of Northern California ( TANC). TANC, together with COR, WAPA, two California water districts and PG& E ( collectively, the COTP Participants) own the California- Oregon Transmission Project( COTP)— a 339- mile long, 1, 600 MW, 500 kV transmission project extending from southern Oregon to central California.

COR is entitled to 8. 4119 percent of TANCs share of COTP transfer capability( approximately 115 MW) on an unconditional take- or-pay basis. On April 1, 2005, COR purchased from COSL, its 1. 5856 percent ownership interest( approximately 25 MV in the COTP. As a result, COR participates in the use of the COTP as both a member- participant of TANC ( 115 MV and as a direct COTP owner 25 MV; this participation provides a total of 140 MW of firm transmission capability.

Access to the COTP entitlements is gained through a long- term transmission contract with WAPA.

Currently, a portion of its COTP transfer capability is used to provide transmission of renewable wind capacity and energy purchased through the M- S- R PPA. The remaining transfer capability is used to make spot market purchases of firm and non- firm energy and as reliability backup for firm power purchases and sales commitments.

In order for TANC members to utilize the full transfer capability of the COTP on a firm basis and to maximize the benefits of the line, the COTP is operated on a coordinated basis with the Pacific AC Intertie ( the" Intertie"). The Intertie is a two- line system that, like the COTP, connects California I > I a f: Iii, I r ar, ii r a ri: i 7 caPr Srr I r ar, rir.S YIr, ri 3.. 1'1 Packet Pg. 512 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric utilities with other utilities in the Pacific Northwest. The Intertie is owned by PG& E, PacifiCorp, and WAPA; it is operated by the CAISO. The three-line system comprised of the COTP and the Intertie is collectively referred to as the California- Oregon Intertie ( COI). o" o, ° I"^. II. r Ili r° u. run^. i u u^.^. u aru u u° i; The southern physical terminus of the COTP is PG& E' s Tesla Substation near Tracy, California.

TANC has arranged for PG& E to provide TANC, and certain TANC Members, with 300 MW of firm, bi- directional transmission capacity on its transmission system between PG& E' s Tesla Substation and the Midway Substation in Buttonwillow, California (the Tesla- Midway Service) under a longterm agreement known as the South of Tesla Principles ( SOTP). COR' s share of Tesla- Midway Service is 31 MW. This transmission service enhances the value of the COTP to TANC and the TANC Participants by increasing opportunities for energy purchases, sales, and other utility arrangements. The full allocation of Tesla- Midway transmission service has been utilized for firm and non- firm power transactions. This service provides value related to the delivery of CAISO renewables.
o" o," M1 I 1"` I" n"° II II IV' a;:' 7 II n". 0 II IY IV". W". 0 II i dr II n " u" u° w". W
Delivery of power from sources outside the service territory are at the Airport and Keswick 230/ 115 kV substations. These two facilities provide a reliable interconnection capacity of 275 MW from WAPA' s 230 kV transmission system. COR jointly owns the Airport Substation with WAPA: at the Airport Substation, WAPA owns and maintains the 230 kV related facilities; COR owns, and is responsible for, the 115 kV facilities. At the Keswick Substation, WAPA owns, and is responsible for, all facilities other than the remote terminal unit equipment specific to COR' s use at the Keswick Substation.

3. 5 DISTRIBUTION ASSETS AND ADEQUACY
u" No IV".' W II IIII& IV, P': Il drlln m". W u° w. W
COR provides customers with electrical service through a distribution network which includes electric substations, transmission lines, distribution lines, and transformers. A large portion of its electric infrastructure was constructed from the 1950' s through the 1980' s to serve loads with

12. 47 kV, 3- wire overhead service. The infrastructure has since been periodically expanded, updated, and modernized. The most recent modernization program began in 2007 and will be completed in 2019, with all substations having received technology and equipment upgrades to improve reliability.

Between 1985 and 2008, commercial developers supported and assisted in funding the expansion ofthe electric system which more than doubled the 12 kV distribution system using underground cabling. Figure 3- 5 shows the interface ofthe 115 kV transmission system with the distribution system through 115 kV/ 12 kV substations.

Current transmission and distribution system consists of the following:

Service area of approximately 61 square miles
Approximately 72 miles of 115 kV transmission
Eleven distribution substations, one generation station Approximately 740 miles of 12 kV distribution, ( OH= 300 mi, UG= 440 miles) I > I a f: lii, I r ar, ii r, a ri: i 7 caPr Srr I r ar, rir.S Ylr, ri 3..' 1 Packet Pg. 513 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Approximately 17, 000 poles
i
i
r
L d
u t i
I
w,,, w
e' di g Pa r r
o
y_
w ., ;
w 19_ k""
r
a a. ur
h Cu y' Li 1` Nut
A
l' q' 4
rv i' (
ca: a: c w N ,
I S
r
e,
s ur mmuuir flivixi JY
i ^ uMwuMwWl a n y
14 5'{
wu w
v
w
y a4. p
uom uw
4J FREN h+ PFaW
yl t" AI dEIY ( ...,;
4 r"pul. dQlN ;
N W '
i
j
N w II
a : Q 1
b
r
w, °
i a .,,
i
J i l
r a ur .
u I: .....
kUB F' bf
a,
w,..
l..

F B fi. tlN'. r IPG34WER mY1
f .

OG w"
r,
f
I
r
i
lu
r
J"'
r u ' .
a, r 9 w"
5 f iw,
p;'..

U
ti
r, W — ,
uU a d
Figure 3- 5 Electric Distribution System
u° Noo,' IVr.'W" II IIII IV, P''. Il drlln u,' u" 411 w n° 4nlh, Po-;:'rm An all- time high service availability index rating of 99. 992 percent in 2017. This means that the average customer experienced only 39 minutes without power over the entire year. This is significantly better than the comparable average for all Americans ( 130 minutes in 2013), as illustrated in Figure 3- 6.

I > I a f: Iii, I r ar, ii r, a ri: i 7 caPr Srr I r ar, rir.S YIr, ri 3..'13 Packet Pg. 514 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric f EU HA N II T TAN d
af p ravi ir gservice t ur custam cs.

I r 2 17, ur availabi ity rate vv s:
i, y,. u ,>„ N
A ., , . . a)) '
p ll tl':. w I, 119 F V 4...
a= µ: n Vii: i M: f I: m. o: w$ k. 4i
u n mu^ id: N r. u d^ r:; r$ r
y,,,
t ,
r
i
I li"',dYPd I u, m 011C" aM1lf fiJy' `
1 I h. 9"
y hd" tl r U:" a ll « E a9 V" a
IlUlt vr , ? "
a` I AG u: Bq n
rcl, a a G„"
r' Yl a ti u p A 17u ii. ei
u.

