Agenda Packet — Redding City Council, February 15, 2022 (part 1 of 5)

Agenda
Regular Meeting
Redding City Council
Council Chambers (Doors open 30 minutes prior)
777 Cypress Avenue
Redding, CA
February 15, 2022
6:00 PM
The City Council Chambers are fully open to the public in compliance with current guidelines from the California Department of Public Health regarding indoor meetings with the requirement that masks be worn in all indoor public settings, irrespective of vaccine status from December 15, 2021, through February 15, 2022.

1. CALL TO ORDER - MAYOR KRISTEN SCHREDER
A. Pledge of Allegiance
B. Invocation - Pastor Dayton Phillips, Hope Baptist Church C. Roll Call

2. PRESENTATIONS
2A. Presentation of City of Redding Appreciation Clock to Mimi Moseley for her service on the Community Development Advisory Committee from November 7, 2017, to November 30, 2021.
2B. Presentation by Todd Jones, President of the Shasta Economic Development Corporation, providing an update on past, present, and future activities.

If anyone wishes to address the City Council on any item considered at this meeting before or during Council’s consideration of that item, please fill out a blue Speaker Request Form, located in the lighted alcoves at the back of the Council Chambers, and submit it to the City Clerk. The City Council will allocate up to a maximum of three minutes per speaker for each agenda item. Staff reports are available on-line at the City’s web site at www.cityofredding.org or in the Public View binder located on the podium at the north side of the Chambers.

PLEASE SILENCE YOUR CELL PHONES. THANK YOU.

Redding City Council February 15, 2022

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3. PUBLIC COMMENT - for non-agendized matters within the City’s jurisdiction.

4. CONSENT CALENDAR
The Consent Calendar contains items considered routine and/or which have been individually scrutinized by City Council Members and are anticipated to require no further deliberation. If a member of the public wishes to address an item on the Consent Calendar, please fill out a Speaker Request Form and submit it to the City Clerk before the Consent Calendar is considered. It shall be the prerogative of any Council Member, before the Consent Calendar is acted upon, to: (1) comment on an item; (2) respond to any public comment on an item; (3) request the record reflect an abstention or nay vote on an item; or (4) remove an item and place it on the Regular portion of the agenda for delivery of a staff report and/or an extended discussion or deliberation. 4(a). Approve Minutes: Special Meeting – Civic Auditorium Workshop No. 4 of November 18, 2021; Regular Meeting of December 7, 2021; Special Meeting – Closed Session of December 21, 2021; Regular Meeting of December 21, 2021; Special Meeting – Closed Session of January 5, 2022; and Special Meeting – Closed Session of January 18, 2022.
4(b). Accept City of Redding Accounts Payable Register No. 14; and Payroll Register No. 15.
4(d). Accept the City of Redding Proof of Cash reconciliation and ACR133 report for the month of December 2021.

4.1(a). Accept report and make a determination by a four-fifths (4/5ths) affirmative vote that conditions of local emergency continue to exist within the City of Redding, under Public Contract Code section 22050(c)(1) related to the Coronavirus (COVID-19).

4.1(c). Adopt Resolution ratifying approval of the following actions:
(1) Submission of grant application to the California Department of Forestry and Fire Protection Fire Prevention grant program;
(2) Certifying that the City of Redding meets grant requirements; and (3) Authorizing the City Manager, or designee, to execute and submit documents, and conduct negotiations related to the grant program in the total amount of $520,000, which must be expended by March 15, 2026, for the City of Redding Community Fire Risk Reduction Program project.

PURSUANT TO THE BROWN ACT, CITY COUNCIL CANNOT TAKE ACTION ON PUBLIC

COMMENT ITEMS
The City Council will allocate up to a maximum of three minutes per speaker for 30 minutes total, at the beginning of the meeting for Public Comment for non-agendized matters within the City’s jurisdiction.

The Mayor will determine the order of the speakers. If 30 minutes is not adequate to accommodate all of the individuals who have submitted a Speaker Request Form to the City Clerk, the Council will trail this item to the end of the open session agenda. The remaining speakers will address the City Council at that time.

Redding City Council February 15, 2022

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4.4(a). Authorize the following actions regarding the Regional Early Action Planning grant agreement with the County of Shasta and the City of Shasta Lake to assist with the City of Redding’s General Plan Update:
(1) Approve and authorize the Mayor to execute the Memorandum of Understanding between County of Shasta and City of Shasta Lake for administration of the grant funds awarded by California Department of Housing and Community Development through the Regional Early Action Planning Grants Program; and
(2) Authorize the Mayor, or designee, to execute all documents necessary to accept the grant as awarded.

4.5(a). Approve purchase of Digger Derrick-Tracked Backyard truck using Sourcewell contract pricing with Altec Industries, Inc. in the amount of $245,000, including taxes and fees, for the Redding Electric Utility.

4.5(b). 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, to execute the Agreement and any future amendments.

4.6(a). Authorize and approve the following actions relative to Request for Proposal Schedule No. 5260, to furnish limited food and beverage service at Redding City Hall:
(1) Award to Heritage Coffeehouse;
(2) Authorize the Community Services Director to negotiate a three-year term effective on or before April 1, 2022, through March 31, 2025, with three one-year options to unilaterally extend the term; and (3) Authorize the City Manager, or designee, to execute the contract, and any future amendments and extensions.

4.11(a). Approve the following actions relative to the City of Redding Local Road Safety Plan (LRSP):
(1) Adopt Resolution approving the LRSP; and
(2) Find that the action is statutorily exempt from environmental review under the California Environmental Quality Act pursuant to Section 15262 – Feasibility and Planning Studies.

4.11(b). Authorize the following actions regarding the Westside Sewer Interceptor Phase Three Project for the City of Redding Wastewater Utility:
(1) Adopt Mitigated Negative Declaration, including the Mitigation Monitoring Program;
(2) Approve Westside Sewer Interceptor Phase Three Project as described; and
(3) Direct staff to file a Notice of Determination with the Shasta County Clerk’s Office and the State Clearinghouse, thereby satisfying requirements of the California Environmental Quality Act (CEQA Guidelines §15074).

Redding City Council February 15, 2022

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4.11(c). Authorize purchase of one 2022 Doppstadt Inventhor Type 6 Slow-Speed Shredder from Ecoverse Industries, Ltd., using Houston-Galveston Area Council Buy contract pricing, with a net delivered cost of $671,981.20, including all applicable taxes and fees, for the City of Redding Solid Waste Utility.

4.11(d). Adopt Resolution authorizing the City Manager, or the Director of Public Works, to sign Master Agreement No. 02-0568S21, including revisions and program supplement agreements, with the California Department of Transportation for State of California funded projects.

4.11(e). Authorize the following actions relative to the Old Oregon Trail Safety Improvement Project:
(1) Adopt Mitigated Negative Declaration and Mitigation Monitoring Program;
(2) Approve Old Oregon Trail Safety Improvement Project as described, thereby satisfying the requirements of the California Environmental Quality Act (CEQA Guidelines §15074); and
(3) Direct staff to file a Notice of Determination with the Shasta County Clerk’s Office and the State Clearinghouse.

4.11(f). Authorize purchase of Atlas Copco blower in the amount of $190,948.53 for the City of Redding Clear Creek Wastewater Treatment Plant; and approve additional funding in an amount not to exceed $30,000 for shipping and handling, taxes, and start-up and commissioning services.

4.11(g). Accept Bid Schedule No. 5177 (Job No. 3650), CARR Fire Buenaventura Trail Ten Bridges Project, awarded to SNL Group Inc., as satisfactorily complete, with a final cost of $658,538.

4.11(h). Authorize the following actions relative to Bid Schedule No. 5263 (Job No. 2629) Magnolia Area Sewer Improvements Phase One Project:
(1) Award to Jason Abel Construction, Inc., in the amount of $6,330,696.50; (2) Approve an additional $1,006,000 to cover the cost of administration and inspection fees and $250,000 for project development costs; (3) Approve $630,000 to provide construction contingency funding; (4) Authorize the City Manager to approve additional increases in either the construction management or construction contingency amounts up to a total of $50,000;
(5) Find that the project is categorically exempt from review under the California Environmental Quality Act Guidelines 15302 (c) - Replacement or Reconstruction; and
(6) Adopt Resolution approving and adopting the 27th Amendment to City Budget Resolution No. 2021-078 appropriating $200,000 in funding for the project.

4.11(i). Accept update on the City of Redding’s COVID-19 Local Economic Stimulus Package projects.

Redding City Council February 15, 2022

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4.11(j). Authorize the following actions relative to capital project execution at City of Redding (City) Airports:
(1) Adopt Resolution authorizing the filing of three grant applications with the Federal Aviation Administration for Airport Improvement Program funding for the following projects: (a) Airport Master Plan Update and Airport Master Drainage Plan at Redding Municipal Airport; (b) Runway and Taxiway Connector Pavement Preservation and Magnetic Variations (MAGVAR) Updates Project at Benton Airpark; and (c) authorizing a subsequent application for California Department of Transportation Airport Improvement Program Matching Grant funds for the Runway and Taxiway Connector Pavement Preservation and MAGVAR Updates Project at Benton Airpark;
(2) Adopt Resolution approving and adopting the 28th Amendment to City Budget Resolution No. 2021-078 appropriating an additional $2,208,660 to the City’s Airport Fund; and
(3) Authorize City Manager, or designee, to execute grant applications, submit all subsequent documentation necessary to obtain grant funds for the projects, and appropriate all grant funds received to the Airport Fund in accordance with the Airports Capital Improvement Plan.

4.15(a). Adopt Resolution formally certifying the unit modification of the International Brotherhood of Electrical Workers Local Union 1245 AFL-CIO Electric Employees Unit (IBEW Electric Unit) acknowledging IBEW Electric Unit as the Exclusively Recognized Employee Organization for the classification of Electrical Technician in accordance with the City of Redding’s EmployerEmployee Relations Resolution and the Myers-Millias-Brown Act, effective February 15, 2022.

4.15(b). Adopt Resolution confirming the agreement between the City of Redding and the Classic Unrepresented Non-Safety Employees and Elected Officials Group for additional cost sharing of employer contributions to the California Public Employees Retirement System.

RECOMMENDATION: ACCEPT, ACKNOWLEDGE, ADOPT, APPROVE,
AND/OR AUTHORIZE ALL ITEMS ON THE CONSENT CALENDAR.

Redding City Council February 15, 2022

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6. PUBLIC HEARINGS
A court challenge to action taken by the City Council on any project or decision may be limited to only those issues raised during the public hearing or in written correspondence delivered to the City Council during, or prior to, the public hearing.

Development Services

6.1. Continued Public Hearing to consider General Plan Amendment, Rezoning, and Specific Plan Amendment Applications; and the Resolution and Ordinance associated with the adoption of the proposed Downtown Redding Specific Plan Update.

Recommendation:

Reconvene the public hearing opened at the City Council Meeting of December 7, 2021, and continued on December 21, 2021, and January 18, 2022, and upon conclusion:
(1) Adopt Resolution: (a) adopting the Addendum to the Negative Declaration adopted for the Downtown Redding Specific Plan; (b) adopting the addendum to the mitigated negative declaration prepared for the City of Redding Zoning Map; (c) adopting amendments to Redding’s General Plan (General Plan Amendment Application GPA-2021-00449); and (d) amending the City of Redding Schedule of Fees and Service Charges;
(2) Offer Ordinance for first reading by title only and waive the full reading: (a) adopting the Addendum to the Negative Declaration adopted for the Downtown Redding Specific Plan; (b) adopting the Addendum to the Mitigated Negative Declaration prepared for the City of Redding Zoning Map; (c) adopting the Downtown Redding Specific Plan Update (Specific Plan Amendment Application AMND-2021-00361); (d) approving amendments to Redding Zoning Map (Rezoning Application RZ-2021- 00450); (e) making findings in support of a general plan consistency determination; and direct the City Attorney to prepare a summary ordinance, and authorize the City Clerk to publish the summary ordinance according to law; and
(3) Find that the Addendum to the Negative Declaration adopted for the Downtown Redding Specific Plan and the Addendum to the Mitigated Negative Declaration adopted for the City of Redding Zoning Map are adequate to comply with the requirements of the California Environmental Quality Act, and the necessary findings for approval are in evidence.

Redding City Council February 15, 2022

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Deputy City Manager

6.2. Public Hearing to consider adopting a Resolution approving submission of the 2021-22 Home Investment Partnership Program – American Rescue Plan Program (HOME-ARP) Allocation Plan (Plan).

Recommendation:

Conduct a public hearing and, upon conclusion, adopt Resolution approving submission of the HOME-ARP Plan; and authorize the City Manager, or designee, to sign all necessary documents and forward the Plan to the U.S. Department of Housing and Urban Development.

Public Works

6.3. Public Hearing to consider Resolution approving the Five-Year Capital Improvement Plan for the City of Redding (City).

Recommendation:

Conduct a Public Hearing and, upon conclusion, adopt Resolution approving the City’s Capital Improvement Plan for Fiscal Years 2021−22 to 2026−27.

9. REGULAR CALENDAR: REPORTS & COMMUNICATIONS OF DEPARTMENTS,

BOARDS, COMMISSIONS AND COMMITTEES
Electric Utility

9.5(c). Consider Redding Electric Utility's Quarterly Financial Report and Industry Activities Update.

Recommendation:

Accept Redding Electric Utility’s Fiscal Year 2021-22 Second Quarter Financial Report and Industry Activities Update.

Public Works

9.11(k). Oral report regarding City of Redding Traffic Calming Program.

Recommendation:

Accept oral presentation.

Redding City Council February 15, 2022

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11. COUNCIL TRAVEL REPORT(S)
City Council Member attendance at conference/meetings reimbursed at City expense. {Requirement of Assembly Bill 1234}
[A-050-060]
Information Only

12. SUGGESTIONS FROM COUNCIL MEMBERS RELATIVE TO POTENTIAL TOPICS

FOR FUTURE CITY COUNCIL MEETINGS

13. ADJOURNMENT
Pursuant to the Brown Act, non-confidential materials related to an item on this agenda submitted to the City Council after distribution of the agenda packet are available for inspection during normal business hours at the Office of the City Clerk, 3rd Floor, City Hall, 777 Cypress Avenue, Redding, California.

City Council Meetings will be televised live on Shasta Community Access Channels via Charter/Spectrum Cable channel 181, and will be rerun on Thursday at 12:30 p.m. during the week in which the meeting is held. Additionally, the meeting can be viewed online at the following: http://scac.cablecast.tv:8080/CablecastPublicSite/watch/4?channel=1. Video of the City Council meetings can also be viewed on the City’s web site at http://www.cityofredding.org/. Open the City’s meetings and agendas portal; Click on tab named "Meetings Videos" and select Redding City Council under “Available Archives 2022” select the desired date, then click on “video” to view the meeting.

In compliance with Title II of the Americans with Disabilities Act, the City of Redding will make available to persons with disabilities modifications or accommodations including auxiliary aids or services necessary to participate in public meetings. A person needing assistance should contact the Redding City Clerk by telephone at (530) 225-4447 or in person, or by mail at 777 Cypress Avenue, 3rd Floor, Redding, California 96001 at least three (3) working days in advance.

The City of Redding will ensure that no person shall be excluded from participation in, denied the benefits of, or otherwise be subjected to discrimination under any of its projects, activities, services, or business opportunities on the basis of race, color, national origin, age, sex, or disability, as afforded by Title VI of the Civil Rights Act of 1964 and related statutes as amended. All persons, regardless of their citizenship status, are covered under this regulation.

Questions, complaints, or requests for accommodations or additional information may be forwarded to the ADA & Title VI Coordinator at 777 Cypress Avenue, Attn: Personnel Dept., Redding, California 96001, Phone (530) 225-4065.

CITY OF REDDING

REPORT TO THE CITY COUNCIL
Recommendation
Presentation of City of Redding Appreciation Clock to Mimi Moseley for her service on the Community Development Advisory Committee from November 7, 2017, to November 30, 2021.

MEETING DATE: February 15, 2022
ITEM NO. 2A
FROM:
***APPROVED BY***
[email protected]
[email protected]
SUBJECT: 2A--Presentation of City of Redding Appreciation Clock to Mimi Moseley Pamela Mize, City Clerk
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CITY OF REDDING

REPORT TO THE CITY COUNCIL
Recommendation
Presentation by Todd Jones, President of the Shasta Economic Development Corporation, providing an update on past, present, and future activities.

MEETING DATE: February 15, 2022
ITEM NO. 2B
FROM:
***APPROVED BY***
[email protected]
SUBJECT: 2B--Presentation by Todd Jones, President of the Shasta Economic Development Corporation.

Janelle Galbraith, Economic
Development, Innovation &
Equity Manager
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CITY OF REDDING

REPORT TO THE CITY COUNCIL
Recommendation
Approve Minutes: Special Meeting – Civic Auditorium Workshop No. 4 of November 18, 2021; Regular Meeting of December 7, 2021; Special Meeting – Closed Session of December 21, 2021; Regular Meeting of December 21, 2021; Special Meeting – Closed Session of January 5, 2022; and Special Meeting – Closed Session of January 18, 2022.

Attachments
Unofficial Minutes - November 18, 2021 - Special Meeting - Civic Auditorium Property Workshop No. 4 (available online)
Unofficial Minutes - December 7, 2021 - Regular Meeting (available online) Unofficial Minutes - December 21, 2021 - Special Meeting - Closed Session (available online) Unofficial Minutes - December 21, 2021 - Regular Meeting (available online) Unofficial Minutes - January 5, 2022 - Special Meeting - Closed Session (available online) Unofficial Minutes - January 18, 2022 - Special Meeting - Closed Session (available online) MEETING DATE: February 15, 2022
ITEM NO. 4(a)
FROM:
***APPROVED BY***
[email protected]
[email protected]
SUBJECT: 4(a)--Approve City Council Minutes.

Pamela Mize, City Clerk
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465
11/18/2021
Unofficial Minutes
Redding City Council, Special Meeting
Civic Auditorium Property Workshop No. 4
777 Cypress Avenue
Redding, CA 96001
November 18, 2021, 5:15 PM
The City Council Chambers are fully open to the public and in compliance with current guidelines from the California Department of Public Health regarding indoor meetings.

The meeting was called to order by Mayor Erin Resner with the following Council Members present: Michael Dacquisto, Mark Mezzano, Kristen Schreder, and Julie Winter.

Also present were: City Manager Barry Tippin, City Attorney Barry DeWalt, Economic Development, Innovation, and Equity Manager Janelle Galbraith, City Clerk Pamela Mize, and Executive Assistant Luisa Klapperich.

City Manager Tippin noted that this is the final workshop regarding the Civic Auditorium Properties.

PRESENTATION REGARDING THE VARIOUS AVAILABLE OPTIONS FOR THE CITY OF

REDDING-OWNED CIVIC AUDITORIUM PROPERTIES AND THE STEPS REQUIRED

FOR EACH
3(a). Summary report associated with the City of Redding-owned properties that include the Rodeo Grounds, Civic Auditorium, Turtle Bay Exploration Park, and associated open space.

City Manager Tippin provided a PowerPoint presentation and summarized the Report to City Council (staff report), both incorporated herein by reference. He provided an overview of the six options contained in the staff report for the Council’s consideration.

Shannon Phillips, Chief Operating Officer for The McConnell Foundation, and Michael Lockwood, Principal-in-Charge for Populous, provided a PowerPoint presentation, incorporated herein by reference.

The following speakers expressed support for the development of the property: Bennett Gooch, Redding Rodeo Association, Rick Boudro, President of Asphalt Cowboys, Julie Dyer, Advanced Redding, Mimi Moseley, Jake Mangas, Tyler Dunbar, Steve Williams, Matthew Wilson, Randi Slaughter, Kimberly Johnson, John Truitt, Tenessa Audette, Lynn Fritz, Mercy Kravitz, and Carrian Foster.

Senator Emeritus Maurice Johannessen recalled past projects within the City.

Katheryn McDonald proposed that citizens be included as key stakeholders in discussions regarding the property.

Brooke McDonald, Winter Hawk, Iverson, Robin Grissom, Michelle Radcliff-Garcia (Walking North), Jonathan Freeman, Robert Tryga, and Caleen Sisk spoke in opposition to the development of the property.

Arthur Garcia, representing the Wintu Tribe (Tribe), advised the Council to give the riverfront property back to the Tribe instead of selling it to private owners.

Jessie, Greg Burgin, Jr., and Richard Gallardo stated the riverfront property is of great significance to indigenous people and should be included as stakeholders in any decisions made regarding development of the property.

Steve Kohn and Stephanie Hughes opposed selling the property but favored the development of a Master Plan.

Julie Buick objected to the property being designated as surplus.

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Attachment: Unofficial Minutes - November 18, 2021 - Special Meeting - Civic Auditorium Property Workshop No. 4 (available online) (4(a)--Approve City Council Minutes) 466
11/18/2021
Misa Jōō favored a plan that included an environmental impact study at the beginning of the project.

Radley Davis and Rebeca Ladrón de Guevara, president of Wintu Audubon Society, asserted that environmental studies should be conducted before deciding to sell the property.

Kevin Crye opposed selling the property but was in favor of development.

Gary Cadd suggested that a public vote should determine the property’s future.

Kathy Grissom requested clarification of the areas being considered for sale.

Ronnean Land was impressed with the vision presented by Populous.

John Wilson complimented the openness of the workshops and opined that Council Member Winter should recuse herself due to conflict of interest issues.

Kathy Hill, Charles W., and Tim Garman supported the Council researching alternatives to improve/enhance the subject area.

A discussion amongst the Council ensued.

A MOTION WAS MADE by Council Member Dacquisto, seconded by Council Member Mezzano to accept the summary report and take no action.

The Vote:

AYES: Council Members – Dacquisto and Mezzano
NOES: Council Members - Schreder, Winter, and Resner
ABSTAIN: Council Members - None
ABSENT: Council Members - None
A MOTION WAS MADE by Council Member Winter, seconded by Council Member Schreder, to accept the summary report and direct staff to: (1) continue developing information regarding the subject properties; refine the information already developed; and create plans for next steps to develop the properties and/or change the use of the properties whether or not for public or private enterprise; (2) research alternatives which would allow development/improvement to the area without the requirement to declare the property surplus and look to other cities and meet with the parties who made the initial unsolicited proposal and make determinations whether other options may exist to create a public/private partnership to improve/enhance the subject area; and (3) begin the process to surplus identified properties and simultaneously continue the direction provided in item one (1). The direction to staff is to gather information and to return to the City Council for consideration at a future date.

The Vote:

AYES: Council Members - Mezzano, Schreder, and Winter
NOES: Council Members - Dacquisto and Resner
ABSTAIN: Council Members - None
ABSENT: Council Members - None

ADJOURNMENT
There being no further business, Mayor Resner declared the meeting adjourned at the hour of 8:30 p.m.

APPROVED:
_______________________________
Erin D. Resner, Mayor
ATTEST:
_______________________________
Pamela Mize, City Clerk
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Attachment: Unofficial Minutes - November 18, 2021 - Special Meeting - Civic Auditorium Property Workshop No. 4 (available online) (4(a)--Approve City Council Minutes) 469
12/07/2021
Unofficial Minutes
Redding City Council, Regular Meeting
Civic Center Council Chambers
777 Cypress Avenue
Redding, CA 96001
December 7, 2021, 6:00 PM
The City Council Chambers are fully open to the public in compliance with current guidelines from the California Department of Public Health regarding indoor meetings.

The meeting was called to order by Mayor Erin Resner with the following Council Members present: Michael Dacquisto, Mark Mezzano, Kristen Schreder, and Julie Winter.

Also present were: City Manager Barry Tippin, Assistant City Manager Sheri DeMaagd, City Attorney Barry DeWalt, City Clerk Pamela Mize, and Executive Assistant Luisa Klapperich.

The Pledge of Allegiance to the Flag was led by Mayor Resner.

The Invocation was provided by Lori Moretti, Redding Police and Fire Departments' Chaplain.

PRESENTATIONS
2A. Reorganization of the City Council - Selection of Mayor, Vice Mayor, and Mayor Pro Tempore.

A MOTION WAS MADE by Council Member Winter, seconded by Council Member Mezzano, to appoint Council Member Schreder to serve as Mayor, Council Member Mezzano to serve as Vice Mayor, and Council Member Winter to serve as Mayor Pro Tempore for one-year terms expiring at the first meeting in December 2023.

A MOTION TO AMEND WAS MADE by Mayor Resner, seconded by Council Member Mezzano, to appoint Council Member Schreder to serve as Mayor, Council Member Dacquisto to serve as Vice Mayor, and Council Member Mezzano to serve as Mayor Pro Tempore for one-year terms expiring at the first meeting in December 2023.

The Vote. Unanimous Ayes
2B. Presentation of Mayor’s Appreciation Gavel to Erin Resner.

Mayor Schreder presented Mayor Emeritus Resner with a Gavel Plaque of Appreciation for service as Redding Mayor from December 2020 to December 2021.

PUBLIC COMMENT
Mayor Schreder determined that no one present wished to address the items agendized for the Consent Calendar.