T J ' v A°`V11V' f& uPl(;:"• l
I 5 7r 1 a Uf p. a. u^ 4a
ir
r
m u; la;ul" s c i ii u. um us tr: i: s iu.
ir,: I i. d a Il U„ r.:16u;. Rut.. I
I Il;. Rl
U:" 3A V'^ G I: PIOii NI- s s: Q: V u i
u,„: Figure 3- 6 Reliability
Comparison For a more local comparison, in2016, PG& Ecustomers in thenorth valley had anaverage of 175 minutes without
power. During the Carr Fire— araging wildfire that torethrough Shasta County andblazed into Redding' s city limits—the local transmission system lost 5out of6elementsof redundancy. Because of our community- owned generation station and multiple connections to the WAPA grid, our operators were able toavoid atotal city-wide
blackout.Thedistribution system conditions arecontinually evaluated andappropriate adjustments are made as needed to improve and optimize the distribution network. Projects are approved and funded through the Electric Distribution Capital Expenditure Plan. Current modifications under consideration
include: I > I a f: lii, I r i. ii r, a ri: i 7caPr Srn I r ar,rir. S Ylr, ri 3..'
Packet Pg. 515 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric

1. Improved communication for Power and VAR control via local network, installation of additional circuit breaker dedicated to substations.

2. Potential system modifications to accommodate future solar installations are dependent upon site approval/ location. Presently 10 MW of additional solar is expected which would equate to a requirement of 475 Amps at 12. 47 kV. The majority of this solar generation is anticipated for nearby East Redding Substation and the remainder may split between two other locations. The project completion is planned for year 2021.

3. Re- conductoring ofthe 115 kV lines between Eureka Way and Oregon substations to increase the line rating. Under certain contingencies that cause increased through- flow, the present line may become overloaded. The project would be completed end of year 2019.

4. Installation of fiber optic communication links between the Plant, Texas Springs Substation, and Moore Road Substation. This will provide high speed tripping capability to increase generator stability as well as redundant substation communication path. The project would be completed end of year 2019.

5. Provide reconfiguration of the lines interconnecting the Plant to the bulk electric system to reduce the system impedance and resultant voltage drop to Canby Substation under certain system contingencies. If approved, the project is proposed to be completed by the end of year 2020.

6. Alternatively ( to the reconfiguration project immediately above), provide VAR capacitors at Canby Substation system to reduce the resultant voltage drop to Canby Substation under certain system contingencies. If approved, the project is proposed to be completed by the end of year 2020.

Other projects being considered would provide upgrades to the communication systems necessary to integrate additional demand- side energy management investments. These projects could include:

1. Install city- wide radio network communications in support of a remote commercial metering project. This network will provide open architecture communications for control and monitoring of 12 kV line voltage via capacitor control and commercial remote metering.

The project would be completed by the end of 2020.

2. Installation of the optional OMS/ DMS software to augment the present OSI- SCADA system used by the Electric Utility Distribution System Operators. This improvement will decrease response times, reduce the risk of switching errors, and reduce the likelihood of unknown equipment overloads. The project would be completed by the end of 2020.

3. Provide System Operator control and monitoring of the utility-owned and large customerowned solar facilities. This improvement will give the System Operators direct control of solar generation output including MW& Volt/ VAR control. The project would be completed by the end of 2022.

4. Upgrade substation communications equipment to automatically retrieve protective relay fault information and display to the System Operator. This improvement will decrease event response times. The project would be completed by the end of 2019.

Finally, it is important to mention that it has been long recognized that reducing losses on the power distribution system through investment in energy efficiency has beneficial impacts on I > I a f: Iii, I r ar, ii r, a ri: i 7 caPr Srr I r ar, rir.S YIr, ri 3..' 1 Packet Pg. 516 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric customer rates, on the environment, and it can extend the lifespan of transmission, distribution, and generating assets. Energy efficiency efforts are consistent with goals of reliability, affordability, and sustainability.

In this context, the energy efficiency programs undertaken ( and discussed in Section 5) constitute significant steps to reduce losses on its distribution system. For example, since enacting the street lighting program in September 2015, annual system losses have been reduced by an average of 1, 231,494 kWh through the conversion of high pressure sodium lighting to LED lighting. The LED lighting technology consumes nearly two-thirds less energy and is estimated, at project completion in 2021, to save over 3, 700, 000 kWh annually. To date, the project is approximately 33 percent completed with 2, 783 LED lights already installed.

3. 6 NATURAL GAS COMMODITY, TRANSPORTATION AND STORAGE
Natural gas is the primary fuel and the primary variable operating cost ofthe Station. The Station can require delivery of up to 38, 000 decatherms ( Dth) of natural gas per day, with current average daily requirements of 8, 500 Dth per day.

A comprehensive natural gas program has been developed to mitigate the electric retail impacts of gas supply and price volatility. This program includes a gas prepayment arrangement( in which a supply of natural gas can be procured at a discount from the monthly index price), as well as forward purchases of natural gas at fixed prices plus gas storage options. o,. ° IV... u r u u r
i,' II° n, ru° i r^ i! II° r
The M- S- R PPA members have formed a JPA known as the M- S- R Energy Authority( M- S- R EA). The M- S- R EA was created for the purpose of entering into contracts and issuing bonds to assist M- S- R EA participants in financing the acquisition of supplies of natural gas for use in each participant' s electrical generation stations. In 2009, COR participated in the M- S- R EA Gas Prepay Project. The Gas Prepay Project provides, through a Gas Supply Agreement with M- S- R EA ( the Gas Supply Agreement), a secure and long-term supply of natural gas of 5, 000 Dth daily (or 1, 825,000 Dth annually) through September 30, 2039. The Gas Supply Agreement provides this supply at a discounted price below the monthly market index price (the PG& E City Gate index) over the 30- year term. M- S- R EA entered into a prepaid gas purchase agreement with Citigroup Energy, Inc. to provide this gas supply. Under the terms of the Gas Supply Agreement, M- S- R EA bills for actual quantities of natural gas delivered each month on a" take- and- pay" basis. This prepay cannot be used as a financial instrument( i. e. it must be utilized for load only). o. o, o^'
e K"° h, II" IV"° i drll'" C, 11qa 711 h, " II II Il o-.'. u°, W In addition to natural gas procured through the M- S- R EA Gas Prepay Project, a number of purchase obligations have been entered into, such as fixed price hedges to purchase natural gas through 2025. Currently, forecasted gas requirements range from approximately 6, 000 to 10, 000 Decatherms per day(" Dth/ day") ( a decatherm is equal to one MMBtu) for the next 7 yrs. Table 3- 5 provides the volume of current fixed price natural gas purchases to which COR is committed on a yearly basis.

I > I a f: lii, I r ar„ ii r a ri: i 7 caPr Srr I r ar, rir.S Ylr„ ri 3..'1E Packet Pg. 517 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Table 3- 5 Natural Gas Purchase Obligations, Fixed Price Hedges

II IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII I,I,I,I,I,I,I,I,I,I,I,I,I, IIIIIIIIIIIII Illii iiiiiiii iiiiii m iiiii nm iiii iii iiiiii u iiiillm iiiiii u iiiiii uu iiiii nu iiiii iiiii iiiiii u iiiiiinu iiiiii iiii
Decatherm per day( Dth/ day) 6, 167 5, 667 5, 000 4, 500 4, 000 Delivery Point is PG& E City Gate)
Source: City of Redding
o. o, o o-;:''` II II a. 7 IV u a 7" u II IV' a;:' Y II n". 0 I dr 16" m. 7 II dr II M In order to provide for the transportation and delivery of purchased natural gas, COR entered into an agreement to purchase 7, 500 Dth/ day of natural gas pipeline capacity in four segments connecting the AECO supply hub and natural gas storage operation located in Alberta, Canada, to California ( at the PG& E Citygate) from TransCanada affiliates and PG& E. The contractual obligation for three of the segments expired on October 31, 2015. The remaining contractual obligation for the fourth segment expires on October 31, 2023, but shipping rights for this segment have been assigned to a third party for the remainder ofthe contract period. o
P &`:' II II II II. IV n U h Y U II, rvr II,;
To further manage seasonal, weather, and price volatility, a contract has been executed for natural gas storage within northern California since 2004. In 2010, under a 28- year term contract, COR commenced utilizing storage rights at Gill Ranch Storage— a gas storage facility located in central California. Under the agreement, cushion gas has been leased and Gill Ranch Storage provides approximately 600, 000 Dth of natural gas storage. At the end of the contract term in 2038, the cushion gas will be returned.

3. 7 WHOLESALE ENERGY TRADING
COR undertakes e ensive planning to select its future conventional and renewable power supplies.

Once these resources are available, operation and management of its power supply and transmission resources will be done using an" economic dispatch" model that is designed to produce and deliver energy at the lowest cost that reliably serves consumers.

As with any utility, since generation and transmission resource additions do not perfectly match yearly load projections, in addition to making market purchases when economical, excess capacity and energy can be sold. As a result, COR participates in trading in the wholesale energy markets in order to capture the maximum value of its generation assets and to minimize the cost of purchased power. Additionally, coordination of its gas purchases and sales is done within the year in light of wholesale energy costs. For financial forecasting and planning purposes, only revenues from wholesale trading activities that are under contract at the time of the forecast are assumed.

Continued optimization of generation and transmission assets is expected in the wholesale market for the benefit of its retail electric customers and it's anticipated that wholesale sales will continue at some level in the future.

I > I a f: lii, I r ar„ ii r, a ri: i 7 caPr Srr I r ar, rir.S Ylr„ ri 3..'17 Packet Pg. 518 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric ii .., iir ii ii ii iir ... °
A fundamental element of an IRP analysis is the development of the long- term ( 2018- 2037) system peak demand and energy forecasts. The forecast results in a projection ofthe capacity and energy requirements on the system that the utility must plan to meet through self- owned generation or purchase arrangements.

Sufficient capacity must be secured to cover projected peak annual demand as well as reserve requirements. Reserves are an amount over and above the projected system peak that utilities will plan to maintain in the event that the forecasted demand is higher than anticipated due to extreme weather conditions or higher than expected load growth, or in the event that capacity resources are not available due to a forced outage, a transmission line failure, or another unexpected event. A planning reserve margin of 15 percent is used in planning based on the requirement set forth for the region by the North American Electric Reliability Council ( NERC). 8

4. 1 HISTORICAL ENERGY USE AND PEAK DEMAND
Electricity demand exhibits strong seasonal trends, with peak energy requirements driven by airconditioning use in the summer months and minimum energy use normally occurring during the spring and fall seasons. Demand levels during the summer also tend to exhibit a greater daily variation in load. The seasonal variability is demonstrated in Figure 4- 1, which displays the monthly average energy sales for the period of 2013 through 2017. ur u lll llly u ur y III u @ II6 ur n u 2 mm2
a. ....................................................................................................................................................................................................................................................................................................................................................................................:.. ra. a a:

UA
4 i ,
u, a !.. 4. „,
M,,,,
4 n 4
a a. ^ G
4 4
p ry w p
irowau
n' r
ir+
nvuH ... .

V. F" QN 4, M
I, I "
II Q N
rmouw
wy mia m
ir,'
i
r d Q (' C' v
6 4 d
YzPo
Q .. N dQ..
ry , V. Q. ...',, , rDQ.. N
Q ',;. .,,,.. ,,,... .,.... .,.... .,.... ., .... ., .... ., .... ., .... ., ' i.. Q.

U ir II ir I s ir II y U u. ir U u. II u ° I s . U: " r :.

Figure 4- 1 5- Year Average Monthly Energy Sales and Peak Demand ( 2013- 2017) System( evel Resource Adequacy( RA) requirement of 15 percent above the forecast 1 in 2 peak must be met— sometimes referred to as the 50/ 50( oad forecast.

I ir r.; ji i i i 7r i i ri:, i 1= r, r. a' Y 1
Packet Pg. 519 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Table 4- 1lists historical data over the past five Fiscal Years. The table indicates that the combined peak customer demand during the 2013- 2017 period reached a maximum of 249.8 MW in 2014 and was 231. 0 MW in 2017— well below the historic distribution system peak demand of 253. 0 MW recorded on July 24, 2006. Although the peak demand typically only occurs once each year, resources must be maintained to meet the peak year round.

Energy sales also declined over the 2013- 2017 period. The 2017 sales of 745, 607 GWh were only 96 percent of the 2013 energy sales figure. At the same time, the number of customers has increased by 1. 5 percent over the period and reached 44,233 customers in 2017.

Table 4- 1 Historic Customer, Sales, and Demand Data
II IIIIIII IIIIIIIIIIIIIIIIIIIIIIIIIIII I; I; I; I; I
g iiiiiiiiiiiiiiiiiiiiiii
lii iiiiiiii iii iii m iiiiii mi iiiiii iii iiiiii ii iiiillCiii iiiiii mi iiiiii iii iiiiii mi iiiiii ii iiiiii mi iiiiii i M
ui uu i iuui uu iuu uu uuui uuuuiuui ui iuu uui uu uu iuui uu uuu III Residential 37, 268 37, 387 37, 561 37, 751 38, 015
Commercial 5, 022 5, 011 5, 034 5, 025 4, 949
Industrial 334 330 322 335 336
Other 927 934 915 928 933
Total 43, 551 43, 662 43, 832 44, 039 44, 233
Customers
mWd: , mm , w w „ r
IIII III IIIII Illlll iiuui lllllllll III II IIII III IIII hlll IIII IIII IIII III I IIII IIIIII IIIII II IIIIIII Illlnlll IIII IIIII IIIIII Residential 375, 606. 32 361, 105. 70 356, 070. 92 361, 427. 32 366, 353. 63 Commercial 338, 256. 66 336, 506. 90 338, 291. 79 332, 231. 88 324, 201. 81 Industrial 13, 505. 87 12, 303. 01 12, 366. 15 13, 393. 83 13, 266. 38 Other 46, 755. 68 45, 923. 16 43, 087. 05 42, 358. 33 41, 825. 28 Total MWh 774, 124. 53 755, 838. 77 749, 815. 91 749, 411. 36 745, 607. 10

IIIII IIIII III III III
II w
w' w u 1. Data is provided for Fiscal Years ending June 30.