CONSENT CALENDAR
The following matters were considered inclusively under the Consent Calendar and each Report to City Council (staff report) is incorporated herein by reference:
4(a). Approve Minutes: Special Meeting – Civic Auditorium Workshop No. 2 of October 27, 2021.
4(b). Accept City of Redding Accounts Payable Register No. 9; and Payroll Register No. 9. (1) Accounts Payable Register No. 9 for the period of November 1, 2021, through November 12, 2021, for a total of $3,117,530.13 for check numbers 166750 through 167094, inclusive, ACH Transfer numbers 17692 through 17720 inclusive, Wire Transfer numbers 11052 through 11100, inclusive; and (2) Payroll Register No. 9 for the period of October 17, 2021 through October 31, 2021, in the amount of $3,550,587.99 for electronic deposit transaction numbers 545775 through 546681, inclusive, and check numbers 607431 through 607443, inclusive; SUMMARY TOTAL: $6,668,118.12.

Packet Pg. 14
Attachment: Unofficial Minutes - December 7, 2021 - Regular Meeting (available online) (4(a)--Approve City Council Minutes) 470
12/07/2021
4(c). Accept the City of Redding Treasurer’s Report for the month of October 2021.

4.4(a). Adopt Resolution No. 2021-138, a resolution of the City Council of the City of Redding, granting County of Shasta’s request to waive the 60-day noticing requirement for the lease of space located within the City of Redding limits, located at 3985 Eastside Road, for the temporary storage of property as needed, pursuant to the provisions contained in Government Code Section 25351.

4.4(b). Approve the following action relative to Bid Schedule No. 5207, Environmental Impact Report of the General Plan Update 2023: (1) authorize staff to negotiate a Consulting and Professional Services Contract with PlaceWorks for the preparation of an Environmental Impact Report, in amount not to exceed $442,833.00; (2) authorize the City Manager to approve amendment(s) to the contract for an additional total amount not to exceed $40,000; and (3) authorize the Mayor to execute the contract.

4.5(a). Authorize the increase of Purchase Order No. 113626 (awarded to Siemens Energy, Inc.) in an amount not to exceed $465,000, including taxes and shipping, for the purchase of nine additional 115 kV circuit breakers needed for Redding Electric Utility’s system.

4.6(b). Award Request for Proposal No. 5242, Landscape Maintenance District Services, to McEntire Landscaping, Inc. with an evaluated annual total cost of $410,760; and authorize the City Manager to execute the agreement for the period January 1, 2022, through December 31, 2022, and any subsequent extensions through December 31, 2026.

4.8(a). Adopt Resolution No. 2021-139, a resolution of the City Council of the City of Redding, approving and adopting the 21st Amendment to City Budget Resolution No. 2021-078 appropriating $65,420 for Fiscal Year 2022-23 for the addition of one full-time Administrative Assistant for Fire Administration.

4.8(b). Approve submission of a grant application to the Federal Emergency Management Agency, Assistance to Firefighters Grant, in the amount of $725,000 for the purchase of nine new base station radios and a station alerting system for the Redding Fire Department.

4.11(a).Adopt Resolution 2021-140, a resolution of the City Council of the City of Redding, summarily vacating a portion of Mark Street within the Map of Alta Subdivision recorded in Book Five of Maps at Page 53, Shasta County Records (A-2021-00490); and find this action consistent with the General Plan and categorically exempt from environmental review under the California Environmental Quality Act per Section 15061(3) - Common Sense Exemption.

4.11(b).Authorize the following actions relative to Bid Schedule No. 5238 (Job No. 2664) California Street Water Main Improvement Project (Project): (1) award to SnL Group, Inc. in the amount of $662,049; (2) approve an additional $120,000 to cover the cost of administration and inspection fees; and $120,000 for project development costs; (3) approve $70,000 to provide construction contingency funding; (4) authorize the City Manager to approve additional increases in either the construction management or construction contingency amounts up to a total of $15,000; and (5) find that the Project is categorically exempt from the California Environmental Quality Act per Section 15302(c) – Replacement or Reconstruction.

Packet Pg. 15
Attachment: Unofficial Minutes - December 7, 2021 - Regular Meeting (available online) (4(a)--Approve City Council Minutes) 471
12/07/2021

4.11(c).Authorize the following actions relative to Bid Schedule No. 5234 (Job No. 2644) South Bonnyview I-5 Bechelli Project: (1) award to JF Shea Construction in the amount of $3,403,836; (2) approve an additional $610,000 to cover the cost of administration and inspection fees; and $830,000 for project development costs; (3) approve $340,000 to provide construction contingency funding; (4) authorize the City Manager to approve additional increases in either the construction management or construction contingency amounts up to a total of $50,000; and (5) find that the Project is categorically exempt from the California Environmental Quality Act per Section 15302(c) – Replacement or Reconstruction.

4.11(d).Accept Bid Schedule No. 5108 (Job No. 2616/2620), Bechelli Lane Water and Sewer Project, awarded to Site Work Solutions, as satisfactorily complete, with a final cost of $11,169,591.95.

A MOTION WAS MADE by Council Member Resner, seconded by Council Member Mezzano, that the foregoing items on the Consent Calendar be accepted, acknowledged, adopted, approved, and/or authorized as recommended.

The Vote:

AYES: Council Members - Dacquisto, Mezzano, Resner, Winter, and Schreder NOES: Council Members - None
ABSTAIN: Council Members - None
ABSENT: Council Members - None
Resolution Nos. 2021-138 through 2021-140 are on file with the Office of the City Clerk.

PUBLIC HEARING(S)

6.1. Public Hearing to consider General Plan Amendment Application (GPA-2021-00449), Rezoning Application (RZ-2021-00450), and Specific Plan Amendment Application (AMND-2021-00361), and Resolution and Ordinance associated with the adoption of the proposed Downtown Redding Specific Plan Update.

Mr. Tippin summarized the Report to City Council and advised that an inadvertent defect was found in public notice. He advised the City Council to continue the public hearing to December 21, 2021 and to receive staff presentation at the continued meeting. However, he advised the Council to open the public hearing and hear comments from speakers regarding this matter.

The hour of 6:23 p.m. having arrived, Mayor Schreder opened the Public Hearing.

Kathryn McDonald opposed to extending the Downtown zone to the borders of her neighborhood.

David Ledger encouraged the preservation of historical areas of Redding.

The Affidavit of Publication – Notice of Public Hearing is on file in the Office of the City Clerk.

Mayor Schreder determined that no one else present wished to address this matter and closed the Public Hearing.

A MOTION WAS MADE by Council Member Mezzano, seconded by Council Member Resner, to continue the public hearing to 6:00 p.m., Tuesday, December 21, 2021.

The Vote: Unanimous Ayes.

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6.2. Public Hearing to consider Resolution approving Electric Utility rate increases, establishing a Multi-Family Rate class, and increasing the Residential Energy Discount.

Electric Utility Director Dan Beans provided a PowerPoint presentation and summarized the Report to City Council (staff report), both incorporated herein by reference.

A discussion amongst the council ensued.

The hour of 6:44 p.m. having arrived, Mayor Schreder opened the Public Hearing.

The Affidavit of Publication – Notice of Public Hearing is on file in the Office of the City Clerk.

Mayor Schreder determined that no one present wished to address this matter and closed the Public Hearing.

A MOTION WAS MADE by Council Member Mezzano, seconded by Council Member Winter, to: (1) adopt Resolution 2021-141, a resolution of the City Council of the City of Redding, to increase Redding Electric Utility’s rates by two percent effective January 1, 2022, and a second two percent rate increase effective January 1, 2023, for usage beginning on the first day of the first electric billing cycle; (2) establish a Multi-Family Rate class; and (3) approve increase to Residential Energy Discount Program benefits and find that the adoption of this Resolution is exempt from the California Environmental Quality Act under the common sense clause.

The Vote:

AYES: Council Members - Dacquisto, Mezzano, Resner, Winter, and Schreder NOES: Council Members - None
ABSTAIN: Council Members - None
ABSENT: Council Members - None
Resolution No. 2021-141 is on file in the Office of the City Clerk.

REGULAR CALENDAR: REPORTS & COMMUNICATIONS OF DEPARTMENTS,

BOARDS, COMMISSIONS AND COMMITTEES

9.5(b). Redding Electric Utility's 2021 Monitoring and Auditing Annual Report on Wildfire Mitigation, and the revised Wildfire Mitigation Plan.

Electric Utility Director Dan Beans provided a PowerPoint presentation and summarized the Report to City Council (staff report), both incorporated herein by reference.

A discussion amongst the council ensued.

A MOTION WAS MADE by Council Member Mezzano, seconded by Council Member Winter, to accept Redding Electric Utility’s 2021 Monitoring and Auditing Annual Report on Wildfire Mitigation; and approve the revised Wildfire Mitigation Plan pursuant to California Senate Bill 901. The Vote: Unanimous Ayes
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9.6(a). Amended and Restated Lease (C-5682) with Advance Redding for the Redding Civic Auditorium located at 700 Civic Auditorium Drive.

Council Member Winter recused herself from this agenda item based on a conflict of interest. Ms. Winter left the Council Chamber at 7:07 p.m.

Community Services Director Kim Niemer summarized the Report to City Council (staff report), incorporated herein by reference.

A discussion amongst the council ensued.

Julie Dyer, General Manager of Advanced Redding, provided a brief synopsis of Advance Redding’s past and future leasing and managing the City of Redding Civic Auditorium.

John Wilson opposed leasing the Redding Civic Auditorium.

Josh Divine, member of Community Services Advisory Committee, favored leasing the Redding Civic Auditorium to Advance Redding.

A MOTION WAS MADE by Council Member Resner, seconded by Council Member Mezzano, to authorize and approve the following actions: (1) approve Amended and Restated Lease Agreement (C-5682) with Advance Redding for the Redding Civic Auditorium located at 700 Civic Auditorium Drive, for a 10-year term, expiring in December 2031; an annual lease rate of $120,000 in calendar years 2022, and 2025-2031; annual lease rate adjustments based on Consumer Price Index in calendar years 2023 and 2024; and (2) find that the action is categorically exempt from review under the California Environmental Quality Act Guidelines pursuant to Section 15301 - Existing Facilities, because renewal of the lease will not result in a significant impact on the environment and will not cause an expansion of the existing use.

The Vote:

AYES: Council Members - Dacquisto, Mezzano, Resner, and Schreder NOES: Council Members - None
ABSTAIN: Council Members - Winter
ABSENT: Council Members - None
Council Member Winter returned to the Council Chambers at 7:41 p.m.

9.11(h).Oral report providing an update regarding the Enterprise Anderson Groundwater Sustainability Agency.

Water Utility Manager Josh Watkins provided a PowerPoint presentation and summarized the Report to City Council (staff report), both incorporated herein by reference.

A discussion amongst the council ensued.

The City Council took no formal action on this informational item.

ADJOURNMENT
There being no further business, at the hour of 7:56 p.m. Mayor Schreder declared the meeting adjourned.

APPROVED:
_______________________________
Kristen Schreder, Mayor
ATTEST:
_______________________________
Pamela Mize, City Clerk
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Unofficial Minutes
Redding City Council, Special Meeting
Civic Center Council Chambers
777 Cypress Avenue
Redding, CA 96001
December 21, 2021, 5:15 PM
The City Council Chambers are fully open to the public in compliance with current guidelines from the California Department of Public Health regarding indoor meetings with the requirement of masks to be worn in all indoor public settings, irrespective of vaccine status from December 15, 2021, through January 15, 2022.

The meeting was called to order by Mayor Kristen Schreder with the following Council Members present: Mark Mezzano, Erin Resner, and Julie Winter. Vice Mayor Michael Dacquisto was absent.

Also present were: City Manager Barry Tippin, Assistant City Manager Sheri DeMaagd, City Attorney Barry DeWalt, and Executive Assistant Luisa Klapperich called the roll prior to leaving the Closed Session meeting.

PUBLIC COMMENT
Mayor Schreder determined that no one present wished to address the items agendized for Closed Session.

CLOSED SESSION
At the hour of 5:18 p.m., Mayor Schreder opened the Special Meeting and announced that the Council would adjourn to Closed Session.
3A. Closed Session pursuant to California Government Code Section 54957.6:

CONFERENCE WITH LABOR NEGOTIATOR
Designated Agency Representative: Assistant City Manager/Personnel Director DeMaagd
Employee Organizations:

1. Local 1934 of International Association of Fire Fighters

2. International Brotherhood of Electrical Workers AFL-CIO-Electric Employees

3. Redding Independent Employees’ Organization-Clerical, Technical and Professional Unit

4. Redding Independent Employees’ Organization-Supervisory & Confidential Unit

5. United Public Employees of California–Redding Technical Unit Pursuant to Government Code section 54957.1(a), the City Council took no reportable action on this item.

ADJOURNMENT
There being no further business, Mayor Schreder declared the meeting adjourned at the hour of 5:58 p.m.

APPROVED:
_______________________________
Kristen Schreder, Mayor
ATTEST:
_______________________________
Sharlene Tipton, Assistant City Clerk
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Unofficial Minutes
Redding City Council, Regular Meeting
Civic Center Council Chambers
777 Cypress Avenue
Redding, CA 96001
December 21, 2021, 6:00 PM
The City Council Chambers are fully open to the public in compliance with current guidelines from the California Department of Public Health regarding indoor meetings with the requirement that masks be worn in all indoor public settings, irrespective of vaccine status from December 15, 2021, through January 15, 2022.

The meeting was called to order by Mayor Kristen Schreder with the following Council Members present: Mark Mezzano, Erin Resner, and Julie Winter. Vice Mayor Michael Dacquisto was absent.

Also present were: City Manager Barry Tippin, Assistant City Manager Sheri DeMaagd, City Attorney Barry DeWalt, Assistant City Clerk Sharlene Tipton, and Executive Assistant Luisa Klapperich.

The Pledge of Allegiance to the Flag was led by Mayor Schreder.

The Invocation was provided by Lori Moretti, Redding Police and Fire Department Chaplain.

PRESENTATIONS
2A. Presentation recognizing the University Preparatory (U-Prep) School Girls Volleyball Team for winning the 2021 California Interscholastic Federation Division IV state volleyball championship on November 20, 2021.

The City Council took no formal action on this informational item. 2B. Presentation regarding Redding Electric Utility's 100th Anniversary.

Electric Utility Director Dan Beans highlighted the Report to City Council (staff report) and provided a PowerPoint presentation, both incorporated herein by reference.

The City Council took no formal action on this informational item.

PUBLIC COMMENT
Alex Bielecki opined that laws should apply to all and opposed recent decisions made by the federal government.

Nick Gardner expressed his frustration with the City Council for its decision to not appoint Vice Mayor Dacquisto, who was Mayor Pro Tempore at the time, as Vice Mayor in 2020.

CONSENT CALENDAR
The following matters were considered inclusively under the Consent Calendar and each Report to City Council (staff report) is incorporated herein by reference:
4(a). Approve Minutes: Special Meeting – Closed Session of November 2, 2021; Regular Meeting of November 2, 2021; and Special Meeting – Closed Session of November 16, 2021.

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4(b). Accept City of Redding Accounts Payable Register No. 10; and Payroll Register Nos. 10 and 11.
(1) Accounts Payable Register No. 10 for the period of November 13, 2021, through November 30, 2021, for a total of $18,216,382.82 for check numbers 167095 through 167409, inclusive, ACH Transfer numbers 17721 through 17792 inclusive, Wire Transfer numbers 11101 through 11136, inclusive; (2) Payroll Register No. 10 for the period of November 1, 2021 through November 13, 2021, in the amount of $3,702,075.46 for electronic deposit transaction numbers 546682 through 547607, and check numbers 607444 through 607485; and (3) Payroll Register No. 11 for the period of November 14, 2021 through November 27, 2021, in the amount of $3,650,933.77 for electronic deposit transaction numbers 547608 through 548511 inclusive, and check numbers 607486 through 607507, inclusive; SUMMARY TOTAL: $25,569,392.05. 4(d). Accept City of Redding Proof of Cash reconciliation and ACR133 report for the month of October 2021.

4.1(b). Authorize submission of grant application through California Homeless Coordinating and Financing Council Encampment Resolution Funding Program, in the amount of $950,000, to support the development and implementation of City of Redding programs addressing the ongoing shelter crisis; and authorize the City Manager, or designee, to sign the grant application and all applicable documents to complete the application and accept the grant funds.

4.2(a). Authorize the City Manager, or designee, to execute and record a Covenant to Pay Unpaid Water and Sewer Connection Fees and Traffic Impact Fees and Lien with LaFrance Development, LLC., for its mixed-use project located at 1212 South Street (Assessor Parcel No. 101-660-021).

4.3(a). Approve sole-source procurement of the Avigilon Access Control Manager from various resellers/installers, to become the City of Redding-wide solution for any current and future physical access control system needs.

4.5(a). Authorize the following actions related to repairs at the Redding Power Plant: (1) approve sole-source procurement of Allied Power Group’s services for the repair of Generator Unit 1’s compressor 9
th stage hook fit in the amount of $307,000, with a contingency of $43,000, for a total of $350,000; and (2) authorize the City Manager, or designee, to sign any documentation necessary to complete the work.

4.6(a). Approve the following actions relative to Request for Proposal No. 5250 for heating, ventilation, and air conditioning maintenance, repair, and replacement: (1) award to ACCO Engineered Systems with an annual fixed cost of $543,635.73 for the first two years; (2) authorize the Mayor to execute the contract for the period January 1, 2022, through December 31, 2023; (3) authorize the City Manager to execute any subsequent contract extensions through December 31, 2031, with annual cost adjustments, if needed, based on Consumer Price Index – All Urban Consumers, All items in West – Size Class B/C, not seasonally adjusted; (4) authorize the Parks and Facilities Manager, or designee, to add and delete locations/equipment on behalf of the City of Redding, during the contract term, which will be incorporated into the Contractor’s Scope of Work and annual contract cost; and (5) find that this project is categorically exempt from review under the California Environmental Quality Act Guidelines Section 15301 (a) and (d) – Existing Facilities.

4.6(b). Approve donation of one new riding floor-scrubbing machine, valued at $14,154.85, to Turtle Bay Exploration Park for cleaning the Sundial Bridge glass panels, related to Sundial Bridge maintenance agreement (C-4212).

4.8(a). Approve the conversion of three Apprentice Firefighter positions to three Firefighter positions.

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4.11(a).Award the lowest competitive bids relative to Bid Schedule No. 5245, Rock and Mineral Products, to J.F. Shea, Loucks Landscaping, Stimpel-Wiebelhaus, and Tullis, Inc. for the annual purchase of rock, asphalt, and mineral aggregates at an estimated cost of $350,000.

4.11(b).Accept Bid Schedule No. 5115 (Job No. 2482), Hartnell Avenue Safety Improvement Project, awarded to RTA Construction, Inc., as satisfactorily complete, with a final cost of $3,558,907.17.

4.11(c).Accept Bid Schedule No. 5165 (Job No. 9616), Cypress Avenue South Side Channel Restoration and Enhancement Project awarded to Steelhead Constructors, Inc., as satisfactorily complete, with a final cost of $1,957,584.23.

4.11(d).Award Bid Schedule No. 5247, for furnishing liquid chlorine and sulfur dioxide, to Thatcher Company, for a total annual evaluated cost of $488,485.25; and authorize the Purchasing Officer to approve annual contract amendments through December 31, 2026.

4.11(e).Authorize the following relative to the City of Redding’s COVID-19 Economic Stimulus Package projects: (1) accept an update on project progress; (2) ratify approval of the City Manager award for the Solar Photovoltaic Power Generation Systems at Various Fire Stations Project (C19-S-02) to Harbert Roofing, Inc. in the amount of $426,212.50; and (3) ratify approval of the City Manager award for the Civic Center Auditorium LED Lighting Retrofit project (C19-L-06) to Fluoresco Services, LLC in the amount of $77,386.80.

4.11(g).Approve the purchase of two 2023 Autocar ACX, 3 axle Rotopak Automated Side Loaders, and one 2023 Autocar ACX, 3 axle Sidewinder Automated Side Loader, using Sourcewell contract pricing, with a net delivered cost of $1,288,416.73, including all applicable taxes and fees for all three vehicles for the City of Redding Solid Waste Utility.

In response to Council Member Mezzano, Public Works Director Aukland explained that the City of Redding is preparing a phased approach to comply with the recently enacted Senate Bill 1383 regarding the ban of organic waste in landfills. Mr. Aukland noted that information regarding the City’s plan to collect and recycle such waste would be forthcoming by the end of the year.

4.12(a).Approve the Local Appointments List consisting of Exhibits A and B relative to 2022 term expirations and vacancies for City of Redding Boards, Commissions, and Committees to fulfill the requirements of Government Code Section 54972 (Maddy Act).

A MOTION WAS MADE by Council Member Winter, seconded by Council Member Resner, that the foregoing items on the Consent Calendar be accepted, acknowledged, adopted, approved, and/or authorized as recommended.

The Vote:

AYES: Council Members - Mezzano, Resner, Winter, and Schreder NOES: Council Members - None
ABSTAIN: Council Members - None
ABSENT: Council Members - Dacquisto

APPOINTMENT(S)

5.1. Mayor's appointments to the Community Development Advisory Committee.

A MOTION WAS MADE by Council Member Resner, seconded by Council Member Mezzano, to approve Mayor Schreder’s recommendation to appoint Hope Seth, Alexander Shea, and Aleta Carpenter to the Community Development Advisory Committee to serve three-year terms beginning December 1, 2021, and ending November 30, 2024.

The Vote:

AYES: Council Members - Mezzano, Resner, Winter, and Schreder NOES: Council Members - None
ABSTAIN: Council Members - None
ABSENT: Council Members - Dacquisto
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5.2. Mayor's appointment and reappointments to the City of Redding Community Services Advisory Commission.

A MOTION WAS MADE by Council Member Resner, seconded by Council Member Mezzano, to approve Mayor Schreder’s recommendation to: (1) appoint James Finck to the Community Services Advisory Commission to serve a four-year term beginning January 1, 2022, and ending December 31, 2025; and (2) reappoint Joshua Divine and Denise Yergenson to serve additional four-year terms ending December 31, 2025.

The Vote:

AYES: Council Members - Mezzano, Resner, Winter, and Schreder NOES: Council Members - None
ABSTAIN: Council Members - None
ABSENT: Council Members – Dacquisto

PUBLIC HEARING(S)

Planning Manager Lily Toy provided a PowerPoint presentation and summarized the Report to City Council (staff report), both incorporated herein by reference.

City Attorney DeWalt announced that Council Member Erin Resner has recused herself due to property ownership within the area under review. She left the room at 6:41 p.m.

The hour of 6:47 p.m. having arrived, Mayor Schreder opened the Public Hearing.

The Affidavit of Publication – Notice of Public Hearing is on file in the Office of the City Clerk.

The following spoke in opposition to extending Downtown Redding mapping: Kathryn McDonald, Susan Murray, Brooke McDonald, and Marie Campbell. .

Mayor Schreder determined that no one else present wished to address this matter and closed the Public Hearing.

In response to Kathryn McDonald’s concerns, both Mayor Schreder and City Manager Tippin noted that there are not different agendas posted on the City of Redding’s website and outlined the multiple ways to view and access the information.

A discussion amongst the Council ensued.

In response to Mayor Schreder’s request, City Attorney DeWalt provided a brief explanation describing the legal meanings of the terms “conflicts of interests” and “recusal” for Council Members and Planning Commissioners, noting that stakeholder groups are not subject to the same legal requirements.

A MOTION WAS MADE by Council Member Mezzano, seconded by Mayor Schreder, to continue the public hearing to the next regularly scheduled City Council meeting to be held at 6:00 p.m., on Tuesday, January 18, 2022.

The Vote:

AYES: Council Members – Mezzano, Winter, and Schreder
NOES: Council Members - None
ABSTAIN: Council Members - Resner
ABSENT: Council Members – Dacquisto
**Clerk’s Note: Council Member Resner returned to the room at 7:15 p.m.

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6.2. Public Hearing to consider Resolution amending the Permanent Local Housing Allocation Five-Year Plan.

Deputy City Manager Steve Bade summarized the Report to City Council (staff report), incorporated herein by reference.

The hour of 7:18 p.m. having arrived, Mayor Schreder opened the Public Hearing.

The Affidavit of Publication – Notice of Public Hearing is on file in the Office of the City Clerk.

Mayor Schreder determined that no one present wished to address this matter and closed the Public Hearing.

A MOTION WAS MADE by Council Member Resner, seconded by Council Member Mezzano, to conduct a public hearing to solicit comments to amend the Permanent Local Housing Allocation Five-Year Plan (PLHA Plan) and upon conclusion: (1) adopt Resolution No. 2021-142, a resolution of the City Council of the City of Redding, amending the PLHA Plan; and (2) authorize the City Manager, or designee, to sign all necessary State of California Department of Housing and Community Development (HCD) documents and forward the Resolution to HCD.

The Vote:

AYES: Council Members - Mezzano, Resner, Winter, and Schreder NOES: Council Members - None
ABSTAIN: Council Members - None
ABSENT: Council Members – Dacquisto
Resolution No. 2021-142 is on file in the Office of the City Clerk.

REGULAR CALENDAR: REPORTS & COMMUNICATIONS OF DEPARTMENTS,

BOARDS, COMMISSIONS AND COMMITTEES

9.9(a). Contract with Motorola Solutions, Inc. to upgrade existing records management system to the PremierOne platform.

Redding Police Lieutenant Christopher Smyrnos summarized the Report to City Council (staff report), incorporated herein by reference.

A discussion amongst the Council ensued.

A MOTION WAS MADE by Council Member Resner, seconded by Council Member Mezzano, to approve the contract with Motorola Solutions, Inc. (Motorola) in the amount of $1,265,000, on behalf of the Integrated Public Safety System, to upgrade the Police Records Management System to Motorola’s PremierOne platform.

The Vote:

AYES: Council Members - Mezzano, Resner, Winter, and Schreder NOES: Council Members - None
ABSTAIN: Council Members - None
ABSENT: Council Members - Dacquisto

9.11(f).Authorization of Service and Resolution to allocate funds for development of an Airport Strategic Plan.

Public Works Utility Director Chuck Aukland provided an overview of the Report to City Council (staff report), both incorporated herein by reference.

A discussion amongst the Council ensued.

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A MOTION WAS MADE by Council Member Resner, seconded by Council Member Winter, to authorize the following actions relative to development of an Airport Strategic Plan for the Redding Municipal Airport (C-8976): (1) adopt Resolution No. 2021-143, a resolution of the City Council of the City of Redding, approving and adopting the 22nd Amendment to City Budget Resolution No. 2021-078, appropriating $225,000 for the Airport Strategic Plan; and (2) approve Authorization of Service No. 21-05 with Mead & Hunt, Inc., for consulting services to develop the Airport Strategic Plan; and (3) authorize the City Manager, or designee, to execute the agreement, and any amendments, or additional documentation needed to facilitate the development of the strategic plan.

The Vote:

ADJOURNMENT
There being no further business, Mayor Schreder declared the meeting adjourned at the hour of 7:40 p.m.

APPROVED:
_______________________________
Kristen Schreder, Mayor
ATTEST:
_______________________________
Sharlene Tipton, Assistant City Clerk
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01/05/2022
Unofficial Minutes
Redding City Council, Special Meeting
Civic Center Council Chambers
777 Cypress Avenue
Redding, CA 96001
January 5, 2022, 5:30 PM
The City Council Chambers are fully open to the public in compliance with current guidelines from the California Department of Public Health regarding indoor meetings with the requirement of masks to be worn in all indoor public settings, irrespective of vaccine status from December 15, 2021, through January 15, 2022.

The meeting was called to order by Mayor Kristen Schreder with the following Council Members present: Michael Dacquisto, Mark Mezzano, Erin Resner, and Julie Winter.

Also present were: City Manager Barry Tippin and Executive Assistant Luisa Klapperich called the roll prior to leaving the Closed Session meeting. City Attorney Barry DeWalt participated telephonically.

PUBLIC COMMENT
Mayor Schreder determined that no one present wished to address the items agendized for Closed Session.

CLOSED SESSION
At the hour of 5:33 p.m., Mayor Schreder opened the Special Meeting and announced that the Council would adjourn to Closed Session.
3A. Closed Session pursuant to California Government Code Section 54957.6:

CONFERENCE WITH LABOR NEGOTIATOR
Designated Agency Representative: Assistant City Manager/Personnel Director DeMaagd
Employee Organizations:

1. Redding Peace Officers’ Association

2. Redding Peace Officers’ Association - Miscellaneous Employees

3. Redding Police Managers’ Association

4. Local 1934 of International Association of Fire Fighters

5. United Public Employees of California–Redding Fire Management Unit

6. United Public Employees of California–Redding Technical Unit

7. International Brotherhood of Electrical Workers AFL-CIO-Electric Employees

8. International Brotherhood of Electrical Workers AFL-CIO-Maintenance Employees

9. Redding Independent Employees’ Organization-Clerical, Technical and Professional Unit

10. Redding Independent Employees’ Organization-Supervisory & Confidential Unit

11. Unrepresented Employees
Pursuant to Government Code section 54957.1(a), the City Council took no reportable action on this item.

ADJOURNMENT
There being no further business, Mayor Resner declared the meeting adjourned at the hour of 6:43 p.m.

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APPROVED:
_______________________________
Kristen Schreder, Mayor
ATTEST:
_______________________________
Pamela Mize, City Clerk
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Attachment: Unofficial Minutes - January 5, 2022 - Special Meeting - Closed Session (available online) (4(a)--Approve City Council Minutes) 483
01/18/2022
Unofficial Minutes
Redding City Council, Special Meeting
Civic Center Council Chambers
777 Cypress Avenue
Redding, CA 96001
January 18, 2022, 5:15 PM
The City Council Chambers are fully open to the public in compliance with current guidelines from the California Department of Public Health regarding indoor meetings with the requirement of masks to be worn in all indoor public settings, irrespective of vaccine status from December 15, 2021, through February 15, 2022.

The meeting was called to order by Mayor Kristen Schreder with the following Council Members present: Michael Dacquisto, Mark Mezzano, Erin Resner, and Julie Winter.

PUBLIC COMMENT
Mayor Schreder determined that no one present wished to address the items agendized for Closed Session.

CLOSED SESSION
At the hour of 5:16 p.m., Mayor Schreder opened the Special Meeting and announced that the Council would adjourn to Closed Session.
3A. Closed Session pursuant to California Government Code Section 54956.8:

CONFERENCE WITH REAL PROPERTY NEGOTIATOR
Property Location: Stillwater Business Park, Lot 6; Assessor’s Parcel No. 054- 220-028
Agency Negotiator: City Manager Tippin
Negotiating Parties: City of Redding and Crosland Barnes Group Under Negotiation: Price and Terms
Pursuant to Government Code section 54957.1(a), the City Council took no reportable action on this item.
3A. Closed Session pursuant to California Government Code Section 54957.6:

CONFERENCE WITH LABOR NEGOTIATOR
Designated Agency Representative: Assistant City Manager/Personnel Director DeMaagd
Employee Organization: United Public Employees of California–Redding Technical Unit
Pursuant to Government Code section 54957.1(a), the City Council took no reportable action on this item.

ADJOURNMENT
There being no further business, Mayor Schreder declared the meeting adjourned at the hour of 6:01 p.m.

APPROVED:
_______________________________
Kristen Schreder, Mayor
ATTEST:
_______________________________
Pamela Mize, City Clerk
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Attachment: Unofficial Minutes - January 18, 2022 - Special Meeting - Closed Session (available online) (4(a)--Approve City Council Minutes)

CITY OF REDDING

REPORT TO THE CITY COUNCIL
Recommendation
Accept City of Redding Accounts Payable Register No. 14; and Payroll Register No. 15.

Fiscal Impact
There is no fiscal impact to accepting the registers.

Alternative Action
The City Council could choose to not accept the registers and provide direction to staff.

Background/Analysis
Attached are the Accounts Payable and Payroll Registers as follows:

Accounts Payable:
(1) Register Number 14 for the period January 15, 2022 – January 31, 2022, in the amount of $11,573,388.18.

Payroll:
(1) Register Number 15 for the period January 9, 2022 – January 22, 2022, in the amount of $3,669,711.42.

Council Priority/City Manager Goals
• This agenda item is a routine operational item.

Attachments
Accounts Payable Register No. 14 and Payroll Register No. 15 (available online) MEETING DATE: February 15, 2022
ITEM NO. 4(b)
FROM:
***APPROVED BY***
[email protected] [email protected]
SUBJECT: 4(b)--City of Redding Accounts Payable and Payroll Registers.

Allyn Feci Clark, Director of
Finance/City Treasurer
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Attachment: Accounts Payable Register No. 14 and Payroll Register No. 15 (available online) (4(b)--Accounts Payable and Payroll Registers) Packet Pg. 31
Attachment: Accounts Payable Register No. 14 and Payroll Register No. 15 (available online) (4(b)--Accounts Payable and Payroll Registers) Packet Pg. 32
Attachment: Accounts Payable Register No. 14 and Payroll Register No. 15 (available online) (4(b)--Accounts Payable and Payroll Registers) Packet Pg. 33
Attachment: Accounts Payable Register No. 14 and Payroll Register No. 15 (available online) (4(b)--Accounts Payable and Payroll Registers) Packet Pg. 34
Attachment: Accounts Payable Register No. 14 and Payroll Register No. 15 (available online) (4(b)--Accounts Payable and Payroll Registers) Packet Pg. 35
Attachment: Accounts Payable Register No. 14 and Payroll Register No. 15 (available online) (4(b)--Accounts Payable and Payroll Registers) Packet Pg. 36
Attachment: Accounts Payable Register No. 14 and Payroll Register No. 15 (available online) (4(b)--Accounts Payable and Payroll Registers) Packet Pg. 37
Attachment: Accounts Payable Register No. 14 and Payroll Register No. 15 (available online) (4(b)--Accounts Payable and Payroll Registers) Packet Pg. 38
Attachment: Accounts Payable Register No. 14 and Payroll Register No. 15 (available online) (4(b)--Accounts Payable and Payroll Registers) Packet Pg. 39
Attachment: Accounts Payable Register No. 14 and Payroll Register No. 15 (available online) (4(b)--Accounts Payable and Payroll Registers) Packet Pg. 40
Attachment: Accounts Payable Register No. 14 and Payroll Register No. 15 (available online) (4(b)--Accounts Payable and Payroll Registers) Packet Pg. 41
Attachment: Accounts Payable Register No. 14 and Payroll Register No. 15 (available online) (4(b)--Accounts Payable and Payroll Registers) Packet Pg. 42
Attachment: Accounts Payable Register No. 14 and Payroll Register No. 15 (available online) (4(b)--Accounts Payable and Payroll Registers) Packet Pg. 43
Attachment: Accounts Payable Register No. 14 and Payroll Register No. 15 (available online) (4(b)--Accounts Payable and Payroll Registers) Packet Pg. 44
Attachment: Accounts Payable Register No. 14 and Payroll Register No. 15 (available online) (4(b)--Accounts Payable and Payroll Registers) Packet Pg. 45
Attachment: Accounts Payable Register No. 14 and Payroll Register No. 15 (available online) (4(b)--Accounts Payable and Payroll Registers) Packet Pg. 46
Attachment: Accounts Payable Register No. 14 and Payroll Register No. 15 (available online) (4(b)--Accounts Payable and Payroll Registers) Packet Pg. 47
Attachment: Accounts Payable Register No. 14 and Payroll Register No. 15 (available online) (4(b)--Accounts Payable and Payroll Registers) Packet Pg. 48
Attachment: Accounts Payable Register No. 14 and Payroll Register No. 15 (available online) (4(b)--Accounts Payable and Payroll Registers) Packet Pg. 49
Attachment: Accounts Payable Register No. 14 and Payroll Register No. 15 (available online) (4(b)--Accounts Payable and Payroll Registers) Packet Pg. 50
Attachment: Accounts Payable Register No. 14 and Payroll Register No. 15 (available online) (4(b)--Accounts Payable and Payroll Registers) Packet Pg. 51
Attachment: Accounts Payable Register No. 14 and Payroll Register No. 15 (available online) (4(b)--Accounts Payable and Payroll Registers) Packet Pg. 52
Attachment: Accounts Payable Register No. 14 and Payroll Register No. 15 (available online) (4(b)--Accounts Payable and Payroll Registers) Packet Pg. 53
Attachment: Accounts Payable Register No. 14 and Payroll Register No. 15 (available online) (4(b)--Accounts Payable and Payroll Registers) Packet Pg. 54
Attachment: Accounts Payable Register No. 14 and Payroll Register No. 15 (available online) (4(b)--Accounts Payable and Payroll Registers)

CITY OF REDDING

REPORT TO THE CITY COUNCIL
Recommendation
Accept the Proof of Cash reconciliation and ACR133 report for the month of December 2021.

Fiscal Impact
There is no fiscal impact to accepting the report.

Alternative Action
The City Council could choose to not accept the Proof of Cash reconciliation and ACR133 report and provide alternate direction to staff.

Background/Analysis
The City Council has requested a monthly report on pooled cash. The ACR133 report summarizes, by fund, the month-to-date pooled cash balances and transactions. The Proof of Cash reconciles the ACR133 report to the Treasurer’s monthly report.

Council Priority/City Manager Goals
• This is a routine operational item.

Attachments
ACR133, Current Cash Balance
Proof of Cash
MEETING DATE: February 15, 2022
ITEM NO. 4(d)
FROM:
***APPROVED BY***
[email protected] [email protected]
SUBJECT: 4(d)--ACR133 Report and Cash Reconciliation for the Month of December 2021.

Allyn Feci Clark, Director of
Finance/City Treasurer
Packet Pg. 55
ACR133 CITY OF REDDING KINGSSYS 10:12:53 1/07/2022
GENERAL ACCOUNTING DATED 1/07/2022
CURRENT CASH BALANCE - CITY COUNCIL REPORT PAGE 1

ENDINGBALANCE
12/31/2021
111 GENERAL FUND 9,249,749.16120 ASSET SEIZURE FUND 51,186.54121 ENT ANDERSON GROUNDWATER 177,346.42-122 PARKING FUND 723,136.45123 GENERAL SPECIAL REVENUE 202,550.97124 IPSS SPECIAL REVENUE 1,709,237.48125 ROLLING STOCK REPLACEMNT 10,841,398.54126 SPECL GAS TAX ST IMPROVE 6,846,052.98127 LOCAL TRANSPORTATION 4,520,019.95128 DEVELOPMENT FUND 3,544,405.86129 LIBRARY 84,224.56130 BRANCH LIBRARIES 42,075.88134 MUNICIPAL AIRPORT FUND 2,084,573.28-140 TOURISM/CONVENTION FUND 203,268.16-142 ELECTRIC UTILITY FUND 75,017,897.81143 WATER UTILITY FUND 55,247,581.69145 WASTEWATER UTILITY FUND 43,071,286.84147 STORM DRAIN UTILITY FUND 5,065,206.39148 WEST CENTRAL LANDFILL 12,158,061.99149 SOLID WASTE COLLECTION 13,564,227.79150 MEDIA, COMMS & PR 59,130.34151 INFORMATION TECHNOLOGY 1,831,549.95153 FLEET MAINTENANCE 48,642.61154 BUILDING MAINT & CONSTR 1,031,260.66158 RECORDS MANAGEMENT 112,921.38160 EMPLOYER SERVICES 208,821.30162 RMU ADMINISTRATION 1,416,584.73165 GEOGRAPHIC INFO SERVICES 573,551.67166 COMMUNICATIONS 313,178.95168 REPROGRAPHICS 128,563.32169 VOLUNTEER SERVICES 17,656.84171 SPECIAL DEPOSITS FUND 19,175,868.03172 RISK MANAGEMENT 9,307,811.70173 EMPLOYEE BENEFITS P/R 155,158.71174 EMPLOYEE BENEFIT GRP INS 502,639.64175 GASB 45 TRUST FUND 39,125.87178 CAPITAL PROJECTS FUND 1,219,315.71191 CD BLOCK GRANT FUND 1,645,837.11193 HOUSING AUTHORITY 82,108.45-194 REDDING REDEVELOPMENT 73,803.61200 REDDING AREA BUS AUTHOR. 101,787.83-230 LOW/MOD INC HOUS ASSET 842,609.78300 SPECIAL ASSESSMENT DIST. 309,005.05400 LANDSCAPE DISTRICTS 10,990.67- FINAL TOTAL 278,291,263.03
ACR133 10:12:53 1/07/2022
Packet Pg. 56
Attachment: ACR133, Current Cash Balance (4(d)--ACR133 Report and Cash Reconciliation - December Sheet "D" December 2021

CITY OF REDDING

PROOF OF CASH
RECONCILIATION BETWEEN TREASURER'S REPORT AND ACR 133
As of December 2021
ACR133 TREASURER
END OF MONTH BALANCE 278,291,263.03 277,959,009.34
LESS OUTSIDE MANAGED FUNDS (320.06)
ACR133 Report
CASH ACCOUNTS NOT ON ACR133
LIBRARY MERCHANT DEPOSIT 100.00

BAD CHECKS -
PAYROLL TIMING DIFFERENCE 3,806.19
BANK CHARGES (77,473.06)

WIRE TRANSFER TIMING DIFFERENCE
OTHER ADJUSTMENTS (937,455.97)
BANK DR/CR (678,649.09)
TOTALS 277,280,140.19 277,280,140.19
Packet Pg. 57
Attachment: Proof of Cash (4(d)--ACR133 Report and Cash Reconciliation - December 2021)

CITY OF REDDING

REPORT TO THE CITY COUNCIL
Recommendation
Accept report and make a determination by a four-fifths (4/5ths) affirmative vote that conditions of local emergency continue to exist within the City of Redding, under Public Contract Code section 22050(c)(1) related to the Coronavirus (COVID-19).

Fiscal Impact
There is no fiscal impact related to this action.

Alternative Action
The City Council could choose to not confirm that conditions of local emergency continue to exist. Under Public Contract Code section 22050(c)(1) the local emergency can only be terminated by a vote of four-fifths of the City Council. To that end, the City Council’s prior determination of a local emergency will remain unless an affirmative vote of the City Council is made to terminate the local emergency.

Background/Analysis
Coronavirus disease (COVID-19) is a wide spread global virus. The first case of COVID-19 in the United States was reported on January 21, 2020. As the number of cases continues to grow rapidly across the country, Federal and State response to the virus has been evolving. The City Council approved a Declaration of a Local Emergency on March 17, 2020, which allows the City of Redding (City) to be better prepared to respond in any manner necessary should the virus continue to spread. The declaration allows the swift purchase of needed goods and services, the ability to respond to any public works needs, and provides for potential receipt of emergency aid from state, and possibly federal, authorities. On March 17, 2020, there was one confirmed case of Coronavirus in Shasta County.

MEETING DATE: February 15, 2022
ITEM NO. 4.1(a)
FROM:
***APPROVED BY***
[email protected]
[email protected]
SUBJECT: 4.1(a)--Confirmation of Continued Local Emergency.

Barry Tippin, City
Manager/Development
Services Director
Packet Pg. 58
Report to Redding City Council February 3, 2022
Re: 4.1(a)--Confirmation of Continued Local Emergency Page 2 On March 19, 2020, the California State Public Health Officer and California State Governor Gavin Newsom issued a public health order for Californians to stay at home as a means to limit the spread of the virus statewide. In response, the City closed City Hall to the general public on March 20, 2020, and re-opened on August 31, 2020. Due to a surge in positive cases, it was necessary, once again, to close City Hall to the general public effective October 12, 2020. City facilities remained closed until March 1, 2021, when positive cases declined in Shasta County and the county moved back to the “red” tier.

As COVID-19 case rates continued to decline state-wide, Governor Newsom, on June 11, 2021, rescinded Executive Order N-33-20 (Stay-at-Home Order). As of this writing, City Hall is fully open to the general public and also continues to offer on-line and telephone services for those preferring not to conduct business face-to-face. As of December 15, 2021, the State of California is once again requiring the wearing face coverings in indoor spaces including City Hall and other City facilities. City management continues to monitor COVID-19 safety protocols issued by the California Public Health Officer and California Division of Occupational Safety and Health (CalOSHA) for updates and newly required safety measures.

Pursuant to Government Code section 3630(c) and Public Contract Code 20168 and 22050 (c)(1), the City Council must review the need for continuing the local emergency every regularly scheduled meeting of the City Council until the City Council terminates the local emergency. No public work which would otherwise be subject to competitive bidding has been accomplished to date. The City Manager, and other staff as deemed necessary, may provide an oral report to the City Council which will detail what has been learned to date about the impacts of Coronavirus in our community and what may be necessary to mitigate conditions which pose a threat to public health, safety, and welfare.

Council Priority/City Manager Goals
• Public Safety – “Work to improve all aspects of public safety to help people feel secure and safe where they live, work, and play in the City of Redding.” • Communication and Transparency – “Improve the quality of communication with the public and City employees to enhance knowledge and increase transparency to improve public trust.”
Packet Pg. 59

CITY OF REDDING

REPORT TO THE CITY COUNCIL
Recommendation
Adopt Resolution ratifying approval of the following actions:
(1) Submission of grant application to the California Department of Forestry and Fire Protection Fire Prevention grant program;
(2) Certifying the City of Redding meets grant requirements; and (3) Authorizing the City Manager, or designee, to execute and submit documents, and conduct negotiations related to the grant program, in the total amount of $520,000, which must be expended by March 15, 2026, for the City of Redding Community Fire Risk Reduction Program project.

Fiscal Impact
If the grant application is successful, the City of Redding (City) could receive California Department of Forestry and Fire Protection (CALFIRE) Fire Prevention (FP) Grant Program funding in the amount of $520,000 with no matching funds required.

Alternative Action
The City Council could decline to ratify the grant application and direct City staff to withdraw the application. The City would not receive funding from the CALFIRE FP Grant Program and would miss the opportunity to receive additional funding for its fire prevention efforts.

Background/Analysis
CALFIRE FP Grants provide funding for fire prevention projects and activities in and near fire threatened communities. The grant’s focus is on increasing the protection of people, structures, and communities. The total funding available for Fiscal Year 2021-22 is up to $120 million while there is no maximum amount for individual awards. Fire prevention projects undertaken with this funding must be completed by March 15, 2026. The City has applied for this funding program in the past, however that application was not successful.

MEETING DATE: February 15, 2022
ITEM NO. 4.1(c)
FROM:
***APPROVED BY***
[email protected]
[email protected]
SUBJECT: 4.1(c)--Ratification of Grant Application Submitted to California Department of Forestry and Fire Protection for the Fire Prevention Grant Program Barry Tippin, City
Manager/Development
Services Director
Packet Pg. 60
Report to Redding City Council February 9, 2022
Re: 4.1(c)--Ratification of Grant Application Page 2
The City is seeking $520,000 from CALFIRE with no required local match to provide wildfire prevention planning and wildfire prevention education for the community. The Community Fire Risk Reduction Program is a comprehensive approach to engage the community in collaborative long-term wildfire risk reduction and associated greenhouse gas emission avoidance.

Specifically, the City intends to develop a Community Wildfire Protection Plan – a collaboration between local and state agencies to identify and prioritize fuel treatments to reduce hazardous fuel areas and recommend measures to reduce ignitability of structures; hold two community hazardous fuel reduction events; and fund a limited-term Fire Prevention Specialist position to conduct wildfire prevention outreach and education, through March 2026. The Fire Prevention Specialist position requested in this grant is in addition to other Redding Fire Department requests for a Fire Prevention Specialist position – the grant-funded Fire Prevention Specialist would be a limited-term position based on the availability of grant funding.

Council Priority/City Manager Goals
• Public Safety – “Work to improve all aspects of public safety to help people feel secure and safe where they live, work, and play in the City of Redding.” • Budget and Financial Management – “Achieve balanced and stable 10-year Financial Plans for all funds.”
• 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
Resolution
Packet Pg. 61
RESOLUTION NO. 2022-_____

A RESOLUTION OF THE CITY COUNCIL OF THE CITY OF REDDING

RATIFYING A GRANT APPLICATION SUBMITTED TO THE CALIFORNIA

DEPARTMENT OF FORESTRY AND FIRE PROTECTION FIRE

PREVENTION GRANT PROGRAM
WHEREAS, the Governor of the State of California in cooperation with the California State Legislature has enacted State of California Climate Investment, which provides funds to the State of California and its political subdivisions for fire prevention programs; and WHEREAS, the State Department of Forestry and Fire Protection (CAL FIRE) has been delegated the responsibility for the administration of the program within the State, setting up necessary procedures governing application by local agencies, non-profit organizations, and others under the program; and WHEREAS, the applicant will enter into an agreement with the State of California to carry out the City of Redding Community Fire Risk Reduction Program project; NOW, THEREFORE, the City Council RESOLVES that:

1. Approved the filing of an application for the “California Climate Investment Fire Prevention Grant Program;” and

2. Certifies that said applicant has or will have sufficient funds to operate and maintain the project; and

3. Certifies that funds under the jurisdiction of the City of Redding are available to begin the project; and

4. Certifies that said applicant will expend grant funds prior to March 15, 2026; and

5. Appoints the City Manager or a designee, to conduct all negotiations, execute and submit all documents including, but not limited to applications, agreements, amendments, payment requests and so on, which may be necessary for the completion of the aforementioned project.

I HEREBY CERTIFY that the foregoing resolution was introduced at a regular meeting of the City Council of the City of Redding on the 15th day of February, 2022, and was duly adopted at said meeting by the following vote:

AYES: COUNCIL MEMBERS:

NOES: COUNCIL MEMBERS:

ABSENT: COUNCIL MEMBERS:

ABSTAIN: COUNCIL MEMBERS:
_______________________________
KRISTEN SCHREDER, Mayor
ATTEST: APPROVED AS TO FORM:
____________________________ ________________________________ PAMELA MIZE, City Clerk BARRY E. DeWALT, City Attorney
Packet Pg. 62
Attachment: Resolution (4.1(c)--Ratification of Grant Application)

CITY OF REDDING

REPORT TO THE CITY COUNCIL
Recommendation
Authorize the following actions regarding the Regional Early Action Planning grant agreement with the County of Shasta and the City of Shasta Lake to assist with the City of Redding’s General Plan Update:
(1) Approve and authorize the Mayor to execute the Memorandum of Understanding between County of Shasta and City of Shasta Lake for administration of the grant funds awarded by California Department of Housing and Community Development through the Regional Early Action Planning Grants Program; and
(2) Authorize the Mayor, or designee, to execute all documents necessary to accept the grant as awarded.

Fiscal Impact
If the grant is awarded, there will be a positive impact of $398,245.80 to the Development Services Department budget to assist with the General Plan Update.

Alternative Action
The City Council may decline to submit the Regional Early Action Planning (REAP) Grant.