2. The values for Number of Customers include every point at which electricity is delivered for end use as of the last month of the Fiscal Year; data does not include sales to COSL.

Source: City of Redding
I ir5r.; ji i i i 7r i i ri:, i 1= r, ir.,.',; p
Packet Pg. 520 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric

4. 2 FORECAST METHODOLOGY AND ASSUMPTIONS
The load forecast for the IRP planning period was developed by Itron; it develops future projections of energy sales and peak demand based on the historical relationship with various socioeconomic factors and temperature data as described further below.

The 20181oad forecast of energy sales and peak demand levels was done by end user class and involved the following customer classes:
i Residential
Large Commercial Users
Small Commercial Users
i Fixed Use
i Time of Use
The load forecast was developed based on Itron's Statistically Adjusted End Use ( SAE) modeling framework, which incorporates models customized for the residential and non- residential sectors.

One of the traditional approaches to forecasting monthly sales for a customer class is to develop an econometric model that relates monthly sales to weather, seasonal variables, and economic conditions. From a forecasting perspective, the strength of econometric models is that they are well suited to identify historical trends and to project these trends into the future.

In contrast, the strength of the end- use modeling approach is the ability to identify the end- use factors that are driving energy use. By incorporating end- use structure into an econometric model, the SAE modeling framework captures the strengths of both approaches. For instance, by explicitly introducing trends in equipment saturation and equipment efficiency levels, it is easier to explain changes in usage levels and changes in weather- sensitivity over time, and identify end use factors driving those changes.

SAE models leverage the U. S. Energy Information Administration' s ( EIA) Sector- level End Use Saturation and Efficiency Forecast for the Pacific Region as well as information specific to COR. The result is a long- term forecasting framework that captures long- term structural changes, short- term driving factors of usage levels such as economic activity, electricity price, and weather, and their appropriate interactions. Furthermore, the framework facilitates the disaggregation of the sectorlevel sales forecasts into end use- level forecasts in support of further evaluation.

Key considerations and assumptions utilized in preparation of the load forecast are shown in Table 4- 2. For the variables listed, those of special importance include assumptions about the future growth of EV, solar installations, energy efficiency, as well as population growth and the consideration of temperature data.

I ir5r.; ji i i i 7r i i ri:, i 1= r, ir.,.',; p
Packet Pg. 521 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Table 4- 2 Load Forecast Assumptions and Input Considerations

IIIII IIIIIIIIIIIIIII IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII

IIIIII II III IIII IIIIIII IIII IIII I III III III
Ilu '° '"

IIII IIIIIII IIII III III II III III III III IIIIII II I Weather Normal Weather for Energy and Peak: ( Calculation Range 2008- 2017) Economics Net Migration Forecast uses a 10- year historical average( 2008- 2017) in 2017& 2018
Net Migration phases into a 20- year historical average( 1998- 2017) by 2023
High and Low Cases+- 10% of historical average
Employment Forecast uses post- recession CAGR( 2009- 2017) in 2018 Employment phases into a long- term growth rate for the 20- 64 Age Cohort

0. 5%) by 2023)
End Use Equipment SAE Inputs- Pacific Region Efficiencies from the EIA' s 2017 Annual Energy Saturation& Efficiency/ Outlook Forecast
New Technology Solar Adoption Forecast
EV Adoption Forecast
Energy Efficiency and Demand Response Forecast
Street Lighting Program . Extended Street Lighting LED Program Savings through the end of the Forecast Horizon
Source: City of Redding
o o^" o,. '.
dr 15 idr If F w idr II a° 7 II" IV IV` n" u' n 7 II I o-;:''' II dr II.' W Installations of rooftop solar are expected to continue growing within the service area, albeit at a diminishing rate, through 2022. Increases in solar installations for a given year are related to the status of the Investment Tax Credit( ITC), which is scheduled to decline from 30 percent in 2018 to 10 percent by 2023. Figure 4- 2 below shows COR' s forecast overlaid with the scheduled ITC rates through 2022.

Solar Installations ( kW) Investment Tax Credit ( ITC) % 3500 .... .... .... .... .... .... .... ...... 35%
3000 30%
2500 25%
2000 20% o
1500 15%
cn
1000 10%
0 500 5%
0 ... .... .... .... .. .... .... .... ....... 0%
2017 2018 2019 2020 2021 2022
Figure 4- 2 Projected Solar Installations vs ITC Tax Credit I ir r.; ji i i i 7r i i ri:, i 1= r, r. a' Y
Packet Pg. 522 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric o o^" o, o^ II II I° II°' 5': II II "" 4I" n II II"° ;" dr II"° o-.' W' 5':

For the service area, the EV forecast involves a significant increase in the number of vehicles through 2026. Figure 4- 3 shows the cumulative number of EVs, including EVs and plug- in electric vehicles (PEVs) that are projected to increase from approximately 200 to more than 2, 200 in 2026; this forecast was based on the 2016 Zero Emission Vehicle Action Plan. This rapid growth is also a function of the EV rebate program that went into effect in August 2017. Under this program, commercial incentives of up to $ 1, 000 per vehicle, plus $ 3, 000 are available to commercial customers who install a EV Leve12 charger; residential incentives are$ 1, 000 plus up to$ 500 for installing a Leve12 charger. 9 It is estimated that the cost of charging under the applicable electricity rate equates to a cost of only$ 1. 08/ gallon of gasoline and provides an equivalent environmental benefit to planting more than 100 full grown trees.
5 Jt
v
l l!
v_ 1, 5 Jt
1, l 1C!
5 1t
2C117 2C118 2C119 2C12C1 2C121 2C122 2C123 2C124 2C125 2C12 Ein of Ye, r
Figure 4- 3 Projected Electric Vehicles— COR Service Territory o o^" o II I° II i ,'' l II II" 411 1 V a. 7 II M:° "° II V It o-;:' II n h °,' u F. dr II". 0;"' The load forecast considered a number of energy efficiency and demand reduction measures.