Background/Analysis
This item is being presented again to the City Council due to a clerical error with the agenda at the January 24, 2022, meeting. The California 2019-20 Budget Act allocated $250 million in funding for all regions, cities, and counties to prioritize planning activities that accelerate housing production to meet identified needs of each community. With this funding, the California Department of Housing and Community Development (HCD) established the REAP Grant Program with $125 million to regions. REAP provides one-time grant funding to regional governments and regional entities for planning activities that will accelerate housing production MEETING DATE: February 15, 2022
ITEM NO. 4.4(a)
FROM:
***APPROVED BY***
[email protected]
[email protected]
SUBJECT: 4.4(a)--Approve the Regional Early Action Planning (REAP) Grant Agreement Barry Tippin, City
Manager/Development
Services Director
Packet Pg. 63
Report to Redding City Council February 7, 2022
Re: 4.4(a)--Approve REAP Grant Agreement - County of Shasta & City of Shasta Lake Page 2 and facilitate compliance in implementing the sixth cycle of the Regional Housing Needs Allocation. The program offers funding to councils of governments (COGs), other regional entities, and certain counties to be utilized for regional efforts or to be equitably sub-allocated.

The REAP Grant Program allocates a total of $682,364 to the County of Shasta as the applicant for the region. The County’s application proposes to sub-allocate the full amount available to the region to the incorporated cities for the following activities:
• City of Redding
Comprehensive General Plan Update Staffing $398,245.80
• City of Shasta Lake
Wastewater Feasibility Study $260,000
• County of Shasta
Administrative Cost $24,118.20
Each city has identified eligible key planning activities which would greatly benefit housing production. To ensure that each agency’s needs are met, the City of Redding, the City of Anderson, and the County of Shasta were consulted throughout the process of formulating the REAP Grant Program application and sub-allocation amounts.

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.”
• Economic Development – “Facilitate and become a catalyst for economic development in Redding to create jobs, retain current businesses and attract new ones, and encourage investment in the community.”
Attachments
REAP Contract City of Redding and County of Shasta (available online) Packet Pg. 64

Page 1 of 11 ends

MEMORUNDUM OF UNDERSTANDING (Agreement)

BETWEEN COUNTY OF SHASTA AND CITY OF SHASTA LAKE

FOR ADMINISTRATION OF SUB-RECIPIENT GRANT FUNDS AWARDED BY THE

CALIFORNIA DEPARTMENT OF HOUSING AND COMMUNITY DEVELOPMENT

THROUGH THE REGIONAL EARLY ACTION PLANNING (REAP) GRANTS PROGRAM STANDARD AGREEMENT NO. 21-REAP-16782
This Agreement is entered into between City of Redding (“City” of “Sub-recipient), a municipal corporation, and County of Shasta, through its Department of Resource Management, a political subdivision of the State of California (“County”), (individually a “Party” or collectively as “Parties").

RECITALS
WHEREAS, County and the State of California have entered into Standard Agreement No. 21-REAP-16782 referred to as the "Standard Agreement'' and attached as Exhibit A, for the County to receive and suballocate funds to City from the Local Government Planning Support Grants Program (LGPSGP) (referred to herein as the Regional Early Action Planning Grant Program, or “REAP”) from the State of California, Department of Housing and Community Development, referred to as "HCD." Funds through REAP were authorized, in part, to finance the City of Redding’s Comprehensive General Plan Update – an approved, eligibility activity under the REAP program; and
WHEREAS, County meets the requirements as outlined by the REAP Program and executed Standard Agreement No. 21-REAP-16782 with HCD and City’s procurement requirements and is authorized through the REAP program, pursuant to Health and Safety Code Sections 50515.02, to implement and administer funding for activities which increase housing planning and accelerate housing production within the region; WHEREAS, County and the Sub-recipient intend to coordinate submittal of reimbursement requests, including invoices and reporting documents in a manner consistent with REAP program requirements, with final submission of the requests to be made by County; and
WHEREAS, County and the Sub-recipient intend to cooperate to ensure continual satisfactory compliance with applicable Federal and State laws and requirements of the Standard Agreement County has entered into with HCD; and WHEREAS, County and the Sub-recipient intend to ensure their respective cost accounting systems meet Federal and State regional planning fund requirements; and WHEREAS, County and Sub-recipient intend to ensure mutual accountability of parties carrying out the duties prescribed in this AGREEMENT, and reduce delays associated with the billing process; and
WHEREAS, the Parties desire to enter into this Agreement; ACCORDINGLY, THE PARTIES AGREE AS FOLLOWS:

Packet Pg. 65
Attachment: REAP Contract City of Redding and County of Shasta (available online) (4.4(a)--Approve REAP Grant Agreement - County of

Page 2 of 11 ends

1. Agreement with the Sub-Recipient and Amendments
A. This Agreement consistutes an arrangement between the Sub-recipient and County, and may be amended by mutual written agreement ans is subject to periodical review.

B. This Agreement includes appendices, “HCD Standard Agreement” (Appendix A), “Approved REAP Grant Application” (Appendix B), “Sample Sub-Recipient Invoice” (Appendix C) hereinafter referred to as Appendices A, B, and C, respectively, attached hereto and incoporated herein by this reference.

C. County’s maximum payment obligation to the Sub-recipient is limited to those funds identified in Appendix B.

D. Billable work may be performed prior to this fully signed Agreement and corresponding notice to proceed so long as the reimbursement requirements of the REAP grant program, as approved by HCD, are met.

2. Scope of Sub-Recipient Responsibilities
A. County shall engage the Sub-recipient and the Sub-recipient shall be responsible for the complete performance of the work associated with the Comprehensive General Plan Update as described in Appendix B.

B. Sub-recipient shall assist County in preparing invoices, supporting documentation and reports for quarterly reimbursement requests or requests based on completion of a deliverable.

C. Sub-recipient shall assist County in maintaining books, records, documents and other evidence that demonstrates the funding is used for the appropriate purpose and provide a separate ledger and/or receipts and expenditure details in accordance with the budget timeline. The books, records, documents or other evidence that would be kept as accounting records shall be subject to audit and inspection at any point during the term of the agreement the County has with HCD and for a minimum of three (3) years after final payment, unless a longer period of records retention is stipulated and subject to any amendments.

D. Sub-recipient and any subcontractors employed and paid with moneys under the terms of this Standard Agreement shall be responsible for maintaining accounting records as specified above.

E. Sub-recipient shall ensure that project documents related to the execution of funds from this Agreement can be made available for review by HCD over the life of the project.

F. Sub-recipient shall assist in any performance report required by HCD at any time during the Standard Agreement between County and HCD. The performance report would be required to demonstrate satisfaction of all Packet Pg. 66
Attachment: REAP Contract City of Redding and County of Shasta (available online) (4.4(a)--Approve REAP Grant Agreement - County of

Page 3 of 11 ends

requirements identified in the Standard Agreement with emphasis on eligible activities, eligible uses, ineligible uses and expenditures according to timelines and budgets referenced in the Standard Agreement.

G. Sub-recipient, by assisting County in providing a performance report, shall do so in the form and manner prescribed by HCD, and shall make the report publicly available on its internet website, by April 1 of the year following the receipt of those funds, and annually thereafter until those funds are expended.

It must contains the following information:
• The status of the proposed uses listed in the entity’s application for funding and the corresponding impact on housing within the region or jurisdiction categorized by eligible uses specified in the application; and • A summary of building permits, certificates of occupancy, or other completed entitlements issued by entities within the region or by the jurisdiction, as applicable.

H. Upon completion of all deliverables, the Sub-recipient shall assist the County in preparing a close out report in accordance with HCD’s REAP grant program requirements.

I. Sub-recipient shall identify a staff person to serve as the primary contact and provide prompt assistance with the responsibilities listed above.

J. Sub-recipient shall be obligated to any other responsibility outlined elsewhere in this Agreement.

3. Scope of County Responsibilities
A. County shall make available to the City $398,245.80 in funds for the approved activity in the REAP application as pass-through funds upon approval of reimbursement requests and release of funds by HCD .

B. With assistance from the Sub-recipient, County shall submit invoices, supporting documentation and reports for quarterly reimbursement requests or requests based on completion of a deliverable.

C. County shall keep a separate ledger and provide receipts and expenditure details in accordance with the budget timeline that would be kept as accounting records subject to audit for a minimum of three (3) years after final payment, unless a longer period of records retention is stipulated.

D. With assistance from Sub-recipient, County shall prepare performance reports as required by HCD pursuant to the Standard Agreement between County and HCD.

E. County shall prepare a close out report in accordance with HCD’s REAP grant program requirements.

Packet Pg. 67
Attachment: REAP Contract City of Redding and County of Shasta (available online) (4.4(a)--Approve REAP Grant Agreement - County of

Page 4 of 11 ends

F. County shall identify a staff person to serve as the County’s primary contact and provide prompt direction to City regarding status, procedures and other matters related to the REAP program grant funds disbursement and reporting process.

G. County shall complete and file all required reports, including but not limited to any reports or other filings required by the Standard Agreement.

F. County shall pay to the City funds available under this Agreement based upon information submitted by the City and consistent with any approved budget and Section 4 Billing and Payment of this Agreement. Payments will be made as immediate pass-through funds once released to County by HCD.

H. County, and if necessary, HCD, must approve budget changes in writing prior to any budget adjustment or amendment.

I. County shall be obligated to any other responsibility outlined elsewhere in this Agreement.

4. Billing and Payment
A. City shall submit to County a detailed, itemized, and documented request for payment as necessary.

B. Invoices shall be in the form and contain the information requested by County and shall be subject to approval by County, which approval shall not be unreasonably withheld. County will make payments within thirty (30) days of receipt of approved invoice(s). County will notify City of any objections, questions, or complaints regarding any particular invoice within fifteen (15) days of receipt of such invoice. If County determines that amounts were improperly billed and/or paid to City, or City was improperly underpaid, adjustments by such amounts may be made in the payment on the current or a later invoice with explanation provided. No interest or penalties shall accrue for late payments.

5. Term of Agreement
This Agreement shall commence January __, 2022 and shall expire on December 31, 2023, unless otherwise terminated as provided in this Agreement. Notwithstanding the foregoing, any term of this Agreement which by its nature extends beyond the end or termination of this Agreement remains in effect until fulfilled, including the grant closing requirements.

A. County’s maximum payment obligation is the amount identified in the HCD Approved REAP Grant Application for the City of Redding sub-allocation:
$398,245.80
Packet Pg. 68
Attachment: REAP Contract City of Redding and County of Shasta (available online) (4.4(a)--Approve REAP Grant Agreement - County of

Page 5 of 11 ends

6. Termination of Agreement
A. City may terminate this Agreement on 30 days' written notice for any reason.

County shall provide funds to City for all work satisfactorily completed and demonstrated as of the date of termination which has been shown to meet REAP Program deliverables as approved by HCD. County is not obligated to facilitate any grant funds for work that is completed after the termination date.

B. City may terminate this Agreement immediately upon oral notice should funding cease or be materially decreased.

C. County may terminate this Agreement on 30 days’ written notice if the program is ceased or if City is in breach of this agreement.

D. City’s right to terminate this Agreement may be exercised by its City Manager.

County’s right to terminate this Agreement may be exercised by County’s Board of Supervisors, County’s Executive Officer or his/her designee.

Section 7. Entire Agreement/Modification
This Agreement constitutes the entire understanding of the Parties hereto. City shall be entitled to no other benefits other than those specified herein. No changes, amendments or alterations shall be effective unless in writing and signed by both Parties. Both parties specifically acknowledges that in entering into and executing this Agreement, each party relies solely upon the provisions contained in this Agreement and no others.

If any ambiguity, inconsistency, or conflict exists or arises between the provisions of this Agreement and the provisions of any of this Agreement's exhibits or appendices, the provisions of this agreement shall govern.

Section 8. Financial Management
A. Accounting Standards
1) The City and County, their staff, contractors and subcontractors shall establish and maintain an accounting system and reports that properly accumulate incurred project costs by line. The accounting system shall conform to Generally Accepted Accounting Principles (GAAP), enable the determination of incurred costs at interim points of completion, and provide support for reimbursement payment vouchers or invoices. 2) The County and City shall each establish a separate ledger account for receipts and expenditures of grant funds and maintain expenditure details in accordance with the scope of work, project timeline and budget. Separate bank accounts are not required for expenditures or ledgers.
3) The County and City shall each maintain documentation of its normal procurement policy and competitive bid process (including the use of Packet Pg. 69
Attachment: REAP Contract City of Redding and County of Shasta (available online) (4.4(a)--Approve REAP Grant Agreement - County of

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sole source purchasing), and financial records of expenditures incurred during the course of the project in accordance with GAAP. 4) The County agree that the State or designated representative shall have the right to review and to copy any records and supporting documentation pertaining to the performance of the Standard Agreement.
5) Subcontractors employed by the County or City and paid with moneys under the terms of the HCD Standard Agreement (Appendix A) shall be responsible for maintaining accounting records as specified above.

Section 9. Documentation and Record Keeping
A. Reporting
1) During the term of the Agreement the County shall submit, upon request of HCD, a performance report that demonstrates satisfaction of all requirements identified in the HCD Standard Agreement (Appendix A). 2) The County, and by extension, the City, will be subject to amendments to this section as a result of subsequent applications and awards. 3) The City shall assist the County in any performance report requested by HCD referenced in Section 9 subsection A of this agreement.

B. Records to be Maintained
The City and County shall maintain all records required by State and Federal regulations that are pertinent to the activities to be funded under this Agreement. Such records shall include but not be limited to:
1) Records providing a full description of each activity undertaken; 2) Records demonstrating that each activity undertaken meets one of the requirements of the REAP Program;
3) Records required to determine the eligibility of activities; and 4) Financial and other records as required and necessary to document compliance by Federal and State Code of Regulations.

C. Closeouts
The County’s obligation to facilitate pass-through funds to the City shall not end until all closeout requirements are completed. Activities during this closeout period shall include, but are not limited to: making final payments, and determining the custodianship of records. Notwithstanding the foregoing, the terms of this Agreement shall remain in effect during any period that the County has engaged in any activities making use of funds.

D. Access to Records
The County and City shall furnish and cause each of its own representatives or subcontractors to furnish all information and reports required hereunder and Packet Pg. 70
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will permit access to its books, records and accounts by HCD, or its agent, or any other authorized State/Federal officials for purposes of investigation to ascertain compliance with the rules, regulations and provisions stated herein.

Section 10. Audits
A. At any time during the term of the Agreement, HCD may perform or cause to be performed a financial audit of any and all phases of the award. At HCD’s request, the County and City shall provide, at their own expense, a financial audit prepared by a certified public accountant. The State of California has the right to review project documents and conduct audits during and over the project life.
1) The County and the City agree that HCD or HCD’s designee shall have the right to review, obtain, and copy all records and supporting documentation pertaining to performance of this Agreement. 2) The County and City agree to provide HCD or HCD’s designee, with any relevant information requested.
3) The County and City agree to permit HCD or HCD’s designee access to its premises, upon reasonable notice, during normal business hours for the purpose of interviewing employees who might reasonably have information related to such records and inspecting and copying such books, records, accounts, and other material that may be relevant to a matter under investigation for the purpose of determining compliance with statutes, Program guidelines, and this Agreement.

B. If a financial audit is required by HCD, the audit shall be performed by an independent certified public accountant. Selection of an independent audit firm shall be consistent with procurement standards contained in Exhibit D, Section 8 subsection A. of the Standard Agreement (attached as Appendix A). 1) The County shall notify HCD of the auditor's name and address immediately after the selection has been made. The contract for the audit shall allow access by HCD to the independent auditor's working papers. 2) The County and City is responsible for the completion of audits and all costs of preparing audits.
3) If there are audit findings, the County, with assistance form the City, shall submit a detailed response acceptable to HCD for each audit finding within 90 days from the date of the audit finding report.

C. The County agrees to maintain such records for possible audit after final payment pursuant to Exhibit D, Section 3, subsection E. of Appendix A, unless a longer period of records retention is stipulated.

11. Release of Funds Upon Expiration, Cancellation or Termination Packet Pg. 71
Attachment: REAP Contract City of Redding and County of Shasta (available online) (4.4(a)--Approve REAP Grant Agreement - County of

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The County shall transfer to the City any REAP funds on hand and any accounts receivable attributable to the use of funds under this Agreement at the time of expiration, cancellation, or termination of the program.

12. Non-Assignment of Agreement
Inasmuch as this Agreement is intended to secure the specialized service of County, County may not assign, transfer, delegate or sublet any interest herein without the prior written consent of City.

13. Independent Contractor
The Sub-recipient and its officers, employees, and agents shall be independent contractors in the performance of this Agreement. City shall, during the entire term of this Agreement, be construed to be an independent contractor and nothing in this Agreement is intended nor shall be construed to create an employer-employee relationship, a joint venture relationship, or to allow County to exercise discretion or control over the professional manner in which City performs the services which are funded through sub-allocation outlined in this Agreement; provided always, however, that the services to be provided by City shall be provided in a manner consistent with the professional standards applicable to such services and consistent with the requirements of REAP program and Standard Agreement No. 21-REAP-16782. City shall be fully responsible for payment of all taxes due to the State of California or the Federal government which would be withheld from compensation if City were a County employee. County shall not be liable for deductions for any amount for any purpose from City's compensation or reimbursement. City shall not be eligible for coverage under County's workers compensation insurance plan nor shall City be eligible for any other County benefit.

14. Indemnification
To the fullest extent permitted by law, City shall indemnify and hold harmless County, its elected officials, officers, employees, agents, and volunteers against all claims, suits, actions, costs, expenses (including, but not limited to, reasonable attorney's fees of County Counsel and counsel retained by County, expert fees, litigation costs, and investigation costs), damages, judgments, or decrees arising from the work or the provision of services undertaken pursuant to this agreement by City, or by any of City’s subcontractors, any person employed under City, or under any subcontractor, or in any capacity, except when the injury or loss is caused by the sole negligence or intentional wrongdoing of County. City shall also, at City’s own expense, defend the County, its elected officials, officers, employees, agents, and volunteers, against any claim, suit, action, or proceeding brought against County, its elected officials, officers, employees, agents, and volunteers, arising from the work or the provision of services undertaken pursuant to this agreement by City, or any of City’s subcontractors, any person employed under City, or under any Subcontractor, or in any capacity. City shall also defend and indemnify County for any adverse determination made by the Internal Revenue Service or the State Franchise Tax Board and/or any other taxing or regulatory agency and shall defend, indemnify, and hold harmless County with respect to City’s “independent contractor” status that would establish a liability on Packet Pg. 72
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County for failure to make social security deductions or contributions or income tax withholding payments, or any other legally mandated payment. The provisions of this paragraph are intended to be interpreted as broadly as permitted by applicable law. This provision shall survive the termination, expiration, or cancellation of this agreement.

18. Governing Law
This Agreement is governed by and shall be interpreted in accordance with the laws of the State of California.

19. Timeliness
Time is of the essence in this Agreement. Reimbursement requests must be submitted to HCD no later than August 31, 2023, (or as otherwise may be extended by HCD).

20. Notices
Any notice required to be given pursuant to the terms and provisions of this Agreement shall be in writing and shall be sent first-class mail to the following addresses:

If to City: Barry Tippin, City Manager
City of Redding
PO Box 496071
Redding, CA 96049-6071
If to County: Paul A. Hellman, Director
Shasta County Dept. of Resource Management
1855 Placer Street, Suite 103
Redding, CA 96001
Notice shall be deemed to be effective three days after mailing.

21. Appendices
Attachments are a part of this Agreement and are incorporated herein by reference:

Appendix A: HCD Standard Agreement
Exhibit B: Approved REAP Grant Application
Exhibit C: Sample Sub-Recipient Invoice

22. Entire Agreement
This Agreement and its exhibits constitute the entire Agreement between the City and the County for the use of funds received under this Agreement and it supersedes all prior or contemporaneous communications and proposals, whether electronic, oral, or written between the City and the County with respect to this Agreement.

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The City and County agree to be knowledgeable of and comply with all the requirements contained in the Standard Agreement and all other applicable Federal, State and local laws, regulations, and policies governing the funds provided under this Agreement.

SIGNATURE PAGE FOLLOWS
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IN WITNESS WHEREOF, City and County have executed this Agreement on the day and year set forth below.

CITY OF REDDING COUNTY OF SHASTA
By: ___________________________________________ By: ___________________________________________ Kristen Schreder, Mayor LEONARD MOTY, CHAIR
City of Redding Board of Supervisors
County of Shasta
State of California
Date: _________________________________________ Date: _________________________________________ ATTEST: ATTEST:

Pamela Mize, City Clerk Matthew P. Pontes
City of Redding Clerk of the Board of Supervisors
By: ___________________________________________ ________________________________________ By: Deputy
Date: _________________________________________
APPROVED AS TO FORM:

By: ___________________________________________
Barry E. DeWalt, City Attorney
City of Redding
Date: _________________________________________
RUBIN E. CRUSE, JR
County Counsel
By: _______________________________ Date:

Name: ____________________________ Title: _____________________________

RISK MANAGEMENT APPROVAL
By: ______________________________ Date:

Name: ____________________________ Title: _____________________________ Packet Pg. 75
Attachment: REAP Contract City of Redding and County of Shasta (available online) (4.4(a)--Approve REAP Grant Agreement - County of

CITY OF REDDING

REPORT TO THE CITY COUNCIL
Recommendation
Approve purchase of Digger Derrick-Tracked Backyard truck using Sourcewell contract pricing with Altec Industries, Inc. in the amount of $245,000, including taxes and fees, for the Redding Electric Utility.

Fiscal Impact
The vehicle purchase has been anticipated and adequate funding is available in Redding Electric Utility’s (REU) Rolling Stock fund. The purchase was anticipated to occur in the next fiscal year, but due to the long lead-time, funds need to be encumbered this fiscal year.

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

Background/Analysis
REU has an Altec Industries, Inc. (Altec) Backyard Digger Derrick truck, (E-466), which is utilized for accessing backyard pole lines in difficult to reach areas. The Backyard Digger Derrick truck is used by line crews to dig holes, set power poles, lift transformers, and other linework equipment tasks. The truck is also utilized to raise line crew personnel to an elevated position when working on overhead power lines.

This vehicle meets the replacement guidelines set by the City of Redding Fleet Division, which take into consideration the vehicle’s age, mileage, usage hours, and maintenance costs. The replacement of this truck is a part of REU’s vehicle replacement plan.

MEETING DATE: February 15, 2022
ITEM NO. 4.5(a)
FROM:
***APPROVED BY***
[email protected] [email protected]
SUBJECT: 4.5(a)--Purchase of an Altec Digger Derrick Tracked-Backyard Truck Nick Zettel, Interim Director
of Redding Electric Utility
Packet Pg. 76
Report to Redding City Council February 9, 2022
Re: 4.5(a)--Purchase of an Altec Digger Derrick Truck Page 2 Altec participates in a cooperative agreement with Sourcewell, formerly known as the National Joint Powers Alliance, as the result of a competitive bid process.

Council Priority/City Manager Goals
This agenda item is a routine operational item.

Attachments
Altec Industries, Inc. Quote - Backyard Digger Derrick (available online) Rolling Stock Request - Backyard Digger Derrick Truck (available online) Sourcewell Contract Acceptance and Award (available online) Packet Pg. 77
Quote Number: 971714-3
Opportunity Number: 1650645
Sourcewell Contract #: 012418-ALT
Date: 1/21/2022

REFERENCE ALTEC MODEL
Sourcewell
Price
Commercial
List Price
Discount
%
41' Digger Derrick - Tracked Backyard $197,696 $203,810 3% (A.)
1 DB41-TRLR Trailer for base model $17,820 $18,371 3%
(A1.)
1 DEL-TRLR Delivery other than standard drive away service per mile (delivery on trailer) $8,635 $8,635 0% SOURCEWELL OPTIONS TOTAL: $224,151 $230,816 3%
(B.)
1 OTHER Doc & Admin Fee $125 $125 0%
2 OTHER 7.25% Tax (Note: All appropriate taxes will be added to the final price in accordance with regulations in effect at time of invoicing.) $15,624.91 $16,108.12 3% 3 OTHER Tire Tax, Four Tires and One Spare on the Trailer $8.75 $8.75 0% OPEN MARKET OPTIONS TOTAL: $15,758.66 $16,241.87 3%
SUB-TOTAL FOR UNIT/BODY/CHASSIS: $239,909.66
TOTAL FOR UNIT/BODY/CHASSIS: $239,909.66
(C.)
1 2
3 4
BUILD LOCATION: St. Joeseph, MO
WARRANTY: Standard Altec Warranty for Aerials and Derricks - One (1) year parts warranty One (1) year labor warranty Ninety (90) days warranty for travel charges (Mobile Service) Limited Lifetime Structural Warranty. Chassis to include standard warranty, per the manufacturer.

TRADE-IN: Please ask your Altec Account Manager for more information CHASSIS: Per Altec Commercial Standard
DELIVERY: No later than 395-425 days ARO, Depending on Stock Availability, FOB Customer Location TERMS: Net 30 days
BEST VALUE: Altec boasts the following "Best Value" features: Altec ISO Grip Controls for Extra Protection, Only Lifetime Warranty on Structural Components in Industry, Largest Service Network in Industry (Domestic and Overseas), Altec SENTRY Web/CD Based Training, Dedicated/Direct Gov't Sales Manager, In-Service Training with Every Order.

TO ORDER: To order, please contact the Altec Account Manager listed above. **Pricing valid for 45 days**
NOTES
PAINT COLOR: White to match chassis, unless otherwise specified Quoted by: VICKIE BELL
Altec Account Manager: RHAWNIE KRAAK
Phone: 816-236-1264 / Email: [email protected]
Altec Industries, Inc.

SOURCEWELL OPTIONS ON CONTRACT (Unit)
SOURCEWELL OPTIONS ON CONTRACT (General)
OPEN MARKET ITEMS (Customer Requested)
ADDITIONAL ITEMS (items are not included in total above) DB41
Quoted for: CITY OF REDDING
Customer Contact: BEN GOEHRING
Phone: 530-941-9362 / Email: [email protected]
Sourcewell (formerly NJPA) Quote Template 12-5-2021_CITY OF REDDING DB41B - update 1-21-22 Packet Pg. 78
Attachment: Altec Industries, Inc. Quote - Backyard Digger Derrick (available online) (4.5(a)--Purchase of an Altec Digger Derrick Truck) Packet Pg. 79
Attachment: Rolling Stock Request - Backyard Digger Derrick Truck (available online) (4.5(a)--Purchase of an Altec Digger Derrick Truck) Packet Pg. 80
Attachment: Sourcewell Contract Acceptance and Award (available online) (4.5(a)--Purchase of an Altec Digger Derrick Truck)

CITY OF REDDING

REPORT TO THE CITY COUNCIL
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, to execute the Agreement and any future amendments.

Fiscal Impact
This Agreement will be funded 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 to approve 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) to provide 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, 2021.

MEETING DATE: February 15, 2022
ITEM NO. 4.5(b)
FROM:
***APPROVED BY***
[email protected] [email protected]
SUBJECT: 4.5(b)--Agreement with EGIA for Rebate Processing Services Nick Zettel, Interim Director
of Redding Electric Utility
Packet Pg. 81
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
Program Name Applications
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-IRP 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. 82
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. (available 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)
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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. 84
Attachment: Consulting and Professional Services Contract with Electric and Gas Industries Association, Inc. (available online) (4.5(b)-- Page | 2
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.

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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.

Packet Pg. 86
Attachment: Consulting and Professional Services Contract with Electric and Gas Industries Association, Inc. (available online) (4.5(b)-- Page | 4
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.

I. 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) if required 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:

Coverage 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 “x” in the appropriate box)
Packet Pg. 87
Attachment: Consulting and Professional Services Contract with Electric and Gas Industries Association, Inc. (available online) (4.5(b)-- Page | 5
B. Coverage shall be at least as broad as:

1. 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:

1. 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.

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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 A.M.Best’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.

I. 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, Packet Pg. 89
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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 Packet Pg. 90
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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.

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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, fax 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 Packet Pg. 92
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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:

Daniel Beans
3611 Avtech Parkway
Redding, CA 96002
(530) 339-7350
To Consultant:

Bruce Matulich
3800 Watt Ave., Suite 105
Sacramento, CA 95821
(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.

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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.

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Task 1: Program 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
Redding
EGIA
1 Identify Project Manager X X
2 Finalize All Program Specifications with City Program Management
S X
3 Customize Program Specifications and Rules S X
4 Customize Consumer Messaging Requirements S X
5 Design Check Stock and Envelopes For Approval (if
applicable)
S X
6 Setup Bank Account/ Trust Account For Funding Rebate
Checks (if applicable)
S X
7 Finalize Program Messaging For Website Online
Application
S X
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
Rebate Processors Desktop Application
S X
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
Status Function
S X
18 Train CSR’s On Program, Including Terms & Conditions, Requirements, Qualifying Products and Application
S X
19 Develop Standardized Online Reporting Dashboard S X
20 Final Test All Systems and Processes with City Final Approval
S X
21 Launch Program & Begin Processing Rebate Applications S X Note: “X” indicates responsible party and “S” indicates supporting party.

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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
Program Management
30 3 Customize Program Specifications and Rules 30
4 Customize Consumer Messaging Requirements 30
5 Design Check Stock and Envelopes For Approval
(if applicable)
25 6 Setup Bank Account/ Trust Account For Funding
Rebate Checks (if applicable)
25 7 Finalize Program Messaging For Website Online
Application
25 8 Design Phone Script For Program For Approval 25
9 Program Checks and Envelopes Sent To Printer 20
10 Develop Program Customer Communication
Letters
15 11 Complete Development Of The Rebate Database
and Rebate Processors Desktop Application
15 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
Rebate Status Function
10 18 Train CSR’s On Program, Including Terms &
Conditions, Requirements, Qualifying Products and
Application
5 19 Develop Online Reporting Template and
Standardized Reports
5 20 Final Test All Systems and Processes with City
Final Approval
5 21 Launch Program & Begin Processing Rebate
Applications
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Task 2: Rebate Processing
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
Redding
EGIA
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 (pre-installation) and rebate applications (post-installation) and update in database.

X
5 Maintain Rebate Filing System X
6 Maintain Customer Call Center (call handling and
Customer Service)
X
7 Facilitate customer communication including customer
denial letter/email correspondence
X
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.

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Task 3: Provide Online Application Hosting 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
Redding
EGIA
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) and rebate applications (post-installation) and update in database X
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 correspondence
X
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.

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Task 4: Program Management and Reporting
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
Redding
EGIA
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 Managers.

X
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 participation updates)
X
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.

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Task 5: Service Management
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
Frame 95% of rebates processed within 30 days of receipt of completed application.

Call center availability 95% of phone calls answered within 60 seconds.

Call center quality
95% of calls monitored per EGIA quality assurance program achieve rating of “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
Redding
EGIA
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 moving forward.

X S
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.

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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
Redding
EGIA
1 Initiate a written task order defining scope of work and/or deliverables.

X
2 Determine cost and schedule associated with fulfilling the requested task.

X
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.

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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.

Item # Description Unit of
Measure
Not to
Exceed Price
Per Measure
Budgeted
Qty NTE Budget
1 Program Development and Startup – Phase 1 One-Time $8,500.00 1 $8,500 2 Task 2: Residential Electrification Rebate Processing Per Rebate Application $11.61 295 $3,425
Task 2: Commercial Electrification Rebate Processing Per Rebate Application $16.91 113 $1,911
3 Task 3: Provide online hosting of Residential New
Construction Rebate Application and Processing System
Per Month $1,458.00 60 $87,480
Per Rebate
Application $16.91 160 $2,706
Task 3: Provide online hosting of Retail Voucher Rebate Application and Processing System
Per Month $991.00 60 $59,460
Per Rebate
Application $11.61 75 $871
4 Task 4: Program Management and Reporting AND Task 5:

Service Management Per Month $2,597.00 60 $155,820
5 Task Order Contingency Maximum
Budget $25,000 1 $25,000
6 Collect W9s and issue 1099s relating to Commercial
Electrification , Residential New Construction and Retail Voucher Rebates
Per
Application $21.20 348 $7,378
7 Printing and Postage (reimbursed at cost) Maximum
Budget $1,000 1 $1,000
8 Monetary compensation (rebates) paid to customers
(reimbursed at cost)
Maximum
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
Minimum Monthly Rebate Processing Charge
A minimum rebate-processing fee of $300/ month will be charged should monthly rebate processing volume fall below the 11-rebate application minimum.

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Consultant Standard Hourly Billing Rates by Position
Position Hourly Rate
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
Senior Application 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
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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 explicitly 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).

EGIA REBATE PROCESSING SYSTEM (ERPS)
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 application related to customer’s purchases and rebate data fields required for the utility 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.

Data Validation
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 scripting, 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” section of this proposal.

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Rebate Systems In Place To Validate Compliance To Program Rules And Eligibility 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 through the software solution or EGIA CSR’s as part of a full service turnkey 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.

EGIA’s Rebate Processing System Provides An Audit Trail of all Processing Transactions
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.

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Rebate Processing Flow
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.

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Sample Application Exception Codes and Auto Generated Problem Letter 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.

SoCal Water$mart Codes
Code Description
Automatic or
Manual Status

AA INSTALL ADDRESS DOES NOT MATCH THE WATER BILL M R

AD SALES RECEIPT APPEARS TO BE ALTERED M R

AT CUSTOMER APPLIED TWICE M D
BC SUBMITTED WATER BILL IS OVER 6 MONTHS OLD M R

CB CUSTOMER NAME, SERVICE ADDRESS MISSING FROM BILL M R

CD CUSTOMER ASKED TO DELETE REBATE M D

CR NEED CUSTOMERS SALES RECEIPT M R

DM DUPLICATE MEASURE A D

DN NAME ON APPLICATION DOESN'T MATCH NAME ON BILL M R

FO NO RESPONSE FROM CUSTOMER M D

IA NO INSTALLATION ADDRESS ON RECEIPT M R

IR RECEIPT IS ILLEGIBLE M R

MN MODEL NUMBER NOT ON RECEIPT M R

NM NO CUSTOMER NAME ON WATER BILL M R

NP NO PURCHASE PRICE SUPPLIED A R

NQ NON-QUALIFYING MODEL NUMBER A D

NR INITIAL PAPERWORK NOT PROVIDED BY APPLICANT A R

NV NEED FURTHER VERIFICATION OF QUALIFICATIONS M R

OP PURCHASED BEFORE OR AFTER PROGRAM PERIOD A D

OR COPY OF SALES RECEIPT IS MISSING M R

OY PURCHASED OVER ONE YEAR AGO A D

PF PROOF OF FULL PAYMENT REQUIRED M R

PG WATER BILL NEEDED FOR ACCOUNT VERIFICATION M R
PP POSTMARK 90 DAYS AFTER ONLINE SUBMISSION DATE A D

QC NOT QUALIFYING CITY A D

RD NO SALES DATE ON RECEIPT M R

RE REQUIRED EFFICIENCY NOT MET A D

RO RESIDENTIAL APPLICANTS ONLY M D

RT CUSTOMER RETURNED MERCHANDISE M D

SA NO SERVICE ADDRESS ON WATER BILL M R

SI INVALID STORE M D

UD UTILITY DECLINED A D

UP PURCHASE PRICE MISSING FROM RECEIPT M R

UZ ZIP CODE DOES NOT BELONG TO SERVICE AREA A D
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Rebate Invoice and Check Cutting Process
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.

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Fraud Prevention and Mitigation
When EGIA is delivering rebate process as a comprehensive full service, we us an assortment 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 Information 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.

Returning Unspent Rebates
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 property 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 that 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 property.

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.

Reservation System for Pre-Approved Rebates
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 remaining in both percentage and dollar terms. This information is accessible to the utility program managers through 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.

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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 will be 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.

Customer Care/Call Center Operation
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 Packet Pg. 112 Attachment: Consulting and Professional Services Contract with Electric and Gas Industries Association, Inc. (available online) (4.5(b)-- Page | 30
system monitoring capability, EGIA management is able to periodically assess CSR call handling performance, and through 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 substantial call tracking, call reporting and automated call redirection capability. For example, if the CSR group assigned one utilities customer calls is experiencing 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 8:00am to 5:00 pm PST, Monday through 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.

Program Performance Reporting Dashboard
EGIA has developed and deploys a highly flexible 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 managers 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 flexible 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.

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Sample Customizable Dashboard Reports
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ERPS IT Architecture and Data Security
EGIA has developed and maintains a very robust database management system that can track every element of rebate programs administered by the utility through an EGIA application hosting solution or directly from EGIA through 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.

The following is an overview of EGIA’s Information Physical Technology Architecture. EGIA has 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 technological 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 of reporting from all program information  Storage of all consumer and product information
 Rebate check generation interface
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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 efficiency requirements are programmed 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 measures is immediately determined upon data entry of application.

4. EGIA’s database management system allows up-to-the-minute, live tracking of rebate 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.

Network Architecture
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.

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Secure Web Application User Interface
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.

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Application and Reporting Architecture
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.

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Security Authentication, Authorization and Accounting
User Account Administration
Microsoft Active Directory is utilized for user account administration. User accounts are stored and are synchronized 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.

Vulnerability Management Program
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.

System and Data Recovery Program
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.

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Attachment: City of Redding Purchasing approval (available online) (4.5(b)--Agreement with EGIA for Rebate Processing Services) Packet Pg. 122
Attachment: City of Redding Purchasing approval (available online) (4.5(b)--Agreement with EGIA for Rebate Processing Services)

CITY OF REDDING

REPORT TO THE CITY COUNCIL
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 to approving 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’s Electric 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’s current Program Portfolio supports the state’s energy efficiency doubling goals under the California Clean Energy and Pollution Reduction Act of 2015 (Senate Bill 350).

MEETING DATE: September 21, 2021
ITEM NO. 4.5(e)
FROM:
***APPROVED BY***
[email protected] [email protected]
SUBJECT: 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan report and approve adjustments to Redding Electric Utility's Customer Programs.

Nick Zettel, Assistant
Director of Electric Utility
Packet Pg. 123 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Report to Redding City Council September 14, 2021
Re: 4.5(e)--2021 DSM-IRP Report and Adjustments 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-IRP) 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 measures, 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-IRP 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 1, 2022 • Terminate existing energy efficiency rebates on June 30, 2022 • Launch new building electrification and transportation electrification rebates beginning July 1, 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. 124 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Report to Redding City Council September 14, 2021
Re: 4.5(e)--2021 DSM-IRP Report and Adjustments 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.

If the recommendations are authorized by the Council, staff will incorporate the DSM-IRP 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. 125 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Table of Contents i
Demand-Side Management

INTEGRATED RESOURCE PLAN
CITY OF REDDING | SEPTEMBER 2021
Packet Pg. 126 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Table of Contents 1-ii
Table of Contents
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 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 Packet Pg. 127 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Table of Contents 1-iii

LIST OF TABLES
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

LIST OF FIGURES
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 Packet Pg. 128 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Acronyms, Abbreviations, and Definitions List AL-1
Acronyms, Abbreviations, and Definitions List
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 LIfe
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
MW Megawatt
MWh Megawatt-hour
Packet Pg. 129 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Acronyms, Abbreviations, and Definitions List AL-2
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 measure options used for comparison STATE State Regulatory Surcharge
Therm Measurement of heat equivalent to 100,000 British Thermal Units (BTU) ZEV Zero Emission Vehicle
Packet Pg. 130 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan DSM-IRP Project Partners PP-1
DSM-IRP Project Partners
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
Packet Pg. 131 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Executive Summary 5

1.0 Executive Summary
This report documentsthe 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.

Step 1: Develop Guiding Principles
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:
 Offer measures where program participants save money
 Ensure customer programs do not cause transfers of funds from participants to nonparticipants  Focus on programs that cost-effectively reduce carbon emissions Step 2: Identify Key Assumptions and Cost-Effectiveness Tests 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:
 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.  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 Packet Pg. 132 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Executive Summary 6
rate pressure and can help identify measures that align with the guiding principles because it provides benefits to both program participants and non-participants.  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.  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.

Test Component PCT, $ UCT, $ RIM, $ TRC, $ CIT,
$/MT GHG
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
Table 1-1: Summary of Cost-Effectiveness Components for Each Measure Test Step 3: Identify and Characterize Measure Options
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.

Step 4: Perform Detailed Analysis
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 Packet Pg. 133 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Executive Summary 7
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.

Program PCT, $ RIM, $
CIT
(RIM/GHG
Reduction,
$/Ton)
Program
Cost, $
Lifecycle Net
Revenue
Impacts, $
Lifecycle
Carbon
Savings,
Tons
Energy Efficiency Rebates
(FY19) $4,090,000 ($4,540,000) ($540) $950,000 ($3,590,000) 8,330 Shade Trees (FY19) $160,000 ($180,000) ($760) $80,000 ($110,000) 240 Low Income Direct Install
(FY19) $460,000 ($690,000) ($560) $500,000 ($180,000) 1,230 Residential Energy
Discount (FY19) $2,930,000 ($3,010,000) N/A $3,010,000 $0 0 Public Streetlights (FY19) $0 ($110,000) ($230) $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 Table 1-2: Program Performance of FY 2019 EE Programs (Historic) vs. Future BE and TE Programs Based on the information in Table 2, REU staff found the following:
 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.
 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.  Energy efficiency measures are cost-effective for the customers who participate in the energy efficiency programs, as indicated by a positive participant cost test.  Building Electrification Measures pass the RIM test, indicating that they will provide downward rate pressure.
 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.
 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.

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Step 5: Develop a Recommended Program Plan
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:
 Introducing the lowest-risk, most cost-effective measures first  Developing a robust education and outreach program to ensure that all stakeholders have a positive experience
 Ensuring customer satisfaction is tied to the success of the program  Add new measures as technologies improve and/or participation increases  Incorporating lessons learned into a continuous program improvement process Using this phase approach, REU plans to initially offer rebates for the following measures:
 Commercial and Residential Electric Vehicles
 Electric Forklift Rebates
 Low Income Residential Electric Vehicle Rebates
 Residential and Commercial Heat Pump Water Heaters Replacing Natural Gas Water Heaters
 Electric New Home Construction
 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:
 Residential and Commercial Heat Pump Space Heaters Replacing Natural Gas Furnaces  Induction Cooktops
 Panel Upgrades
 Residential and Commercial EV Chargers
Packet Pg. 135 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Purpose and Background 9

2.0 Purpose and Background

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.

Figure 2-1: Example of Various Costs and Benefits Evaluated

COSTS BENEFITS
Program Administration Cost
Customer Rebates
Lost Revenue due to Load
Reduction Programs
Avoided Cost to Procure Energy
Reduced Environmental Impacts
Increased Revenue due to Load
Building Programs
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3.0 Overview of Methodology
The critical steps of the DSM-IRP development undertaken are shown in Figure 3-1.

Figure 3-1 Critical Steps in DSM-IRP Development
•DEVELOP GUIDING PRINCIPLES
•Identify detailed regulatory and funding requirements. •Characterize community priorities as related to environmental stewardship. •Establish applicable policy goals - programs can address a variety of local goals and objectives; should be carefully considered and clearly defined.

Step 1
•IDENTIFY KEY ASSUMPTIONS AND COST-EFFECTIVNESS TESTS
•Develop assumptions that will drive financial impacts such as rate forecasts, avoided cost forecasts, measure cost and many others.
•Develop Cost-Effectiveness tests that reflect the community's policy goals and can be used to compare all DSM Program options.

Step 2
•IDENTIFY AND CHARACTERIZE DSM PROGRAM OPTIONS AND PORTFOLIOS •Develop cost and performance characteristics of each measure and program. Step 3 •PERFORM ANALYSIS OF OPTIONS, IDENTIFY PREFERRED PLAN
•Analyze DSM portfolios and identify the changes relative to the base case. •Select the options that best align with the policy goals.

Step 4
•DEVELOP PREFERED SCENARIO INTO A PROGRAM IMPLEMENTATION PLAN •Develop 10 year proforma plan of programs, program impacts, budget and source of funding. Consider transition from current state to future state. •Define criteria and process for ad-hoc adjustments to the plan, such as criteria for program additions or subtractions.

Step 5
•PREPARE IRP DOCUMENT, SECURE INTERNAL APPROVALS, SUBMIT •Develop the IRP document, get feedback from internal and external sources, secure approval from Council and submit in accordance with regulatory requirements, if applicable.

Step 6
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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.

Planning Step Activity Analysis Tools, Industry Standards, or Planning Activity Step 2:

Identify Key
Assumptions &
Cost-Effectiveness
Tests
Develop Key Assumptions
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, distribution, carbon and renewable fees, and all other fees.

The CPUC Avoided Cost Calculator1 is used to develop an avoided cost forecast for natural gas rates.

The “2017 CMUA Savings Estimation POU Technical Reference Manual”2 is used to define energy efficiency measure impacts, load shapes and other key characteristics.

Develop Cost-Effectiveness
Tests
The basis of all cost-effectiveness tests used are defined in the “National Home Performance Council, Inc., Resource Value Framework”3.

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.

Step 3:

Identify &
Characterize DSM
Program Options
and Portfolios
Define cost & performance
characteristics of each
measure and program.

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

Develop and document assumptions for all measures that are not defined elsewhere.

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
2 https://www.cmua.org/energy-efficiency-technical-reference-manual 3 https://www.homeperformance.org/sites/default/files/nhpc_nesp-recommendations_20140816.pdf Packet Pg. 138 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Overview of Methodology 12
Planning Step Activity Analysis Tools, Industry Standards, or Planning Activity Step 4:

Perform Analysis
and Identify
Preferred Plan
Analyze DSM portfolios and
identify the programs and
measures that best align
with guiding principles and
cost-effectiveness tests.

All measure, program and portfolio attributes are loaded in the Statewide Energy Efficiency Planning tool, “ESP Portfolios,” which quantifies the costs and benefits of each measure.

ESP Portfolio Results are post-processed to determine costeffectiveness parameters based on the cost-effectiveness tests developed in step 2.

Step 5:

Develop Preferred
Scenario into a
Program
Implementation
Plan.

Develop 10 year DSM
Program plan to define
criteria and process for adhoc adjustments
Develop a plan to transition from the current State of DSM program offerings to a preferred scenario. Quantify load impacts and revenue impacts and budgetary needs.

Develop criteria and methods for making future adjustments to the preferred plan to allow flexibility for new measures or changing customer needs.

Table 3-1: Tools Used in DSM-IRP Study and Analysis
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4.0 Guiding Principles
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.

Packet Pg. 140 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Guiding Principles 14
Figure 4-1: Timeline of Key Legislative Actions Impacting DSM-IRP Planning Packet Pg. 141 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Guiding Principles 15
SB 350 CA Clean Energy and Pollution Reduction Act
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.

SB 1037
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 programsto 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.

AB 2021
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.

PUC 385
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 Packet Pg. 142 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Guiding Principles 16
provides substantial flexibility in use of the funds, though “public interest” and consistency with existing statutes are noted.

PUC 386
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.

PUC § 454.5 and PUC § 9615
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.

PUC § 9505
PUC § 9505 codifies energy efficiency planning requirements as follows:
 Every four years, POUs must identify cost-effective EE and establish annual targets for the next 10 years
 Every year, POUs must report progress against the annual targets Packet Pg. 143 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Guiding Principles 17
 POU’s should not consider previous minimum investments per PUC 385 when identifying cost-effective EE.
 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.

PUC § 9621
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:
 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 CARB, in coordination with the CPUC and the Energy Commission, results in economywide GHG emission reductions of 40 percent from 1990 levels 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 (MMTCO2e) 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 level of 108 MMTCO2e.  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

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 2.3, Article 16, 399.11-399.32, the interim requirements are listed in 399.15(b.2.B) and 339.30 (c, 2).

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reliability, strengthening the transmission and distribution system, enhance demand-side management, and minimizing pollutants with early priority on disadvantaged communities.

SB 100
Senate Bill 100 (SB 100), or the 100 Percent Clean Energy Act of 2018, wassigned 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:
 40 percent to 44 percent by 2024;
 45 percent to 52 percent by 2027; and
 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 originatesfrom 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.

Public Benefits
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.

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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 ⅔ 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.

Greenhouse Gas
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 allowances7 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:
 Renewable Energy or integration of RE, including construction and support for renewable energy and/or energy storage projects.
 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: https://ww2.arb.ca.gov/our-work/programs/cap-and-trade-program/cap-andtrade-regulation 7 Each allowance represents one metric ton of GHG emissions.

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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.
 Other GHG Emission Reduction Activities that reduce emissions of sulfur hexafluoride or hydrofluorocarbons; and wildfire risk reduction or forest carbon sequestration activities8  Non-Volumetric Return to Ratepayers
 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.

Low Carbon Fuel Standard
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).

Ratepayer Funds
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.

8 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.

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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:
 Customers prioritize low bills and reliability over the carbon footprint of the utility.  The majority of customers would rather meet the environmental mandates than exceed them.
 Almost half of the customers surveyed are not willing to pay more for renewable and carbon-free electricity.
 In the list of future resource options, energy efficiency ranked fourth behind solar, wind, and hydropower.
 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.  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.

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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.

Potential Limits due to Proposition 26
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:
 “Any cost to exceed the statutory mandate for NEM contracts must be funded from non‐ rate 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.”
 “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.)
 “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 Packet Pg. 149 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Guiding Principles 23
 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.  Cross-subsidies among customer classes are unlawful.

Local Economic Impact Considerations
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:
 “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:
 When performing cost-benefit analysis, general “economic benefits” such as increased economic growth resulting from a program should not be included as a benefit.

Findings from the Solar Committee
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:
 In response to City Council’s 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.
 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.”
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Staffs interpretation of these statements as applied to non-solar DSM programs is as follows:
 REU should not overly prioritize the economics of a measure when setting incentive levels.
 REU’s DSM portfolio should be fair to non-participants and legally defensible.  The definition of “highest credit rate” should be considered when developing the avoided cost rate.

City Council Approval of the Avoided Cost Rate
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.

Figure 4-2: NEM 2.0 Avoided Cost of Site Electricity
$37.20
$19.00
$1.50
$3.10
$0.00
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
$70.00
Avoided Cost
NEM 2.0 Avoided Cost of Site Electricity
Energy RPS Transmission Losses Distribution Losses
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5.0 Identify Key Assumptions and Cost-Effectiveness Tests

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.

10 https://www.cpuc.ca.gov/general.aspx?id=5267 11 https://www.nationalenergyscreeningproject.org/wp-content/uploads/2017/05/NSPM_May-2017_final.pdf Packet Pg. 152 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Identify Key Assumptions and Cost-Effectiveness Tests 26 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.