These are further described in Section 5.
oo,^' o," M1 s; 7' IIn"° 16" 1 i drll" II V It 7IIIIm. 7°` IV drII M Because energy consumption is heavily affected by weather conditions from year to year, actual energy sales and peak demand data were normalized by Itron as a means of adjusting values to reflect long- term average weather conditions.

Itron developed the peak demand forecast by comparing historical peak demand levels from 1980 through 2016 with the temperature at which annual peak demand conditions occurred, and determining a statistical correlation for that year. ( For example, the 50th percentile temperature in the 1980- 2016 period formed the basis for the" 1- in- 2 year" case, and the 90th percentile temperature occurring during this period formed the basis for the" 1- in- 10" year case.) The forecast of future peak demand utilized in the IRP base case is the 1- in- 2 year forecast, which corresponds to an expected maximum temperature of 111 degrees Fahrenheit. 9 A Level 2 charger provides 240 VAC and charges in 4- 8 hours, the equivalent of 12- 20 miles per hour of charge.

I ir r.; ji i i i 7r i i ri:, i 1= r, r. a' Y
Packet Pg. 523 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric oo,^' o, N u" IV'"" II"" II"° '` drllFll, ll. 7°` IYi drIl M An average annual growth rate ( AAGR) for population of less than one percent( 0. 49 percent) is projected by Itron for the forecast period compared to an AAGR of 1. 13 percent experienced between 1990 and 2017.

4. 3 FORECAST RESULTS
The peak and energy forecast results are presented in this section. The capacity and energy requirement forecast is also carried forward to the four required CEC tables in Appendix A. o o, " n; 7llm a. 711fii:; Iln"° i„; drlV'!"' i a". W' 5':

Table 4- 3 shows the energy and peak demand forecast. During the forecast period (2018 through 2037), energy requirements for all customer classes are projected to increase from 767, 535 MWh in 2018 to 804,309 MWh in 2037. For the system, the increase equates to an overall growth of approximately 4.8 percent over the planning horizon and an AAGR of 0. 24 percent.

During the forecast period, peak demand is projected to increase slightly, from a value of 228.1 MW in 2018 to 231. 2 MW in 2037, equating to an AAGR of 0. 07 percent. o, o^ u.'; u`" 411 I IY . dr
a 7 h ' a;:' . dr 16"
Table 4- 3 also indicates the projected system load factor. A load factor is a measure of the variability in utility load over time. A load factor measures total energy requirements on a utility system as a percentage of the theoretical maximum energy requirements that would result if the energy requirements at the time of peak demand were required all hours of the year.

Table 4- 3 summarizes for each year of the analysis the annual net energy sales forecast and peak demand forecast for the projected system load factor. The projected system load factor remains fairly consistent during the period of analysis, ranging from 38.4 percent in 2018 to 39. 7 percent in 2037. The slight increase in load factor and relatively flat peak demand growth rate are reasonable and result from a combination of factors. These results reflect the continued installation of rooftop solar systems by residents or commercial users, programs that may be introduced by State of California to enhance energy efficiency measures to be incorporated into new residential housing and commercial buildings, and assumptions regarding the growth of EVs and demand response.

I ir r.; ji i i i 7r i i ri:, i 1= r, r. a' Y
Packet Pg. 524 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Table 4- 3 Projected Net Energy Requirements, Peak Demand Forecast, and Load Factor qpqii,r,qipiipqiipqiiiiipiiiiiiiiiiiiiiiiiiiii°: giiiiii i,?!. l. d
tU i". I'... iu r i , iu

III IIII
I111''° @p 111! I111''° @p 111!
iii
A IIU
p p p
I
A "
II II Iml III II IIIII II III II II I I III IIIII m
p
i IIIIIIIIII II I IIIII II III II II I I III IIIII m
p
i
p
2017( actual) 798, 960 2. 18% 241. 4 4. 51% 37.8%
2018 767, 535 3.93% 228•1 5. 51% 38.4%
2019 767, 119 0.05% 227.3 0.37% 38. 5%
2020 766, 632 0.06% 226. 7 0.25% 38. 6%
2021 763, 013 0.47% 226. 2 0.21% 38. 5%
2022 761, 992 0. 13% 226. 0 0. 12% 38. 5%
2023 762, 510 0.07% 225. 9 0.01% 38. 5%
2024 767, 096 0.60% 226.1 0.09% 38.7%
2025 768, 249 0. 15% 226.4 0. 11% 38. 7%
2026 770, 535 0.30% 226. 6 0. 11% 38. 8%
2027 773, 399 0. 37% 227. 0 0. 14% 38.9%
2028 778, 734 0.69% 227. 3 0. 13% 39. 1%
2029 780, 769 0.26% 227•8 0.24% 39. 1%
2030 782, 358 0.20% 228. 0 0. 10% 39. 2%
2031 784, 084 0.22% 228.4 0. 17% 39.2%
2032 788, 191 0. 52% 228. 8 0. 17% 39. 3%
2033 789, 134 0. 12% 229. 3 0.20% 39. 3%
2034 792, 330 0.40% 229. 7 0. 19% 39.4%
2035 796, 280 0.50% 230. 2 0.23% 39. 5%
2036 802,497 0. 78% 230.8 0.24% 39.7%
2037 804, 309 0.23% 231. 2 0. 19% 39. 7%
AAGR2018- 2037 0. 025% 0. 071%
Source: City of Redding

4. 4 COMPARISON TO CEC FORECAST
The energy requirements forecast used in this IRP and prepared by Itron can be compared to the forecast published by the CEC in its document California Energy Demand 2018-2030, which is developed annually as part of the CEC' s Integrated Energy Policy Report As seen in Figure 4- 4, the CEC forecasts of energy requirements is comparable to the IRP forecast through 2030, with the CEC forecast ending( 750 GWh) approximately 4 percent lower than the forecast in 2037 ( 782 GWh). Overall, the CEC forecast of energy requirements decreases slightly while the forecast of energy requirements increases slightly through 2030.

I ir5r.; ji i i i 7r i i ri:, i 1= r, ir.,.',; p
Packet Pg. 525 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric The peak demand forecast differs slightly in that the CEC reports a lower peak demand in COR, relative to the Itron forecast In 2018, CEC' s peak demand forecast for COR is 212. 3 MW. The corresponding figure in Itron' s forecast is 228.1 MW.

Similar to the energy demand forecast, the CEC projects declining peak demand through 2030, whereas Itron projects relatively flat demand throughout the forecasted period. Still, the forecasts are substantially similar, especially during the middle years of the projection.

Energy Demand: ITRON vs. CEC Comparison
ITRON Redding CEC Redding
900
800
700
s
600
500 ...
a
C400 ...
a'a 300
a
W 2 ...
100 ...
i 0 i i . i. ..
i ... .... i .... .... i
2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Figure 4- 4 Energy Requirements Comparison: COR Forecast vs. CEC Forecast for COR I ir r.; ji i i i 7r i i ri:, i 1= r, r. a' Y f
Packet Pg. 526 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric ii .., iir iir iir ii , ii .., iir iii iii .., ii ii ii ii II ii ... ... iir ...

Customer Programs, energy efficiency, and demand response resources are an important consideration in the development of an IRP and PUC regulations require their consideration in resource planning. To the extent that reasonable estimates could be developed, the load forecast by Itron considered past and current efforts to reduce consumption through energy efficiency programs and reduce GHG emissions with electrification programs. The energy requirements and peak demand projections reflect the impact of aggressive efforts to reduce energy consumption, system peak, and GHG emissions through the multiple programs described in this section.

Promoting energy efficiency and demand response programs goes back many years and, in part, has been fostered by the requirements of PUC 9505. Section 9505 required POUs, starting in 2013, to describe and quantify POU investment in energy efficiency and demand reduction programs; to describe the funding for these programs; to explain the method used to estimate cost- effectiveness; and to establish annual energy savings and demand reduction targets and report savings achieved.

This section compares the Additional Achievable Energy Efficiency( AAEE) savings incorporated in the IRP assumptions and the target established under PUC Section 9505. Estimates of market, economic, and technically achievable energy efficiency savings from studies used to establish target savings under PUC Section 9505 are also summarized.

5. 1 ENERGY EFFICIENCY PROGRAM BACKGROUND
Targets for energy efficiency programs ( and established under PUC section 9505) are based on the net market potential estimated in the Navigant study. l The net market potential provides a forecast of market potential for specific utility energy efficiency programs. The net market potential is a subset of the total economic potential and technical potential and recognizes that not all of the impacts that are technically or economically achievable will be realized.

The energy efficiency program portfolio was redesigned in 2016, with a launch of new programs in 2017, and continues to develop new offerings that will help achieve energy efficiency goals over the IRP planning period; those programs are being actively promoted.

During program years 2015- 2017, savings achieved exceeded the SB 350 targets set by the CEC see Figure 5- 1). In fiscal years ( F 2018- 2022 and 2027- 2028, however, new ways to achieve savings beyond the PUC 9505 target must be explored. New programs have been developed to help fill this gap and have provided new ways to apply, including a new online rebate portal and a rebate catalog scheduled to be released toward the end of 2018.

The AAEE savings assumed in the IRP filing represent the difference between targets established by COR under PUC section 9505 and the annual target set by the PUC in the SB 350 Doubling Report.

The relationship between SB 350 targets and the AAEE required to make up the difference is shown in Figure 5- 1.
10 CMUA, POU Potential and Goals Study, March 2017http:// docketpublic. energy. ca. gov/ PublicDocuments/ 17- IEPR06/ TN 217482_ 20170508T153251_ Ap pen d ix_ B_ 20182027_ An n u a I_ Ta rgets_ AI I_ PO U s. xl sx. t ii a Yr, i ir r f' rr,, i i i, a, 1=; r r. r, I-: i. ir rir, 3i ii I, r 5rr ii I r ar5r ii, ar 1 1r=, ar iii. r a a..' 1 Packet Pg. 527 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric y y
4500
4000
3500
3000
2500
2000
y 1500
1000
500
0 `
w 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 llf" llf" llCliY.

PUC 9505 Target Redding AAEE > Savings Achieved- 2015- 2017 Redding SB350 Target Figure 5- 1 Comparison of Energy Efficiency Targets and Historical Achievements

5. 2 CURRENT ENERGY EFFICIENCY INITIATIVES
COR maintains a robust suite of energy efficiency programs that will contribute to the state' s goal of doubling statewide energy efficiency savings as codified in SB 350. Energy efficiency programs are intended to offer maximum benefit to the community while meeting all regulatory requirements.

The regulatory requirements include the following:

Public Utilities Code§ 385 requires that the utilities collect and spend a percentage of their base retail electric revenues on qualified Public Benefits Programs. The customary amount collected by public utilities in California is a minimum 2. 85 percent of annual base retail electric revenues. The funds must be spent on programs in four categories including energy efficiency, research and development, RE resource development and low-income assistance.

Public Utilities Code§ 386 requires each local, publicly- owned utility to ensure that lowincome families have access to affordable electricity, and the level of assistance reflects the level of need. Furthermore, utilities shall ensure that low- income families have access to low-cost, no- cost measures that reduce energy consumption.

Public Utilities Code§ 454. 5 and Public Utilities Code§ 9615 both require utilities to address unmet resource needs through energy efficiency and demand response prior to procuring new sources of power.

Public Utilities Code§ 9505 requires each local, publically-owned utility to report annually investments and achievements in energy efficiency and demand reduction programs.

Furthermore, utilities must identify all potentially achievable cost- effective electricity efficiency saving and report savings targets to the CEC.

Public Resources Code§ 25305. 2 requires the CEC to report to the Legislature a comparison of the annual energy savings targets versus the actual energy efficiency savings and demand reduction for each local POU.
t ii a Yr, i ir r f' rr,, i i i, a, 1=; r r. r, I-: i. ir rir, 3i ii I, r 5rr ii I r ar5r ii, ar 1 1r=, ar iii. r a a..

Packet Pg. 528 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Public Resources Code§ 25310 ( c)( 1) requires the CEC to set goals that will double statewide energy efficiency savings in California by 2030 and will require specific targets for COR.

A comprehensive list of energy efficiency projects and programs under consideration is described below. The description indicates whether each program was included in the PUC Section 9505 targets, and is, therefore, counted as" committed savings", or whether the program can contribute to future AAEE goals and can support achieving the SB 350 target to double energy efficiency savings.

I" Noo,^" o . II. IV II° Iln w, '^"°", ullh."" IV` n Ila. 7II IVn"° II„ l ll ll" IV` n° 16" dr irll a° 711 V It. W si rn i l b s,....., a S rri s
The Residential Rebate Program offers prescriptive rebates for a variety of different measures that work to reduce energy consumption and save customers money. The measures included in the Residential Rebate Program are as follows:

Energy Star listed Heat Pump Water Heater
Conventional Storage Water Heater
Energy Star listed Ceiling Fan
Energy Star listed Variable Speed Swimming Pool Pump
Energy Star listed Window and Wall Air Conditioner
Energy Star listed Refrigerator
Energy Star listed Wi- Fi enabled smart thermostat
New Air Conditioner including Split System, Package, and Ductless Systems i Whole House Fan
Wall Insulation upgrade
Ceiling Insulation upgrade
Dual Pane Windows Replacing Single Pane Windows
si rn i l f riz o rn Pr r EE
To address the needs of income- qualified customers who do not typically participate in utility rebate programs, a Low- Income Energy Efficiency Program ( LIEEP) is offered. LIEEP is available to owners and renters residing in single family homes, multifamily dwellings, and mobile homes, who meet the program income eligibility requirements. A trained weatherization contractor conducts program marketing, customer enrollment and income qualification, dwelling assessment, measure installation, and reports program details.