Cost-Effectiveness Test Key Perspective Summary Approach Participant (PCT) Will participants benefit over the life of the measure?
Compare costs and benefits for the
customer installing the measure
Utility/Program Administrator
(UCT/PACT))
Will utility bills increase? Compare program costs to alternative supply-side options
Ratepayer Impact (RIM) Will utility rates increase? Weighs the cost of programs and reduction in revenue against supplyside resource savings Total Resource (TRC) Will the cost of energy in the service territory increase?
Compares program and customer costs
to utility savings
Societal (SCT) Is the utility, State, or other jurisdiction better off?
Societal-level benefits and costs of
energy efficiency at the jurisdictional
level
Table 5-1: Summary of CSPM Cost-Effectiveness Tests
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.

Packet Pg. 153 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Identify Key Assumptions and Cost-Effectiveness Tests 27 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.

Test Component PCT UCT/PACT RIM TRC SCT
Electric energy and capacity avoided costs Benefit Benefit Benefit Benefit Other fuel savings (natural gas, fuel oil, propane,
etc.) Benefit Benefit Benefit
Non-energy benefits (e.g., water, O&M costs, etc.) Benefit if 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
Bill savings / Utility Lost Revenue Benefit Cost
Table 5-2: Summary of Cost-Effectiveness Components and Treatment 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.

Packet Pg. 154 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Identify Key Assumptions and Cost-Effectiveness Tests 28 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.

Carbon Impact Test
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.

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6.0 DSM Program Options and Portfolios

6.1 REU EXISTING PROGRAMS
Energy Efficiency Programs
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.

6.1.1.1 Residential Deemed Rebates
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
 Heat Pump
 Electric Storage
 Ceiling Fan
 Refrigerator
 Room Air Conditioner
HVAC & Thermostat Building Shell
 Air Conditioner Unit
 Heat Pump Unit
 Whole House Fan
 Wi-Fi Enabled Thermostat
 Dual Pane Windows
 Wall Insulation
 Ceiling Insulation
♦ In FY 2020, the Residential Deemed Rebates program accounted for nearly 8% of the total energy savings.

6.1.1.2 Low Income Energy Efficiency Program
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
 Heat Pump  Ceiling Fan
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 Electric Storage
 Water Heater Blankets
 Low-Flow Aerators and Shower Heads
 Refrigerator
 Room Air Conditioner
HVAC & Thermostat Building Shell
 Air Conditioner Unit
 Heat Pump Unit
 Wi-Fi Enabled Thermostat
 Coil Cleaning and Refrigerant Charge
 Dual Pane Windows
 Wall Insulation
 Ceiling Insulation
Other
 LED Light Bulbs
 Smart Power Strips
♦ In FY 2020, LIEEP accounted for 10.5% of the total energy savings.

6.1.1.3 Commercial Deemed Rebates
The Commercial Rebate Program offers prescriptive rebates for a variety of measures that work to reduce energy consumption and save customers money. The measures included in the Commercial Rebate Program are as follows:

Food Service Refrigeration
 Ice Machine
 Glass Door Refrigerators & Freezers
 Solid Door Refrigerators & Freezers
 Insulated Holding Cabinets
 Commercial Electric Combination Oven
 Electric Steam Cooker
 Electric Convection Oven
 Electric Fryer
 Electric Griddle
 Vending Machine Controller
 Auto Door Closer
 Anti-Sweat Heater (ASH) Controls
 Electronically Commutated Evaporator
Fan for Walk-In Cooler or Display Case
HVAC & Thermostat
 Air Conditioner Unit
 Heat Pump Unit
 Wi-Fi Enabled Thermostat
♦ In FY 2020, the Commercial Deemed Rebates program accounted for <0.5% of the total energy savings
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6.1.1.4 Commercial Custom
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. ♦ There were no energy savings from the Commercial Custom program in FY 2020.

6.1.1.5 Commercial Lighting
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.
♦ In FY 2020, Commercial Lighting accounted for over 70% of Redding’s net energy savings reported to the CEC (2.1M kWh).

6.1.1.6 Energy Advisor
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.
♦ In FY 2020, the Residential Energy Advisor program accounted for <1.0% of energy savings.

6.1.1.7 LED Streetlight Replacement
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.

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♦ In FY 2020, the LED Streetlight Replacement program accounted for 7.1% of energy savings.

Transportation Electrification Program
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.

6.1.2.1 Residential Electric Vehicle Rebates
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.

6.1.2.2 Commercial Electric Vehicle Rebates
The utility currently offers an incentive for Commercial customersfor 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:
 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.
 Opted into the State’s Low Carbon Fuel Standards program to generate revenue through residential EV charging that is reinvested in transportation electrification.  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.
 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.  Installed 10 Level II fleet and employee EV charging stations at two City facilities.  Converted 19 fleet vehicles from gas to electric, retiring the City’s highest emitting vehicles.

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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:
 Increase customer outreach and education efforts through marketing and events.  Install fleet and employee charging at the City of Redding Police Department and Redding Power and continue the conversion of fleet vehicles to electric.  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.
 Develop equity programs to primarily benefit low-income and disadvantaged communities.
 Continue to encourage the development of EV charging rates to incentivize commercial investments in public infrastructure and fleet conversions.  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:
 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.
 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.  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 Packet Pg. 160 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan DSM Program Options and Portfolios 34
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 measures currently being promoted by each utility are summarized in Tables 6-1 and 6-2.

PG&E
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.

12 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 Packet Pg. 161 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan DSM Program Options and Portfolios 35
Sacramento Municipal Utility District (SMUD)
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.

Modesto Irrigation District (MID)
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 15 https://www.energy.ca.gov/filebrowser/download/1937
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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.

City of Roseville Electric Utility (Roseville)
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.

Summary of Program Supported Measures
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 measures. 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 Packet Pg. 163 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan DSM Program Options and Portfolios 37
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 measures.

Measure Type Redding SMUD PG&E Roseville MID
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    
Table 6-1: Residential DSM Portfolio Measure Comparison 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.

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Measure Type Redding SMUD PG&E Roseville MID
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

Table 6-2 Commercial DSM Portfolio Comparison
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7.0 Measure and Program Analysis
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:
 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.  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.  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.

Number Measure Type Measure Name Unit Type PCT ($) RIM ($) CIT ($/Metric Ton) EUL 1 Energy Efficiency AC Pkg Unit-< 5 Tons
(55kBtuh)-15 SEER Ton $3,817 ($4,072) ($497) 15
2 Energy Efficiency

ENERGY STAR HP
water heater, 80 gal.,
located in
garage/basement
Water
Heater $611 ($1,308) ($409) 10
3 Building Electrification All-Electric New Home
17 SEER HP 3-tons
Home $11,202 $5,498 $142 20
4 Building Electrification
DHW Full
Electrification - Gas to
HP Water Heater
Water
Heater $1,201 $1,537 $209 10
5 Transportation
Electrification
Small Light Duty
Vehicle-PHEV Vehicle $2,547 $2,056 $146 12
Table 7-1 DSM-IRP Study Measure Level Results
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The results shown in Table 7-1 demonstrate the following findings applicable to most energy efficiency measures.
 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.
 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.  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.
 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.
 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.
 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.

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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.

Table 7-2 DSM-IRP Study Results
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:
 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.
 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.

Program PCT, $ RIM, $
CIT
(RIM/GHG
Reduction,
$/Ton)
Program
Cost, $
Lifecycle Net
Revenue Impacts,
$
Lifecycle
Carbon
Savings, Tons
Energy Efficiency
Rebates (FY19) $4,090,000 ($4,540,000) ($540) $950,000 ($3,590,000) 8,330 Shade Trees (FY19) $160,000 ($180,000) ($760) $80,000 ($110,000) 240 Low Income Direct
Install (FY19) $460,000 ($690,000) ($560) $500,000 ($180,000) 1,230 Residential Energy
Discount (FY19) $2,930,000 ($3,010,000) N/A $3,010,000 $0 0 Public Streetlights
(FY19) $0 ($110,000) ($230) $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 Packet Pg. 168 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Measure and Program Analysis 42
 Energy efficiency measures are cost-effective for the customers who participate in the energy efficiency programs, as indicated by a positive participant cost test.  Building Electrification Measures pass the RIM test, indicating that they will provide downward rate pressure.
 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.
 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.

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8.0 Electrification Program Development
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:
 Introducing the lowest-risk, most cost-effective measures first  Developing a robust education and outreach program to ensure that all stakeholders have a positive experience
 Ensuring customer satisfaction is tied to the success of the program  Adding new measures as technologies improve and/or participation increases  Incorporating lessons learned into a continuous program improvement process Residential Building Electrification

8.1.1.1 Existing Building Rebates
The Residential Building Electrification – Existing Buildings 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.

Measure Type Proposed Incentive Amount Implementation Date Heat Pump Water Heater $1,000 per unit July 1, 2022 Clothes Dryer $200 per unit Heat Pump Space Heat
Induction Cooktops To Be Determined To Be Determined
Electric Ovens
Table 8-1: Existing Residential Buildings Electrification Program Details Packet Pg. 170 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Electrification Program Development 44

8.1.1.2 New Construction Rebates
The Residential Building 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.

Measure Type Proposed Incentive Amount Implementation Date 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
Table 8-2: Residential New Construction Building Electrification Program Details Commercial Building Electrification

8.1.2.1 Commercial Rebates
The Commercial Building 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.

Measure Type Proposed Incentive Amount Implementation Date Heat Pump Water Heater $1,000 per unit July 1, 2022
Heat Pump Space Heater To Be Determined To Be Determined Table 8-3: Commercial Building Electrification Program Details Education and Outreach
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 Packet Pg. 171 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Electrification Program Development 45
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:
 Provide education on the pros and cons of fuel switching, the potential cost savings, and the overall benefits of building electrification
 Educate customers on the rebate programs and how to participate in them  Solicit feedback from customers regarding satisfaction with the programs  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.

Transportation Electrification Rebate Program
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.

8.2.1.1 Program Measures
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 Packet Pg. 172 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Electrification Program Development 46
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.

Table 8-4: Transportation Electrification Program Details Low Income Transportation Electrification Program
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.

8.2.2.1 Program Measures
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.

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.

17 Low Carbon Fuel Standards Current Regulation
Measure Type Incentive Amount Program Start Date Funding Source Residential and Commercial
EV Rebates
$1,000 per unit Existing LCFS
Electric Forklift Rebates $2,500 per unit July 1, 2021 LCFS Measure Type Incentive Amount Program Start Date Funding Source EV Rebates for Income
Qualified Customers
$3,000 per unit July 1, 2022 LCFS Low-Income
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Custom Community Projects

8.2.3.1 Program Benefits to Customers
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.

8.2.3.2 Program Features
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:
 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.  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.  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.

Education and Outreach
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:
 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.  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.

Packet Pg. 174 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Electrification Program Development 48
 Provide easy access to resources to ensure interested parties are more knowledgeable about applicable incentives when purchasing or leasing an electric vehicle.  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.

Program Type Transportation Electrification Building Electrification Total Source of Funding LCFS LCFS-Low Income Public Benefits
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
Total $980,000 $1,050,000 $4,800,000 $6,830,000
Table 8-5: 10-Year Electrification Available Budget forecast summary Program Type Transportation Electrification Building
Electrification
Total
Source of Funding LCFS (Rebates)
LCFS-Low
Income
(Rebates)
LCFS- Low
Income
(Community
Projects)
Public Benefits
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
Packet Pg. 175 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Electrification Program Development 49
2028 - - - - -
2029 - - - - -
2030 - - - - -
2031 - - - - -
Total $335,000 $165,000 $325,000 $1,970,000 $2,795,000
Table 8-6: 10-Year Electrification Planned Expenditure Summary 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.

Measure Description Budget Amount Funding Budgeted Measure Qty FY 22-27
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
Table 8-7: Measure Quantities included in Planned Expenditure Summary

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.

Packet Pg. 176 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Conclusion 50

9.0 Conclusion
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.

Packet Pg. 177 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Appendices 51

10.0 Appendices

10.1 APPENDIX A: AVOIDED COSTS
Year Energy
Transmission
Losses
Distribution
Losses
RPS
Procurement
Total
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
Table 10-1: Avoided Cost Forecast by Component, $/kWh
Packet Pg. 178 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Appendices 52
$0.00
$0.01
$0.02
$0.03
$0.04
$0.05
$0.06
$0.07
$0.08
$0.09
$0.10
$/kWh
Avoided Cost Forecast
Energy Transmission Losses Distribution Losses RPS Procurement Packet Pg. 179 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Appendices 53

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
 Residential (E1)
 Low-Income Residential (E1LP)
 Small Commercial (E2)
 Large Commercial (E7) (Blended Rate)
 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 purchasesfrom 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. https://www.cityofredding.org/Home/ShowDocument?id=22899 Packet Pg. 180 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Appendices 54
$0.00
$0.02
$0.04
$0.06
$0.08
$0.10
$0.12
$0.14
$0.16
$0.18
$/kWh
REU Volumetric Electricity Rate Forecast
LED Streetlights E2-Commercial E1LP-LI Residential
E1-Residential E7-Large Commercial
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
$/therm
PG&E Natural Gas Retail Rate Forecast
PG&E Small Commercial Gas PG&E Residential Gas
PG&E LI-Residential Gas PG&E Large Commercial Gas
Packet Pg. 181 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Appendices 55
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$/gal
Gasoline Rate Forecast
Vehicle Gasoline
$0.00
$20.00
$40.00
$60.00
$80.00
$100.00
$120.00
$140.00
$160.00
$/Carbon Allowance
Carbon Allowance Value Forecast
Carbon
Packet Pg. 182 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Appendices 56

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:

1. 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)
Packet Pg. 183 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Appendices 57
The Benefit (Bp) and Cost (Cp) terms are further defined as follows:

BP = � 𝐵𝐵𝐵𝐵𝑡𝑡 + 𝑇𝑇𝑇𝑇𝑡𝑡 + 𝐼𝐼𝐼𝐼 𝑡𝑡
(1 + 𝑑𝑑)
𝑡𝑡−1
N
t=1
+ � 𝐴𝐴 𝑎𝑎 + 𝑃𝑃 𝑎𝑎
(1 + 𝑑𝑑)
𝑡𝑡−1
𝑡𝑡=1
C = � 𝑃𝑃 𝑡𝑡 + 𝐵𝐵 𝑡𝑡
�1 + 𝑑𝑑�
𝑡𝑡−1
N
t=1
Where:

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 ABat) 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:

𝐵𝐵𝐵𝐵𝑡𝑡 = �(∆𝐸𝐸𝐸𝐸𝑖𝑖𝑖𝑖 × 𝐴𝐴 ∶ 𝐸𝐸𝑖𝑖𝑖𝑖 × 𝐾𝐾𝑖𝑖𝑖𝑖) +
I
i=1
�(∆𝐷𝐷 𝑖𝑖𝑖𝑖 × 𝐴𝐴 ∶ 𝐷𝐷𝑖𝑖𝑖𝑖 × 𝐾𝐾𝑖𝑖𝑖𝑖)
𝐼𝐼
𝑖𝑖=1
+ 𝑂𝑂 𝑡𝑡
𝐴𝐴 𝑎𝑎 = (Use BRt formula, but with rates and costing periods appropriate for the alternate fuel utility)
𝐵𝐵 𝑡𝑡 = ��∆𝐸𝐸𝐸𝐸𝑖𝑖𝑖𝑖 × 𝐴𝐴 ∶ 𝐸𝐸𝑖𝑖𝑖𝑖 × (𝐾𝐾𝑖𝑖𝑖𝑖 − 1)� +
I
i=1
��∆𝐷𝐷 𝑖𝑖𝑖𝑖 × 𝐴𝐴 ∶ 𝐷𝐷𝑖𝑖𝑖𝑖 × (𝐾𝐾𝑖𝑖𝑖𝑖 − 1)�
𝐼𝐼
𝑖𝑖=1
+ 𝑂𝑂 𝑡𝑡
Where:

Packet Pg. 184 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Appendices 58
∆EGit = Reduction in gross energy use in costing period i in year t ∆DGit = Reduction in gross billing demand in costing period i in year t AC:Eit = 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 PCt term.
4 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. If the 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:Dit = Rate charged for demand in costing period i in year t Kit = 1 when ∆EGit or ∆DGit is positive (a reduction) in costing period i in year t, and zero otherwise
OBRt = Other bill reductions or avoided bill payments (e.g., customer charges, standby rates).

OBIt = 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:

LRIRIM
FRIRIM
ARIRIMt
=
=
=
(CRIM - BRIM) / E
(CRIM - BRIM) / E
FRIRIM
for t = I
for t = I
= (CRIMt - BRIMt )/Et for t=2,...,N
NPVRIM = BRIM-CRIM
BCRRIM` = BRIM/CRIM
Packet Pg. 185 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Appendices 59
Where:

LRIRIM = 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.) FRIRIM = First-year revenue impact of the program per unit of energy, demand, or per customer.

ARIRIM = 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 BRIM and CRIM terms are further defined as follows:

BRIM = � 𝑈𝑈 𝑡𝑡 + 𝑡𝑡
(1 + 𝑑𝑑)
𝑡𝑡−1
N
t=1
+ � 𝑈𝑈 𝑎𝑎
(1 + 𝑑𝑑)
𝑡𝑡−1
𝑡𝑡=1
CRIM = �𝑈𝑈 + 𝑅𝑅 + 𝑃𝑃 + 𝐼𝐼𝐼𝐼
(1 + 𝑑𝑑) −1
N
t=1
+ � 𝑅𝑅𝑎𝑎
(1 + 𝑑𝑑) −1
𝑁𝑁
=1
E= � 𝐸𝐸𝑡𝑡
(1 + 𝑑𝑑)
𝑡𝑡−1
N
t=1
Where:

Packet Pg. 186 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Appendices 60
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 and gas. 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 (UACt, UICt, and UACat) are further determined by costing period to reflect time-variant costs of supply:

𝑈𝑈 𝑡𝑡 = �(∆𝐸𝐸 𝑖𝑖𝑖𝑖 × 𝑀𝑀 ∶ 𝐸𝐸𝑖𝑖𝑖𝑖 × (𝐾𝐾𝑖𝑖𝑖𝑖)
I
i=1
+ �(∆𝐷𝐷 𝑖𝑖𝑖𝑖 × 𝑀𝑀 ∶ 𝐷𝐷𝑖𝑖𝑖𝑖 × 𝐾𝐾𝑖𝑖𝑖𝑖)
𝐼𝐼
𝑖𝑖=1
UACat = (Use UACt formula, but with marginal costs and costing periods appropriate forthe alternate fuel utility.)
𝑈𝑈 𝑡𝑡 �(∆𝐸𝐸 𝑖𝑖𝑖𝑖 × 𝑀𝑀 ∶ 𝐸𝐸𝑖𝑖𝑖𝑖 × (𝐾𝐾𝑖𝑖𝑖𝑖 − 1))
I
i=1
+ �(∆𝐷𝐷 𝑖𝑖𝑖𝑖 × 𝑀𝑀 ∶ 𝐷𝐷𝑖𝑖𝑖𝑖 × (𝐾𝐾𝑖𝑖𝑖𝑖 − 1)))
𝐼𝐼
𝑖𝑖=1
Where:
[Only terms not previously defined are included here.]
∆ENit = Reduction in net energy use in costing period i in year t ∆DNit = 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 Packet Pg. 187 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Appendices 61
The revenue impact terms (RGt, RLt, and RLat) 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 differentiate gross 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 BTRC, CTRC, LCRC, and IMP terms are further defined as follows:

BTRC�𝑈𝑈 + 𝑇𝑇𝑇𝑇
(1 + 𝑑𝑑) −1
N
t=1
+ �𝑈𝑈 𝑎𝑎 + 𝑃𝑃 𝑎𝑎
(1 + 𝑑𝑑) −1
𝑁𝑁
=1
Packet Pg. 188 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Appendices 62
CTRC �𝑃𝑃 𝑡𝑡 + 𝑃𝑃 𝑡𝑡 + 𝑈𝑈 𝑡𝑡
(1 + 𝑑𝑑)
𝑡𝑡−1
N
t=1
LCRC �𝑃𝑃 𝑡𝑡 + 𝑃𝑃 𝑡𝑡− 𝑇𝑇𝑇𝑇𝑡𝑡
(1 + 𝑑𝑑)
𝑡𝑡−1
N
t=1
IMP = ∑ �
�∑ ∆𝐸𝐸 𝑖𝑖𝑖𝑖 𝑛𝑛
𝑖𝑖=1 � 𝑜𝑜𝑜𝑜 (∆)
(1 + d)t−1 � N
t=1 (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 Bpa = � 𝑼𝑼𝑼𝑼𝑼𝑼𝒕𝒕
(𝟏𝟏 + 𝒅𝒅)
𝒕𝒕−𝟏𝟏
N
t=1
+ � 𝑼𝑼𝑼𝑼𝑼𝑼𝒂𝒂
(𝟏𝟏 + 𝒅𝒅)
𝒕𝒕−𝟏𝟏
𝑵𝑵
𝒕𝒕=𝟏𝟏
Packet Pg. 189 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Appendices 63
Cpa = � 𝑃𝑃 𝑡𝑡 + 𝐼𝐼𝐼𝐼 𝑡𝑡 + 𝑈𝑈 𝑡𝑡
(1 + 𝑑𝑑)
𝑡𝑡−1
N
t=1
LCpc = � 𝑃𝑃 𝑡𝑡 + 𝐼𝐼𝐼𝐼 𝑡𝑡
(1 + 𝑑𝑑)
𝑡𝑡−1
N
t=1
[All 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:

Packet Pg. 190 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Appendices 64
Where:
d is the discount rate or cost of capital used to value future expenses in current year dollars (𝑦𝑦) 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
(𝑦𝑦) 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 measures 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:

Packet Pg. 191 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Appendices 65
𝑇𝑇~ ×
𝑃𝑃
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., ∑ (𝐸𝐸𝐵𝐵(𝑦𝑦) − 𝐸𝐸𝑋𝑋(𝑦𝑦))]. 𝑦𝑦=0 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.

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

Avoided costs
Participant Test Yes, include non-electric fuel savings. Retail rates Rate Impact Measure
Test
Non-electric fuel savings are
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
Avoided costs
Packet Pg. 192 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Appendices 66
non-electric fuels when calculating the
RIM test.

Total Resource Cost
Test
Yes, include non-electric fuel savings. Avoided costs
Societal Cost Test Yes, include non-electric fuel savings. Avoided costs Cost of conserved
energy (CCE)
Yes. Typically, when a measure saves
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.

Not applicable
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.

Packet Pg. 193 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Appendices 67

SUMMARY OF EQUATIONS AND GLOSSARY OF SYMBOLS
Basic Equations
Participant Test
NPVP = BP - CP
NPVavp = (BP-CP) / P BCRP
BP/CP
DPP = min j such that Bj > Cj
Ratepayer Impact Measure Test
LRIRIM = (CRIM - BRIM) / E
FRIRIM = (CRIM - BRIM) / E for t = 1
ARIRIMt = FRIRIM 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 = � 𝑩𝑩𝑩𝑩𝒕𝒕 + 𝑻𝑻 𝒕𝒕 + 𝑰𝑰 𝒕𝒕
(𝟏𝟏 + 𝒅𝒅)
𝒕𝒕−𝟏𝟏
N
t=1
+ � 𝒂𝒂 + 𝑷𝑷 𝒂𝒂
(𝟏𝟏 + 𝒅𝒅)
𝒕𝒕−𝟏𝟏
𝑵𝑵
𝒕𝒕=𝟏𝟏
Cp = � 𝑃𝑃 𝑡𝑡 + 𝐵𝐵 𝑡𝑡
(1 + 𝑑𝑑)
𝑡𝑡−1
N
t=1
Packet Pg. 194 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Appendices 68
Ratepayer Impact Measure Test BRIM = � 𝑼𝑼𝑼𝑼𝑼𝑼𝒕𝒕 + 𝑹𝑹𝒕𝒕 (𝟏𝟏 + 𝒅𝒅)𝒕𝒕−𝟏𝟏 N t=1
+� 𝑼𝑼𝑼𝑼𝑼𝑼
𝒂𝒂
(𝟏𝟏+𝒅𝒅)
𝒕𝒕−𝟏𝟏
𝑵𝑵
𝒕𝒕=𝟏𝟏
CRIM = �
𝑈𝑈
+𝑅𝑅+𝑃𝑃+ 𝐼𝐼𝐼𝐼
(1+𝑑𝑑)
−1
N
t=1
+�
𝑅𝑅
𝑎𝑎
(1+𝑑𝑑)
−1
𝑁𝑁=
1 E= �
𝐸𝐸
𝑡𝑡
(1+𝑑𝑑)
𝑡𝑡−1
N
t=1
Total Resource Cost Test BTRC = � 𝑈𝑈 𝑡𝑡 + 𝑇𝑇𝑇𝑇𝑡𝑡 (1 + 𝑑𝑑)𝑡𝑡−1 N t=1
+�
𝑈𝑈
𝑎𝑎
+𝑃𝑃
𝑎𝑎
(1+𝑑𝑑)
𝑡𝑡−1
𝑡𝑡=1
CTRC = �
𝑃𝑃
𝑡𝑡+
𝑃𝑃
𝑡𝑡
+𝑈𝑈
𝑡𝑡
(1+𝑑𝑑)
𝑡𝑡−1
N
t=1
LTRC = �
𝑃𝑃
𝑡𝑡+
𝑃𝑃
𝑡𝑡
− 𝑇𝑇𝑇𝑇
𝑡𝑡
(1+𝑑𝑑)
𝑡𝑡−1
N
t=1
IMP = �
��
∑
∆𝐸𝐸
𝑖𝑖
𝑛𝑛𝑖𝑖=
1 � 𝑜𝑜𝑜𝑜�∆𝐷𝐷
𝑖𝑖
𝑤𝑤ℎ𝑒𝑒𝑒𝑒𝐼𝐼=𝑝𝑝𝑝𝑝𝑝𝑝��
(1+𝑑𝑑)
𝑡𝑡−1
N
t=1
Program Administrator Cost Test Bpa= � 𝑈𝑈 𝑡𝑡 (1 + 𝑑𝑑)𝑡𝑡−1 N t=1
+�
𝑈𝑈
𝑎𝑎
(1+𝑑𝑑)
𝑡𝑡−1
𝑡𝑡=1
Cpa= �
𝑃𝑃
𝑡𝑡
+ 𝐼𝐼𝐼𝐼
𝑡𝑡
+𝑈𝑈
𝑡𝑡
(1+𝑑𝑑)
𝑡𝑡−1
N
t=1
LCPA =�
𝑃𝑃+ 𝐼𝐼𝐼𝐼
(1+𝑑𝑑)
−1
N
t=1
Packet Pg. 195 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Appendices 69

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 of the 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 if they 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 year j
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
∆Dgit Reduction in gross billing demand in costing period i in year t ∆Dnit 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
∆Egit Reduction in gross energy use in costing period i in year t ∆Enit 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 FRIRIM 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 ∆EGit or ∆DGit is positive (a reduction) in costing period i in year t, and zero otherwise
Packet Pg. 196 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Appendices 70
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
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10.4 APPENDIX D: IRP CUSTOMER SURVEY AND SURVEY RESULTS

CUSTOMER SURVEY
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:

Packet Pg. 198 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Appendices 72
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
☐ Up to 5% of my bill
☐ Up to 10% of my bill
☐ More than 10% of my bill
☐ I don’t want to pay extra
5) Do you have a preference on where REU builds or purchases future energy resources? ☐ 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 (energy from 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)
Packet Pg. 199 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Appendices 73
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)
_____________________________________________________________________ Additional comment(s)
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 www.reupower.com/irp and will also be shared at our next IRP Public Workshop scheduled in June 2018. If you have additional questions or concerns, feel free to e-mail [email protected].