LIEEP utilizes a tiered approach that provides a suite of cost-effective deemed energy efficiency measures ( Tier 1) to all participating customers, with a subset of customers who qualify for additional measures (Tier 2). All eligible customers are able to participate in Tier 1 measures that include lighting, appliances, HVAC Retrofits, Wi- Fi thermostats, Tier II smart power strips, and others. However, for more substantial measures such as window replacements, HVAC replacements, duct replacement, heat pump water heaters, etc., an energy audit is performed to verify that the measure is cost- effective in a specific home. This tiered approach provides service to t ii a Yr, i ir r f' rr,, i i i, a, 1=; r r. r, I-: i. ir rir, 3i ii I, r 5rr ii I r, ar5r ii, ar 1 1r, ar iii. r a a.. 3 Packet Pg. 529 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric a significant number of customers with Tier 1 measures, while allowing a mechanism to provide significant dwelling upgrades to customers that need improvements the most. si rn i l SI ° r Pr r ..... EE
The Residential Shade Tree Program offers customers an opportunity to reduce energy consumption by planting trees in locations that shade their home. Customers sign up through an online portal and locate the appropriate tree- planting site near their home. Based on the species of tree selected and orientation to the home, the portal, powered by i- Tree software, calculates the energy savings over the life ofthe tree in a format that is beneficial for integrated resource planning.

5. 3 COMMERCIAL REBATES
a r 6 1 b s,....., a 6 S rri s
A suite of rebates is offered to incentivize building owners to install energy efficiency mechanical equipment, refrigeration equipment, and appliances. The measures included in the commercial deemed rebate program are as follows:

Auto door closers for walk- in refrigerator and freezer doors Anti- sweat door heater controllers
ECM Fan motors and motor controllers
Unitary air cooled air conditioners
i Unitary heat pumps
Packaged Terminal Air Conditioners and Heat Pumps
Web- enabled programmable thermostats
Electric food service equipment including refrigerators, freezers, ice machines, steam cookers, convection ovens, fryers, griddles and combination ovens, and vending machine controllers
a r 6 1 I G Li f i b s..... a 6 S rri s
The largest commercial program continues to be the calculated commercial lighting program; this program incentivizes customers to upgrade interior and exterior lighting systems. a r l s Pr r,....., EE
The commercial custom program serves commercial customers that are performing large projects not addressed by other commercial rebate programs. Incentives are designed to promote comprehensive projects to achieve energy savings over applicable end uses.

5. 4 ADDITIONAL PROGRAMS
wr rn n pl Pr r s..... EE
In addition to the residential and commercial programs, this program provides leadership and incentives for projects that reduce operational costs, energy consumption, and GHG emissions.

These programs will contribute to AAEE and include the following:
t ii a Yr, i ir r f' rr,, i i i, a, 1=; rir. r, l- fi. ir rir, 3i ii i I", r5rn ii i I r ar5r ii, ar 1 1r=, ar iii. r,; Packet Pg. 530 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Retrofit of approximately 7000 existing HID streetlights with new LED fixtures at a rate of approximately 1000 streetlights per year
Leading a City- wide effort to implement an Energy Savings Performance Contract as allowed by Government Code§ 4127. This comprehensive upgrade will cost- effectively reduce energy costs across all City departments
Fa w Pr r s
Current programs are realizing increased participation rates and improved energy savings rates.

These observed trends are consistent with the market potential by end use projected by the Navigant study through 2024, shown in Figure 5- 2. Based on these recent successes and programs launched in anticipation of SB 350 doubling requirements, it is projected that new programs launched in 2017 and 2018 will accommodate the AAEE gap and meet or exceed the current savings target.

ANNUAL EE PORTFOLIO MARKET POTENTIAL BY END USE
4, 500
4, 000
3, 500
3, 000
u mm
i m m fl VIIU I VIIU j 2, 500
V 2, 000
u
y
1, 500
1, 000
500
3 0 .............
2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 W
Program Year
Ns tr Re: Light irrg Re: She]] u Re: Ps c] Pun r
Ns tY Re: S Cs c] itYg -;,,;; Re: S Cs c] itYg IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII Re; S Ref riger t is tY I A li trce: Re: VV ter F e t
irrg SL35a S virrg:" I" rget
Figure 5- 2 Annual EE Portfolio Market Potential by End Use Although well positioned to meet the current savings targets, it is recognized that unforeseen changes may require future alterations to the program portfolio to better meet community needs, respond to changing statutory requirements, or adapt to technology changes. Throughout the planning horizon, program offerings will be assessed to determine how to provide the best value to customers and optimize energy efficiency impacts. Areas of opportunity that may be considered to increase program energy savings or demand reduction include but are not limited to the following:

Residential and commercial new construction programs
Residential and commercial behavioral programs
t ii a Yr, i ir r f' rr,, i i i, a, 1=; rir. r, l- fi. ir rir, 3i ii i I", r5rn ii i I r ar5r ii, ar 1 1r=, ar iii. r; Packet Pg. 531 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric Commercial retro- commissioning

5. 5 DEMAND RESPONSE PROGRAMS
The CEC encourages POUs to include in the IRP Filing the expected quantitative impacts of planned price-sensitive demand response measures that are proposed, or being considered for future implementation (for example, time-of-use rates), including discussion of POU demand response programs.

Analysis of large customers has been conducted to determine if any have the ability to shift load during periods of high demand. Due to the limited potential for load shifting, there are no current demand response programs or time- of-use rates offered to customers. In the future, time- of-use rates may be offered to non-residential customers; however, the expected impact of new time-ofuse rates on peak load are expected to be negligible given the current limited ability of large customers to shift significant amounts of energy load.

No ° No' u u; , u f aru!
Energy storage ( ES) includes batteries and other technologies such as chillers that can store energy for use at a future time. According to the ES Bill ( AB 2514, signed into law in 2010), an ES system shall do one or more of the following:
1) Use mechanical, chemical, or thermal processes to store energy that was generated at one time for use at a later time.
2) Store thermal energy for direct use for heating or cooling at a later time in a manner that avoids the need to use electricity at that later time. 3) Use mechanical, chemical, or thermal processes to store energy generated from renewable resources for use at a later time.
4) Use mechanical, chemical, or thermal processes to store energy generated from mechanical processes that would otherwise be wasted for delivery at a later time.

ES can be effective in reducing system peaks and providing energy at the time of day when it is of most value. It can be viewed as a stand- alone resource, or it can be coupled with a renewable resource such as wind or solar and used to" firm- up" intermittent resources to some degree. Costs for ES have decreased significantly in recent years and the cost decrease is expected to continue in the coming years ( see Section 6 for assumptions in this IRP).