Packet Pg. 200 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Appendices 74
Packet Pg. 201 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Appendices 75

10.5 APPENDIX E: DSM-IRP MEASURE RESULTS
Measure Name Units Unit Type PCT ($) RIM ($) CIT ($/Ton) EUL AC Pkg Unit-< 5 Tons (55kBtuh)-
15 SEER 10 Ton $3,817 ($4,072) ($497) 15
AC Split Unit-< 5 Tons (55
kBtuh)-15 SEER-ER 3 Ton $2,235 ($1,960) ($476) 15
AC Split Unit-< 5 Tons (55
kBtuh)-15 SEER-ROB 3 Ton $1,583 ($1,323) ($497) 15
Add Insulation R8 to R38 31 1000 Sq. Ft. ($17,717) ($28,915) ($445) 20 Ceiling insulation, increase to R38 40 1000 Sq. Ft. $399,870 ($66,456) ($66) 20 Ceiling insulation, R-11 addition 2 1000 Sq. Ft. $80 ($144) ($66) 20 Ceiling insulation, R-19 addition 37 1000 Sq. Ft. $3,731 ($3,889) ($69) 20 Ceiling insulation, R-30 addition 46 1000 Sq. Ft. ($1,991) ($6,106) ($69) 20 Commercial Custom Rebate -
HVAC FY19 1 Project ($523,101) ($6,380) ($497) 15
Commercial Lighting Rebate FY
20 - Exterior 1 Program $843,781 ($666,593) ($459) 10
Commercial Lighting Rebate
FY20 - Interior 1 Program $2,250,118 ($2,424,482) ($529) 11 Commercial Solar Storage 1 Building $1,339,951 ($1,339,696) ($516) 30 Commercial Solar Track storage 1 Building $3,406,437 ($3,028,188) ($475) 30 Commercial Solar Track 1 Building $3,624,294 ($3,028,188) ($475) 30 Commercial Solar 1 Building $1,364,442 ($1,191,314) ($511) 30 Ductless mini-split air
conditioner, 19 SEER (after
1/1/15)
12 Ton ($2,448) ($2,055) ($436) 15
Ductless mini-split heat pump,
15 SEER (after 1/1/15) 4 Ton $349 ($846) ($434) 15
Ductless mini-split heat pump,
16 SEER (after 1/1/15)-ER 15 Ton $5,560 ($6,377) ($409) 15 Ductless mini-split heat pump,
16 SEER (after 1/1/15)-ROB 46 Ton $4,350 ($10,876) ($434) 15 ENERGY STAR ceiling fan 2 Ceiling Fan $403 ($362) ($416) 10 ENERGY STAR HP water heater,
50 gal., located in
garage/basement
1 Water Heater $765 ($1,153) ($407) 10
ENERGY STAR HP water heater,
50 gal., space htg-elec 1 Water Heater $232 ($787) ($409) 10 ENERGY STAR HP water heater,
80 gal., located in
garage/basement
1 Water Heater $611 ($1,308) ($409) 10
ENERGY STAR HP water heater,
80 gal., space htg-elec 2 Water Heater ($327) ($1,544) ($409) 10 Energy Star LED Bulb A19 633 Bulb $21,520 ($15,928) ($429) 15 Packet Pg. 202 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Appendices 76
Energy Star LED Bulb B10 144 Bulb $3,227 ($2,489) ($429) 15 Energy Star LED Bulb BR30 125 Bulb $4,250 ($3,145) ($429) 15 Energy Star LED Bulb G25 106 Bulb $3,604 ($2,667) ($429) 15 Energy Star Refrigerator 40 Refrigerator $3,150 ($3,279) ($430) 14 Energy Star Refrigerator - CEE
Level II 3 Refrigerator $420 ($373) ($430) 14
Energy Star Refrigerator - CEE
Level III 1 Refrigerator $199 ($165) ($429) 14
ENERGY STAR room air
conditioner, 14,000 to 19,999
Btuh
1 Room A/C $56 ($75) ($411)9
Heat pump, 15 SEER, 8.4 HSPF
(after 1/1/15)-ER 21 Ton $8,600 ($8,175) ($409) 15
Heat pump, 15 SEER, 8.4 HSPF
(after 1/1/15)-ROB 93 Ton $14,428 ($19,655) ($434) 15
Heat pump, 16 SEER, 8.4 HSPF
(after 1/1/15)-ER 10 Ton $3,693 ($3,667) ($409) 15
Heat pump, 16 SEER, 8.4 HSPF
(after 1/1/15)-ROB 61 Ton $8,223 ($12,686) ($434) 15
Home Energy Reports Existing -
Multi-Family 1 Building $14 ($11) ($338)
1 Home Energy Reports Existing -
Single-Family 1 Building $20 ($16) ($343)
1 Home Energy Reports New
Construction - Multi-Family 1 Building $6 ($5) ($316)
1 Home Energy Reports New
Construction - Single-Family 1 Building $9 ($8) ($329)
1 HP Pkg Unit-< 5 Tons (55 kBtuh)-
15 SEER 8.5 HSPF 3 Ton $588 ($680) ($497) 15
HP Pkg Unit-5 Tons (55-64
kBtuh)-15 SEER 8.5 HSPF 5 Ton $1,171 ($944) ($497) 15
HP Split Unit-< 5 Tons (55
kBtuh)-15 SEER 9 HSPF 4 Ton $2,657 ($2,494) ($466) 15
Package System, 14.5 SEER, 12
EER or Greater 429 Ton $108,374 ($163,589) ($436) 15
Residential Solar rooftop 1 Building $19,457 ($28,277) ($475) 30 Residential Solar rooftop-
storage
1 Building $9,852 ($28,277) ($475) 30
Shade Trees FY20 947 Tree $100,894 ($108,765) ($447) 20 Smart Power Strip 30 Power Strip $2,343 ($3,282) ($380)5 Split-system air conditioner, 15
SEER, 12.5 EER (after 1/1/15)-
ROB
231 Ton ($7,153) ($19,411) ($436) 15
Split-system air conditioner, 15
SEER, 12.5 EER (after 1/1/15)-ER 68 Ton $7,116 ($12,132) ($407) 15 Split-system air conditioner, 16
SEER, 13 EER (after 1/1/15)-ROB 173 Ton ($6,378) ($15,783) ($436) 15 Split-system air conditioner, 16
SEER, 13 EER (after 1/1/15)-ER 78 Ton $7,826 ($14,608) ($408) 15 Split-system air conditioner, 17
SEER, 13 EER (after 1/1/15) 3 Ton ($206) ($295) ($436) 15 Packet Pg. 203 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Appendices 77
Split-system air conditioner, 18
SEER, 13 EER (after 1/1/15)-ROB 11 Ton ($420) ($1,312) ($436) 15 Split-system air conditioner, 18
SEER, 13 EER (after 1/1/15)-ER 14 Ton ($535) ($1,670) ($436) 15 Split-system air conditioner, 19
SEER, 14 EER (after 1/1/15) 3 Ton $438 ($743) ($414) 15 Variable speed residential pool
pump
28 Pump $25,305 ($27,753) ($395) 10
Whole house fan 14 Fan (2,000
cfm) $6,042 ($11,939) ($555) 20
Wi-Fi Enabled Thermostat 241 1000 Sq. Ft. $83,969 ($22,014) ($106) 11 Window Replacement Energy
Efficient Windows 1 1000 Sq. Ft. ($507) ($13,375) ($288) 20 ECM BLOWER MOTOR 7 Motor $246 ($1,743) ($213) 10
EFFICIENT FAN CONTROLLER 56 Fan
Controller $4,086 ($6,705) ($213) 10
FY20-Electrification - Installation
of Single Head Mini Split Heat
Pump
1 Program $32,349 $18,662 $66 20
Heat Pump Water Heater
replacing electric heater 7 HPWH $1,552 ($8,773) ($204) 10

HOT WATER FLOW RESTRICTOR

FAUCET RESTRICTOR ELECTRIC
WH (2)
23 Restrictor $2,816 ($1,581) ($204) 10

HOT WATER FLOW RESTRICTOR

HAND-HELD LOW FLOW
SHOWERHEAD ELECTRIC WH (2)
38 Restrictor $550 ($1,233) ($204) 10

HOT WATER FLOW RESTRICTOR

LOW FLOW SHOWERHEAD

ELECTRIC WH
9 Restrictor $226 ($292) ($204) 10
Installation of Single Head Mini
Split Heat Pump 7 Head $23,444 ($26,395) ($213) 20
LED A-Lamp, 13W 4,638 Bulb $58,240 ($63,232) ($212) 15
LED A-Lamp, 9W 44 Bulb $713 ($560) ($211) 16
LED NIGHT LIGHTS 1,301 Bulb $42,027 ($25,719) ($212) 15 LED Screw In BR 213 Bulb $3,089 ($2,614) ($212) 15
LED Screw In Candelabra 717 Bulb $6,477 ($6,354) ($212) 15 POWER STRIP, TIER 2
ADVANCED 7 Power Strip $155 ($384) ($191)
5 REFRIGERANT CHARGE W/COIL
CLEANING 5 TON 3 Cleaning $180 ($457) ($195)
5 REFRIGERANT CHARGE W/COIL
CLEANING, 3 TON 118 Cleaning ($6,364) ($10,783) ($195)
5 REFRIGERANT CHARGE W/COIL
CLEANING, 4 TON 23 Cleaning $82 ($2,802) ($195)
5 REFRIGERATOR REPLACEMENT
19 CUBIC FOOT AND BELOW (2) 31 Refrigerator ($12,776) ($4,472) ($215) 14

REFRIGERATOR REPLACEMENT
OVER 19 CUBIC FOOT (2) 34 Refrigerator ($21,425) ($4,770) ($215) 14 Residential Energy Discount 1 Program $0 ($85,758) $01
Packet Pg. 204 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Appendices 78

WATER HEATER BLANKET,
ELECTRIC WH 5 HPWH $1,321 ($821) ($211) 15
Wi-Fi Enabled SMART
THERMOSTAT 173 Thermostat ($41,574) ($12,077) ($214) 11 Window Replacement 3 1000 Sq. Ft. ($29,255) ($17,470) ($214) 20 All-Electric New Home 15 SEER
HP 3-tons
1 Home $11,656 $5,833 $153 20
All-Electric New Home 16 SEER
HP 3-tons
1 Home $11,225 $5,798 $152 20
All-Electric New Home 17 SEER
HP 3-tons
1 Home $11,202 $5,498 $142 20
All-Electric New Home 18 SEER
HP 3-tons
1 Home $11,068 $5,258 $133 20
Class IV Forklift 1 Forklift $43,829 $15,810 $145 10
Class V Forklift 1 Forklift $48,444 $17,556 $147 10
DHW Electrification to Baseline
Fuel Substitution - Gas to ER
Water Heater
1 Water Heater ($924) $3,473 $1,325 10
DHW Electrification to Baseline
Fuel Substitution - Gas to ER
Water Heater-MF
1 Water Heater ($737) $2,956 $1,325 10
DHW Full Electrification - Gas to
HP Water Heater 1 Water Heater $1,201 $1,537 $209 10
DHW Full Electrification - Gas to
HP Water Heater-MF 1 Water Heater $1,244 $1,120 $166 10 Ebike Bike Share per bike Light
Duty 1
E-Bike ($1,089) $62 $395
Ebike Business per bike Light
Duty 1
E-Bike ($1,355) $32 $295
Ebike Personal per bike Light
Duty 1
E-Bike ($1,817) $9 $285
Electric Airport Bag Tractor 1 Unit ($13,682) $36,136 $6,103 10 Electric Airport Belt Loader 1 Unit $16,897 $5,559 $116 10 Electric Airport Pushback
Tractor 1 Unit ($2,326) $24,638 $1,422 10
Electrification - Average Gas and
A/C to Packaged HP - Grocery 1 Ton $299 $706 $90 15
Electrification - Average Gas and
A/C to Packaged HP - Lodging -
Hotel
1 Ton $438 $470 $65 15
Electrification - Average Gas and
A/C to Packaged HP - Lodging -
Motel
1 Ton $866 $29 $6 15
Electrification - Average Gas and
A/C to Packaged HP - Office -
Large
1 Ton ($17) ($125) ($156) 15
Electrification - Average Gas and
A/C to Packaged HP - Office -
Small
1 Ton $112 ($9) ($6) 15
Electrification - Average Gas and
A/C to Packaged HP - Restaurant
- Fast-Food
1 Ton $728 $303 $57 15
Packet Pg. 205 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Appendices 79
Electrification - Average Gas and
A/C to Packaged HP - Restaurant
- Sit-Down
1 Ton $384 ($54) ($21) 15
Electrification - Average Gas and
A/C to Packaged HP - Retail -
Large
1 Ton $239 ($110) ($46) 15
Electrification - Average Gas and
A/C to Packaged HP - Retail -
Small
1 Ton $449 $118 $34 15
Electrification - Average Gas and
A/C to Packaged HP - Storage -
Conditioned
1 Ton $632 $578 $98 15
Gas Clothes Dryer to Electric
Resistance 1 Dryer ($895) $884 $4,175 16
Gas Clothes Dryer to Electric
Resistance-MF 1 Dryer ($895) $884 $4,175 16
Gas Clothes Dryer to HP Dryer 1 Dryer ($100) $474 $839 12 Gas Clothes Dryer to HP Dryer-
MF 1 Dryer ($100) $474 $839 12
Gas to Electric Resistance Oven 1 Oven $31 $127 $409 20 Gas to Electric Resistance Oven-
MF 1 Oven $18 $76 $409 20
Gas to Electric Resistance Stove 1 Stove $42 $381 $478 20 Gas to Electric Resistance Stove-
MF 1 Stove $25 $229 $478 20
HP DHW Grocery 1 Water Heater ($1,777) $8,107 $190 10
HP DHW Hotel 1 Water Heater ($3,632) $13,208 $208 10
HP DHW Motel 1 Water Heater ($1,489) $6,180 $191 10
HP DHW Office Large 1 Water Heater ($1,602) $4,894 $206 10 HP DHW Office Small 1 Water Heater $342 $1,466 $166 10
HP DHW Retail Single Story
Large 1 Water Heater ($527) $3,472 $164 10
HP DHW Retail Small 1 Water Heater $319 $1,530 $171 10
HP Electrification to Baseline HP
Fuel Substitution - Gas & A/C to
15 SEER/8.7 HSPF HP
3 Ton $3,196 $2,547 $176 15
HP Electrification to Baseline HP
Fuel Substitution - Gas & A/C to
15 SEER/8.7 HSPF HP-MF
2 Ton $1,554 $1,428 $193 15
HP Full Electrification - Gas &
A/C to 16 SEER 9.0 HSPF HP 3 Ton $3,320 $2,147 $139 15
HP Full Electrification - Gas &
A/C to 16 SEER 9.0 HSPF HP-MF 2 Ton $1,513 $1,296 $168 15 HP Full Electrification - Gas &
A/C to 17 SEER 9.4 HSPF HP 3 Ton $3,423 $1,760 $108 15
HP Full Electrification - Gas &
A/C to 17 SEER 9.4 HSPF HP-MF 2 Ton $1,476 $1,161 $144 15 HP Full Electrification - Gas &
A/C to 18 SEER 9.7 HSPF HP 3 Ton $3,410 $1,439 $84 15
Packet Pg. 206 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Appendices 80
HP Full Electrification - Gas &
A/C to 18 SEER 9.7 HSPF HP-MF 2 Ton $1,389 $1,054 $127 15 Large Light Duty Vehicle-PHEV 1 Vehicle $6,895 $3,573 $168 12 Large Light Duty Vehicle-PHEV-
COM 1 Vehicle $1,426 $4,076 $191 12
Light Duty Truck-BEV 1 Vehicle ($25,999) $5,060 $138 12 Light Duty Truck-BEV-COM 1 Vehicle ($35,711) $5,772 $158 12 Medium Light Duty Vehicle-BEV 1 Vehicle ($1,046) $3,869 $115 12 Medium Light Duty Vehicle-BEV-
COM 1 Vehicle ($6,840) $4,413 $131 12
Medium Light Duty Vehicle-
PHEV 1 Vehicle $2,134 $2,711 $152 12
Medium Light Duty Vehicle-
PHEV-COM 1 Vehicle ($2,819) $3,093 $173 12
Small Light Duty Vehicle-BEV 1 Vehicle $9,106 $3,130 $122 12 Small Light Duty Vehicle-BEV-
COM 1 Vehicle $1,029 $3,570 $139 12
Small Light Duty Vehicle-PHEV 1 Vehicle $2,547 $2,056 $146 12 Small Light Duty Vehicle-PHEV-
COM 1 Vehicle ($1,464) $2,345 $167 12
LED Street Light Replacement 1 Program ($205,071) $91,637 $183 10 Packet Pg. 207 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Appendices 81

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.

Figure 10-1 2021 Energy Efficiency Goals vs. Estimated Net Energy Savings 0 200
400
600
800
1,000
1,200
1,400
1,600
2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
MWH
Fiscal Year (FY)
2021 Energy Effiency Goals vs. Estimated Net Energy Savings Energy Efficiency Building Electrification Council Approved Goals (2021) Packet Pg. 208 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan

CITY OF REDDING

REPORT TO THE CITY COUNCIL
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 projection 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 MEETING DATE: March 2, 2021
ITEM NO. 4.5(a)
FROM:
***APPROVED BY***
[email protected] [email protected]
SUBJECT: 4.5(a)--Authorization to submit Redding Electric Utility's Energy Efficiency Potential Forecast Study.

Daniel Beans, Director of
Electric Utility
Packet Pg. 209 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan 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. 210 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan 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. 211 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan 1850 Parkway Place  Suite 800  Marietta, GA 30067  770-425-8100  Fax 866-611-3791  www.gdsassociates.com Georgia  Texas  Alabama  New Hampshire  Wisconsin  Florida  Maine  Washington  California

MEMORANDUM
TO Redding Electric Utility
FROM GDS Associates, Inc.

DATE February 5, 2021
RE 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.

SUMMARY OF POTENTIAL
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 BY SECTOR (MWH) AND PERCENT OF SALES

0.00%

0.05%

0.10%

0.15%

0.20%
0 200
400
600
800
1,000
1,200
1,400
1,600
2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
% of Annual GWh Sales
MWh
Res Incremental Market Potential Non-Res Incremental Market Potential Total Incremental Potential as a % of Total Sales
Attachment A
Packet Pg. 212 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan

MEMORANDUM
2020 CMUA Energy Efficiency Potential Forecasting Study CONFIDENTIAL 2
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 of forecasted sector-level and total sales. Incremental annual savings range from 388 MWh to 1,358 MWh, which corresponds to 0.05% to 0.19% of forecasting sales.

TABLE 1 NET INCREMENTAL MARKET POTENTIAL BY SECTOR – ENERGY AND DEMAND 10 Year Energy Goals (Incremental Net MWh)
ALL Sectors (MWh) 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Total Market Potential 1,358 1,305 1,233 1,115 992 755 581 525 439 388 Res Market Potential 59 65 70 72 73 73 73 74 42 38
Non-Res Market
Potential 1,298 1,240 1,164 1,043 919 681 508 451 397 350 Total Potential as a %
of Total Sales 0.19% 0.18% 0.17% 0.16% 0.14% 0.11% 0.08% 0.07% 0.06% 0.05% Res Potential as a % of
Res Sales 0.02% 0.02% 0.02% 0.02% 0.02% 0.02% 0.02% 0.02% 0.01% 0.01% Non-Res Potential as a
% of Non-Res Sales 0.36% 0.34% 0.32% 0.29% 0.25% 0.19% 0.14% 0.12% 0.11% 0.10% 10 Year Demand Goals (Incremental kW)
ALL Sectors (kW) 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Total Market Potential 205 194 180 161 142 110 87 77 66 58 Res Market Potential 1 1 1 1 1 1 1 1 1 1
Non-Res Market
Potential 204 193 179 160 142 110 86 77 66 58
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)
Detailed Results
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
Packet Pg. 213 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Memo
1 From
To
Title
Current Date
Long-Term Resources
Energy Risk Committee
Recommendation to Approve Energy Efficiency Potential Forecast Results 2/16/2021
Summary
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. Redding submitted the required forecasts in March 2013 and March 2017, and the updated forecast is due in March 2021. 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. These targets were incorporated into Redding’s 2019 Integrated Resource Plan (IRP) which was approved by Redding City Council and the California Energy Commission.

The results of the 2021 potential forecast show a significant reduction in cost-effective energy efficiency potential between 2017 and 2021. These changes can be attributed to the following:
• 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 result, 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 commercial lighting program at a rate that exceeds the potential identified in 2017. This reduces the 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. This savings occurs absent any utility programs.

Due to these changes, the results of the 2021 forecast indicate that Redding’s potential for cost-effective energy efficiency programs is approximately ⅓ of the potential identified in the 2017 Forecast. A comparison of the goals approved by the City Council in the 2019 IRP vs the updated potential study is shown in Figure 1. The consultant report that will be submitted to the CEC is attached in Appendix A.

Packet Pg. 214 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Memo
2 Figure 1: Comparison of Current Coals to Updated Market Potential Staff recommends seeking approval of the City Council to submit the updated potential study to the CEC and adjusting Redding’s energy efficiency goals to match the updated study.

Background
The Clean Energy and Pollution Reduction Act of 2015 (SB 350) established new clean energy, clean air, and greenhouse gas reduction goals. To support the state’s goal of doubling energy efficiency savings in electricity and natural gas end uses by 2030, existing mandates were expanded to support SB 350 in the following ways:
• According to Public Utilities Code §9505, by March 15, 2013, and by March 15th every fourth year thereafter, Publicly Owned Utilities (POUs) shall identify all potentially achievable cost-effective electricity efficiency savings and shall establish annual targets for energy efficiency savings and demand reduction for the next 10-year period. This is reported through the Energy Efficiency Potential Forecast (Forecast) study and is traditionally submitted with the POU’s Annual Energy Efficiency Report.
• The California Energy Commission was directed to establish statewide targets to support the state’s goal to double energy efficiency savings by 2030. Furthermore, the results of the Forecast were used as the basis for targets established by the CEC for each POU. • POUs1 are required to submit an IRP that sets forth a plan to achieve the energy efficiency goals in SB 350 and must be approved by their respective boards by January 1, 2019, and submitted to the CEC by April 30, 2019. This was approved by Redding City Council (Council) in November 2018.

The 2017 Forecast results served as the basis for the CEC’s POU annual energy efficiency savings target. Council then approved to set Redding’s energy efficiency goals 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. 0 500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
MWh
Approved Goals and 2021 Market Potential
Goals approved by Council 2018 Market Potential 2021
Packet Pg. 215 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Memo
3 Figure 2: Comparison of CEC EE Targets to Redding EE Goals submitted in IRP In coordination with the other California POUs, REU has been working closely with GDS Associates (GDS) to develop the 2021 Forecast that more accurately reflects characteristics specific to Redding’s territory and conditions. The final Forecast was submitted to REU in February 2021 and is included as Attachment A to this document.