The first Thermal Energy Storage ( TES) system was installed in 2005 ( a chiller-based system at Redding Municipal Airport and another direct expansion TES system at the Redding Fire Department). TES systems are well- suited for warm climates as they shift electrical demand from peak hours to shoulder or off-peak hours, thereby creating value to customers. This participation in the ES market was, in part, a response to AB 2514 and AB 2227.

AB 2514 requires load serving entities to evaluate whether ES procurement targets should be adopted. With approval by the Council in 2012, a contract was executed with a primary TES supplier, Ice Energy, to evaluate the TES capacity that could be cost- effectively installed in COR' s service area. The analysis determined that up to 14 MW of permanent load shifting could be achieved through TES programs.
t ii a Yr, i ir r f' rr,, i i i, a, 1=; rir. r, l- fi. ir rir, 3i ii i I", r5rn ii i I r ar5r ii, ar 1 1r=, ar iii. r; Packet Pg. 532 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric In 2014, ES targets adopted were 3. 2 MW for 2016 and 4.4 MW for 2020. This compares to actual achieved ES capacity of 3. 6 MW by mid- 2017. Due to changing load conditions (lower sales, reduced peak growth) in the state and service area, in October 2017, it was recommended that the 2020 storage target should be set equal to the 2017 achieved capacity of 3. 6 MW.11 Maintaining this level of TES ( 3. 6 MV was assumed in the IRP load forecast.

AB 2227 required utilities to submit a report on progress toward adopted ES goals. The report, submitted to the CEC on December 29, 2016, showed adequate progress with regards to the goals adopted by the Council in 2014. Plans are in place to continue to evaluate the potential benefits of additional ES as part of the IRP process going forward. To date, more than$ 6 million has been expended on the TES Program.
u u
po
ur '
y', II IIi drll nC 7II ui drl o-°:' II a. 711 ih, IIn" 411" II V ItII I" 411"° m l Il ia° 7IVV". uIV.' W To evaluate the potential benefits of adding ES, Black& Veatch was commissioned to perform a stochastic analysis on the load and generation in order to estimate the deviation of actual hourly load, less generation ( Interchange Load), compared to scheduled hourly Interchange Load. In the analysis, Black& Veatch also included a case where a 10 MW Solar PV Project( Solar Project) was included in COR' s Interchange Load.

The stochastic analysis was performed utilizing Palisade Corporation' s @RISK software; @Risk is a Microsoft Excel add- in used to perform stochastic analyses. The 95 percent confidence intervals with and without the Solar Project were compared to assess whether the addition of the Solar Project impacted deviation from scheduled net interchange.

In comparing the stochastic net interchange deviations from the schedule, with and without the addition of the Solar Project, it was observed, based on the stochastic analysis, that there was not a significant impact to the scheduled interchange deviations when comparing the case with 10 MW of solar PV generation to the case without the Solar Project. It was observed from the modeled results that interchange deviation for cases" with and without" the Solar Project were at times wider than the +- 8 MW( 6 MW, plus 2 MW for the contracted load with COSL) deviation band which COR has contracted with WAPA. A detailed report on the stochastic intermittency analysis is included in Appendix C.

Analysis shows that addition of an ES system would ease decreasing deviations from hourly interchange schedules. Consideration and evaluation of the future addition of ES to smooth load and generation would continue, along with plans to investigate other contractual products which could help manage the cost of scheduled interchange deviations. The impact of future increases in renewable generation, or contracted renewable generation, on Interchange Load deviation from schedule will also be considered. The level of impact on Interchange Load due to the addition of these resources will likely be dependent on the resource scale and level of shaping of the resource e.g. inclusion of ES in an owned resource or contractual shaping included in a PPA). Determination ofthe least-cost ES solution will be the subject of a future study. 11 City of Redding Report to Redding City Council, Daniel Beans, September 19, 2017. t ii a Yr, i ir r f' rr,, i i i, a, 1=; rir. r, l- fi. irrir, 3i ii i r5rn ii i I r ar5r ii, ar 1 1r, ar iii. r; 7 Packet Pg. 533 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric

5. 6 TRANSPORTATION ELECTRIFICATION
A number of studies have been performed and initial steps have been taken to encourage increased penetration of EVs. The highlights of these activities are summarized below:

A residential EV Rebate Program began in August 2017. Under this Program, incentives of 1, 000 per new vehicle purchased or leased is available, and another$ 500 is available for infrastructure cost of a Level II EV charger is installed at the customer' s home. 12 As of May 2018, a total of 34 vehicles qualified for the EV Rebate Program.

A dedicated webpage has been created, as well as an e- mail address where customers can reach out to staff for questions or comments regarding EVs. During the kickoff of the EV Rebate Program, staff inet with local dealers to educate them on EVs and available rebates. A Ride- and- Drive Program is currently in the works as a means to further educate our customers and spark interest.

A City-wide study to develop an infrastructure plan for the installation of EV charging stations ( EVCS) is currently underway and will evaluate the best EVCS locations, optimal number of charging stations, and will estimate power requirements and areas where new or upgraded electrical service is required. Once the study is complete, an implementation plan will be developed and itis anticipated that petrol vehicles will be replaced by EVs where and when it is practical.

COR has procured or help procure the following:

One electric bus for Redding Area Bus Authority- supplied monies to help RABA secure full grant amount
Three electric" Mean Green" lawn mowers for the City of Redding Facilities Maintenance Department
Three electric carts for the City of Redding Police Department Two electric carts for the City of Redding Parks Department lz A Level 2 charger provides 240 VAC and charges in 4- 8 hours, the equivalent of 12- 20 miles per hour of charge. t ii a Yr, i ir r f' rr,, i i i, a, 1=; r r. r, I-: i. ir rir, 3i ii I, r 5rr ii I r ar5r ii, ar 1 1r=, ar iii. r a a.. f Packet Pg. 534 Attachment: Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services (4.5(b)--Approve Redding Electric iir iii° iii ii ... iir ... ii iir ... II° iii ii
The development of the load forecast allows a comparison of capacity requirements with existing and additional near-term resources. The result will highlight the adequacy of existing and nearterm additional resources and their ability to meet energy needs and comply with RE requirements during the 2018- 2037 planning period; this determination will be done for a scenario that contemplates continued operation of existing resources to meet future requirements.

Sufficient existing and near-term capacity resources exist to meet its projected peak demand and planning reserve requirements over the study period. However, additional RE resources will be necessary to meet RPS requirements and added RE resources will promote further GHG emission reductions. The need for additional renewable resources established in this section leads to the development of several Scenarios that are modeled and presented from an economic cost and RE perspective in Section 8.

Redding City CouncilMay 5, 2026

Redding City Council
May 5, 2026