Evaluation Methodology
REU’s approach to evaluating energy efficiency and renewable energy programs has changed since the 2017 Forecast. Stakeholder feedback in the IRP Process was used to inform the potential study. To summarize, customer feedback received during the IRP process indicated the following:
a) Redding customers want to keep their energy bills as low as possible by paying for the least expensive energy available so long as it maintains reliability.
b) While customers understand the importance of meeting California environmental mandates, they do not necessarily want to exceed them.
c) Customers generally do not want to pay more for renewable, carbon-free electricity that exceeds state mandates.

Those results were incorporated into the final IRP report approved by Council in November 2018 and the CEC in 2019. Since its approval, REU has continued to use IRP as a guide for evaluating programs.

In addition to the IRP, the NEM 2.0 study also prompted REU to consider how the costs of a program can affect both participating and non-participating customers. Council established a Solar Committee to recommend the highest defensible credit rate that met the following objectives:
a) Legally defensible
b) Fair for non-solar customers
0 500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 MWh
CEC Targets and Approved Goals
Goals approved by Council 2018 CEC Target
Packet Pg. 216 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Memo
4 c) A reasonable 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 legally defensible. In December 2019, the Council 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 all 8,760 hours of the year for 20 years. On an annual average, the results of this study reasonably match the avoided cost rate from the NEM 2.0 study.

Potential Forecast Development
The Forecast model was developed by GDS with input from REU’s Resources team. Results were developed based on Redding’s service area, customer base, climate zone, economic conditions, and other factors during the development of the Forecast. GDS also reviewed Redding’s current program offerings and evaluated them at a measure level.

Forecast Assumptions
The model considers the market saturation and increasingly stringent building codes that continue to add energy efficiency measures as the baseline, reducing the amount of incremental energy savings Redding may claim in the Annual Energy Efficiency reports. GDS and Resources worked closely to refine the appropriate criteria for the 2021 Forecast that would be practical and achievable. Resources used Redding’s IRP and NEM

2.0 study as the guiding principle to develop the Forecast, including:
• Keeping the cost of energy as low as possible while maintaining reliability • Meet the minimum requirements of California environmental 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 included in the 10-year forecast. The analysis excluded measures and programs that are planned to be discontinued by the start of the forecast period in 2022, and measures that do not meet a Total 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 nearly all 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 goals.

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 original NEM 2.0 study rate, which incorporated the following costs components:
• Transmission
• Losses
• Renewable Attributes
• Energy
Redding’s avoided cost was evaluated based on the costs of energy, RPS obligation transmission, and distribution losses, and capacity. As a result, Redding’s avoided costs are 55% lower than the current version Packet Pg. 217 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Memo
5 of the stipulated avoided cost. Using the updated avoided costs yields results that are more applicable to the City of Redding.

Forecast Results
Once the model assumptions were developed, Resources evaluated the results provided by GDS.

The results of the 2021 Forecast indicate that Redding’s energy efficiency potential has decreased by 65% from the 2017 potential study. As seen in Table 1, Redding’s 2021 market potential is consistently lower than the 2017 results from 2022-20272, with an overall reduction of 13,000 MWh during that period.

Table 1: Goal Comparison
Year
2017
Market
Potential
2021
Market
Potential
Difference CEC
Targets New Goals Difference
2022 3,629 1,358 (2,271) 4,000 1,000 (3,000)
2023 3,439 1,305 (2,133) 3,000 1,000 (2,000)
2024 3,438 1,233 (2,205) 3,000 1,000 (2,000)
2025 3,352 1,115 (2,237) 3,000 1,000 (2,000)
2026 3,234 992 (2,242) 3,000 1,000 (2,000)
2027 2,695 755 (1,940) 3,000 1,000 (2,000)
Total 19,787 6,758 (13,029) 19,000 6,000 (13,000)
Figure 3 shows the current goals and the proposed goals based on the results of the potential study. The original goals are much higher because they were not based on Redding’s own avoided costs and misrepresented the amount of cost-effective energy savings in Redding. Tailoring the goals will provide Redding flexibility to develop and administer programs that meet the objectives set out in the IRP. It should be noted that the updated goals do not achieve the SB 350 Targets that were assigned to Redding by the California Energy Commission.

However, by statute, Redding is required to commit to cost-effective energy efficiency, and the recommended goals more accurately quantify the cost-effective potential than do the SB 350 Targets.

Figure 3: Comparison of Current Coals to Recommended Goals

2 The period of time in which both Forecasts overlap.
0 500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
MWh
Current Goals and Recommended Goals
Goals approved by Council 2018 Recommended Goals
Packet Pg. 218 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Memo
6 Conclusion and Next Steps
The Resources team recommends the City approve the potential forecast results and the recommended energy savings goals that will be submitted to the CEC. Once approved, REU staff will:
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 Plan (DSM-IRP) 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.

Packet Pg. 219 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Table of Contents i
©Black & Veatch Holding Company 2018. All rights reserved. 2019 | INTEGRATED RESOURCE PLAN
City of Redding
REU | POWERING A STRONG COMMUNITY

COOPERATIVELY PREPARED WITH
Packet Pg. 220 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Table of Contents 1-ii
Table of Contents
Acronyms, Abbreviations, and Definitions List....................................................................................AL-1 IRP Project 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 Packet Pg. 221 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Table of Contents 1-iii

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

LIST OF TABLES
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, Scenario H.............................................................................................................................................1-14 Table 2-1 Estimated 2030 GHG Emissions by Sector (MMTCO2e)....................................................... 2-5 Table 2-2 POU Share (in 1,000 MTCO2e) 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 Packet Pg. 222 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Table of Contents 1-iv
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$)............................................6-11 Table 6-5 2020 Cost Assumptions for Wind Systems (Nominal$).....................................................6-11 Table 6-6 2030 Cost Assumptions for Solar SAT Systems (Nominal$)............................................6-12 Table 6-7 2030 Cost Assumptions for Wind Systems (Nominal$).....................................................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

LIST OF FIGURES
Figure 1-1 IRP Objectives........................................................................................................................................ 1-2 Figure 1-2 GHG Emissions in the Preferred Plan, Scenario H................................................................1-10 Figure 1-3 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 Figure 3-3 Transmission ......................................................................................................................................... 3-8 Packet Pg. 223 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Table of Contents 1-v
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 Figure 7-2 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, Scenario H.............................................................................................................................................8-14 Figure 8-4 GHG Emissions in the Preferred Expansion Plan, Scenario H .........................................8-15 Figure 8-5 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 Packet Pg. 224 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Acronyms, Abbreviations, and Definitions List AL-1
Acronyms, Abbreviations, and Definitions List
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 Independent System Operator
CalEPA California Environmental Protection Agency
California ISO California Independent 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
CO2 Carbon Dioxide
CO2e Carbon Dioxide Equivalent
COD
Combined Cycle
Commercial Operation Date
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
Packet Pg. 225 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Acronyms, Abbreviations, and Definitions List AL-2
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) Packet Pg. 226 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Acronyms, Abbreviations, and Definitions List AL-3
MMT Millions of metric 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 Bill 350 (De León, 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 Packet Pg. 227 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Acronyms, Abbreviations, and Definitions List AL-4
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
Packet Pg. 228 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan IRP Project Partners PP-1
IRP Project Partners
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
Packet Pg. 229 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Executive Summary 1-1

1.0 Executive Summary
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 Bill 350; 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 report1
 POUs2 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 April 30, 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 Bill 350 Integrated 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.
2 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.

Packet Pg. 230 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Executive Summary 1-2
The 2019 IRP was developed through extensive analysis and benefited from coordination among internal and external partners 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.

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, 2nd Edition, p. 4.
• Comply with changing
California regulations
• Meet the mandates of
SB 350
•Limit future cost increases
•Keeping prices as low and
affordable as reasonably
possible
•Limit risks
• Provide reliable power
• Minimize outages &
service interruptions
• Diverse portfolio with
variety of renewable
resources
•Community values
•Exceptional service
•Balance costs and benefits
COR's
Vision
System
Reliability
Regulatory
Compliance
Managing
Costs
IRP
Packet Pg. 231 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Executive Summary 1-3
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 of the 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

ITEM SELECTED TEXT FROM THE CEC GUIDELINES LOCATION
IN IRP
A. Planning
Horizon and
Objective of
Expansion Plan
“adopt an IRP that ensures the utility achieves the specific goals and targets by 2030, including…greenhouse gas emissions reductions of 40 percent below 1990 levels, and…at least 50 percent of eligible 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”
Section 8
B. Scenarios
and Sensitivity
Analysis
“IRP Filings….must meet the requirements of PUC Section 9621. POUs are encouraged to also evaluate other scenarios and sensitivity analyses to consider the feasibility and cost-effectiveness (and rate impacts) of alternative resource options.”
Section 8
C. Standardized
Tables
“POUs must submit the following four Standardized Tables…  Capacity Resource Accounting Table (CRAT)
 Energy Balance Table (EBT)
 RPS Procurement Table (RPT)
 GHG Emissions Accounting Table (GEAT)”
Appendix A
D. Supporting
Information
“(1) analyses, studies, data, and work papers, or other material that the POU used or relied upon (including inputs and assumptions) in creating the IRP… and (2) additional information required by these guidelines.

Supporting Information supplements the data submitted in the Standardized Tables.”
Section 4,
5, 6; all
Appendices
Packet Pg. 232 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Executive Summary 1-4

ITEM SELECTED TEXT FROM THE CEC GUIDELINES LOCATION
IN IRP
E. Demand
Forecast
“1. Reporting Requirements…annual forecasted peak demand (MW) in the CRAT and annual forecasted retail sales, other loads, and net energy 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.”
Section 4,
Appendix A
F. Resource
Procurement
Plan
“…the mix of resources… in the IRP [as]…reported on the CRAT, EBT, and GEAT, and RPS procurement must also be reported on the RPT [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”
Section 4,
5, 8,
Appendix A
G. System and
Local Reliability
“Filing POUs [must] adopt an IRP to… meets the goal of ensuring system 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…” Section 4
H. Greenhouse
Gas Emissions
“POUs must report in the GEAT estimated emissions intensities (in metric tons of carbon dioxide equivalent [CO2e] per megawatt hour…for each supply resource reported in the EBT.”
Section 8,
Appendix A
I. Retail Rates “…the IRP Filing must include, as Supporting Information, a report or 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.” Section 8
J. T&D Systems “…adopt and IRP [that] achieves the goal of strengthening the diversity, sustainability, and resilience of the bulk transmission and distribution systems, and local communities.”
Section 3
K. Localized Air
Pollutants and
Disadvantaged
Communities
“…adopt IRPs to…[achieve] the goal of minimizing localized air pollutants and other GHG emissions, with early priority on disadvantaged communities…[discuss] how current programs and policies in place…address local air pollution…[and] how programs assist and prioritize disadvantaged communities.”
Section 8
Summarized from Chapter 2 of Vidaver David, Melissa Jones, Paul Deaver, and Robert Kennedy. 2018. Publicly Owned Utility Integrated Resource Plan Submission and Review Guidelines.

California Energy Commission. Publication Number: CEC-200-2018-004.

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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 of meeting 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.

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Table 1-2 Projects Considered in the IRP Scenarios (All Capacities are the Maximum Rated and Not Firm Capacities)
PROJECT 1 PROJECT 2 PROJECT 3 PROJECT 4 PROJECT 5 PROJECT 6 PROJECT 7 Name Local PV
w/Batt
NorCal/OR
PV
AZ PV CV PV 1 CV PV 2 NorCal/ OR
Wind
AZ Wind
Location Local OR/NorCal Arizona Central
Valley
Central
Valley
OR/ NorCal Arizona
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
Factor (%)

27.9% 27.0% 33.1% 30.6% 29.8% 30.0% 30.0%
Annual Energy
(MWh)
24,440 236,520 289,956 53,611 261,048 262,800 525,600
Annual
Degradation (%)

0.70% 0.70% 0.70% 0.70% 0.70% 0.00% 0.00%
Energy Storage?
(Yes/No/Maybe)
Yes Not
included
Not
included
Not
included
Not
included
Not
included
Not
included
ES Capacity (MW) 2.50 Not
included
Not
included
Not
included
Not
included
Not
included
Not
included
ES Duration (Hrs) 4 Not
included
Not
included
Not
included
Not
included
Not
included
Not
included
Transmission
Requirements
None To COTP,
WAPA
To CAISO,
WAPA
NP26,
WAPA
To CAISO,
WAPA
To COTP,
WAPA
To CAISO,
WAPA
LMP Market
Location (To
Value)
NP15 NP15 Palo Verde ZP26 SP15 NP15 Palo Verde
Transmission
Access Charge
(TAC) Costs
(2018-$/kW/mo)
$0.000 $2.258 $3.137 $0.000 $0.000 $2.258 $3.137
Transmission
Costs (2018-
$/MWh)
$0.000 $0.000 $11.221 $11.221 $11.221 $0.000 $11.221
Transmission
Escalation Rate
(%)

5.00% 4.00% 4.00% 4.00% 5.00% 4.00%
There are two methods of accounting for transmission costs: volumetric charges ($/MWh) used by California Independent System Operator, and demand ($/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.

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Table 1-3 Projects in the Scenarios Modeled (All Capacities are the Maximum Rated and Not Firm Capacities)

SCENARIO
NAME
PROJECT 1:

PV
PROJECT 2:

PV
PROJECT 3:

PV
PROJECT 4:

PV
PROJECT 5:

PV
PROJECT 6:

WIND
PROJECT 7:

WIND
A) Base Case MW: 10
Start: 2021
MWh/yr:
24,440
LCOE: $58
B) Balanced
Mix
MW: 10
Start: 2021
MWh/yr:
24,440
LCOE: $58
MW: 30
Start: 2028
MWh/yr:
86,987
LCOE: $57
MW: 20
Start: 2026
MWh/yr:
53,611
LCOE: $71
MW: 70
Start: 2032
MWh/yr:
183,960
LCOE: $76
C) Balanced
Mix-Alternate
MW: 10
Start: 2021
MWh/yr:
24,440
LCOE: $58
MW: 30
Start: 2029
MWh/yr:
70,956
LCOE: $73
MW: 25
Start: 2026
MWh/yr:
65,262
LCOE: $68
MW: 70
Start: 2032
MWh/yr:
183,960
LCOE: $72
D) Heavy
Wind
MW: 10
Start: 2021
MWh/yr:
24,440
LCOE: $58
MW: 85
Start: 2026
MWh/yr:
223,380
LCOE: $68
E) Heavy
Wind –
Alternate
MW: 10
Start: 2021
MWh/yr:
24,440
LCOE: $58
MW: 85
Start: 2026
MWh/yr:
223,380
LCOE: $72
F) Heavy
Solar
MW: 10
Start: 2021
MWh/yr:
24,440
LCOE: $58
MW: 90
Start: 2026
MWh/yr:
212,868
LCOE: $70
G) Existing
System
H) Optimized
Balanced Mix
MW: 10
Start: 2021
MWh/yr:
24,440
LCOE: $58
MW: 60
Start: 2026
MWh/yr:
156,629
LCOE: $68
MW: 65
Start: 2034
MWh/yr:
170,820
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
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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 meeting 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.

1.1.1 Recommendation
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.

1.1.2 Merits of Scenario H
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:

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 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 MW), 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 of the 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 MTCO2e in 2030. This level of emissions is well below the high target of 101,000 MTCO2e in the CARB staff recommendations for COR (although it is above the 57,000 MTCO2e set as the lower end of the targeted range). In subsequent years, the MTCO2e in Scenario H falls below the 2030 level and ends with 73,713 MTCO2e 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 of the 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 MTCO2e recommended by the CARB staff for COR in 2030 (101,000 MTCO2e) and meets the RE targets as is seen in Table 1-6 below. By relying on annual RECs and Packet Pg. 238 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Executive Summary 1-10
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.

Figure 1-2 GHG Emissions in the Preferred Plan, Scenario H Figure 1-3 Renewable Outlook
0 20,000
40,000
60,000
80,000
100,000
120,000
140,000
2022 2023 2024 2025 2026 2027 2028 2029 2030
Emissions (MMTCO2e)
Year

REDDING POWER

GREENHOUSE GAS OUTLOOK

SCENARIO H
Total Emissions Goal
0%
10%
20%
30%
40%
50%
60%
2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 RPS Requirement (%)
Year

RENEWABLE OUTLOOK
Requirement Preferred Plan Base Case
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1.1.3 Analyses of Alternative Scenarios
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.

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Table 1-4 Heat Map Diagram of Scenario CPWC and RE Results CPWC Summary 2030
Renew- Intermediate Avg. RE Achieving RE Balance
CPWC
CPWC
% able, % of Milestones 2018-2030 RE from RE from RE from Description ($1,000) Higher Retail Sales for RE Met? Wind Solar Hydro Base Case Base Case (with local solar only) 583,833 3.3% 32.8% No 32.8% 71% 11% 18% Scenario A Balanced Mix of Wind/Solar 575,766 1.9% 51.8% Yes 38.5% 59% 30% 11% Scenario B Bal. Mix of Wind/Solar – Alt. Projects 602,421 6.6% 51.3% Yes 37.9% 60% 29% 11% Scenario C Wind Heavy 642,176 13.7% 64.9% Yes 45.4% 84% 6% 10% Scenario D Wind Heavy - Alternate Projects 564,925 0.0% 64.9% Yes 45.5% 84% 6% 10% Scenario E Solar Heavy 601,558 6.5% 61.3% Yes 44.2% 42% 47% 11% Scenario F Early Wind Balanced Mix 566,191 0.2% 59.3% Yes 41.1% 81% 8% 11% Scenario G Existing System without Local Solar 601,957 6.6% 29.6% No 30.4% 81% 0% 19% Scenario H Optimized Balanced Mix 580,966 2.8% 53.9% Yes 41.2% 53% 36% 11% *Optimal results are shown in green, unfavorable results in red ** Intermediate Milestones are: 33% by 2020; 40% by 2024; 45% by 2027; 50% by 2030. ***Intermediate Milestones are considered met with the use of banked renewable energy credits Packet Pg. 241 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Executive Summary
1-13
Table 1-5 Detailed CPWC Results for the Preferred Plan, Scenario H Packet Pg. 242 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Executive Summary
1-14
Table 1-6 Renewable Energy and REC Adequacy in the Preferred Plan, Scenario H Packet Pg. 243 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Purpose and Background 2-16

2.0 Purpose and Background
This section provides an overview of the IRP process—a summary of relevant regulatory policies that guide development of the 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 resourceoptionsthat, 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 of various Scenarios.

EightScenariosare developedand compared in an IRP analysis to determine the best long-range plan for the utility. Supply-sideoptions typically include the evaluation of conventional resources, RE resources, and distributed energy resources; however, in the IRP, only RE resources were evaluated based on the REtargets and sufficiency of existing thermal (natural gas-fired) generation.

Demand-side options, such as those shown in

DEMAND SUPPLY
Customer Usage | METER
Energy Efficiency | LED
Customer Generation | SOLAR
New Load | ELECTRIC VEHICLES
Existing Resource | REDDING PWR
Renewable Energy | BIG HORN
Energy Storage | LARGE BATTERY
Carbon-Free | LARGE HYDRO
DEMAND
Packet Pg. 244 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Purpose and Background 2-1
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.

Packet Pg. 245 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Purpose and Background 2-1
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.

Figure 2-2 COR’s Integrated Resource Planning Process
Step 1
•ESTABLISH GOALS AND OBJECTIVES
•Identify the aim of the IRP to balance economics/rates, reliable and flexible supply, regulatory compliance, environmental considerations, and stakeholder involvement.

PW #1
•INVOLVE REU CUSTOMERS AND STAKEHOLDERS IN IRP PROCESS AT ONSET •Seek individuals and groups who have an interest in the future resource plan (Stakeholders) and welcome their participation. Conduct Public Workshop #1.

Step 3
• IDENTIFY PROCESSES, CONSTRAINTS, ASSUMPTIONS
•Develop IRP process that meets required IRP schedule and contents •Identify detailed regulatory and other requirements (GHG, RPS, reliability targets, etc.) •Identify stakeholder involvement process and evaluate objectives/concerns •Identify input assumptions needed for detailed modeling; develop inputs Step 4
•IDENTIFY RESOURCE NEEDS
•Determine the load forecast and need for incremental resources •Consider requirements / constraints applicable to incremental resources (GHG, renewables, contribution to reliability and stability)
Step 5
•IDENTIFY RESOURCE OPTIONS AND PORTFOLIOS
•Identify resource options to be evaluated and develop cost / performance characteristics
•Consider combinations of resource options (portfolios) to be evaluated Step 6
•PERFORM ANALYSIS OF OPTIONS, IDENTIFY PREFERRED PLAN
•Analyze resource portfolios (screening, detailed quantitative, or qualitative evaluation) •Perform sensitivity analyses to assess performance under range of potential market and industry conditions.

PW #2
•KEEP STAKEHOLDERS INVOLVED THROUGHOUT IRP PROCESS
•As part of the Stakeholder process, a Stakeholder Feedback Form was provided to all participants. Conduct Public Workshop #2
Step 8
•PREPARE IRP DOCUMENT, SECURE INTERNAL APPROVALS, SUBMIT •Develop the IRP document, get feedback from internal and external sources, secure approval from Council and submit in accordance with regulatory requirements Packet Pg. 246 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Purpose and Background 2-2

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.

Packet Pg. 247 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Purpose and Background 2-3
Figure 2-3 Timeline of Key State Legislative Actions Impacting IRP Planning SB1037 and AB2021
Energy Efficiency
Standards
SB350 Clean Energy
& Pollution
Reduction Act
AB2021 REU 10-yr
Forecast
Requirement Filed
AB32 GHG Global
Warming Solutions
Act
CARB Cap and Trade
implemented
CARB Cap and Trade
amendments
SB1368 GHG
Emissions
Performance
Standards
SB32 40% reduction
in GHG by 2030
SB1078 Renewable
Energy Portfolio
Standard, 2002
SBX1-2 California
Renewable Energy
Resources Act, 2011
SB1 California Solar
Initiative
SB338 Clean peak
energy standard
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
State Legislation Timeline
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2.3.1 SB 350 and PUC 9621
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 April 30, 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 1990 levels 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 (MMTCO2e) 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 MMTCO2e. 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 Bill 350 Integrated Resource Planning Electricity Sector Greenhouse Gas Planning Targets, July 2018.
5 PUC Division 1, Part 1, Chapter 2.3, Article 16, 399.11-399.32, the interim requirements are listed in 399.15(b.2.B) and 339.30 (c, 2).

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Table 2-1 Estimated 2030 GHG Emissions by Sector (MMTCO2e) 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 MTCO2e 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 MTCO2e) of 2030 GHG Emissions Projected by CARB POU
2030 ELECTRIC

SECTOR EMISSIONS
(%)
LOW 2030 TARGET
(MTCO2e*)
HIGH 2030 TARGET
(MTCO2e*)
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
City of Anaheim 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
SECTOR 1990 2030 SCOPING PLAN
RANGES(MMTCO2e)
% CHANGE FROM
1990 (%)
Electric Power 108 30-53 -72 to -51
Agriculture 26 24-25 -8 to -4
Residential and
Commercial
44 38-40 -14 to -9
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
Lands Net Sink
-7 TBD TBD
Subtotal 431 294-339 -32 to -21
Cap-and-Trade
Program
n/a 34-79 n/a
Total 431 260 -40
CARB, Staff Report: SB 350 Integrated Resource Planning Electricity Sector Greenhouse Gas Planning Targets, July 2018, p. 23.

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POU
2030 ELECTRIC

SECTOR EMISSIONS
(%)
LOW 2030 TARGET
(MTCO2e*)
HIGH 2030 TARGET
(MTCO2e*)
City of Vernon 0.497 149,000 263,000
City of Glendale 0.396 119,000 210,000
Imperial Irrigation
District

1.745 524,000 925,000
L.A. Dept. of Water &
Power

8.851 2,655,000 4,691,000
Modesto Irrigation
District

1.055 317,000 559,000
City of Roseville 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
District

0.629 189,000 333,000
*Low target based on 30 MMTCO2e for the sector; high target based on 53 MMTCO2e for the sector. Emission targets for each utility are rounded to the nearest 1,000 MTCO2e.

CARB, Staff Report: Senate Bill 350 Integrated Resource Planning Electricity Sector Greenhouse Gas Planning Targets, July 2018, p. 30.

2.3.1.1 CEC IRP Guidelines
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 of the 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.

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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 of the 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 of the 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 2-3 lists 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.

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Table 2-3 Summary of Key IRP Filing Requirements and Location in IRP

Supporting Information supplements the data submitted in the Standardized Tables.”
Section 4,
5, 7; all
Appendices
E. Demand
Forecast
“1. Reporting Requirements…annual forecasted peak demand (MW) in the CRAT and annual forecasted retail sales, other loads, and net energy for load in the EBT…

2. Demand Forecast Methodology and Assumptions.

1. Diversified Procurement Portfolio

2. RPS Planning Requirements

3. Energy Efficiency and Demand Response Resources

4. Energy Storage

5. Transportation Electrification”
Section 8,
Appendix A
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ITEM SELECTED TEXT FROM THE CEC GUIDELINES LOCATION
IN IRP
G. System and
Local Reliability
“Filing POUs [must] adopt an IRP to… meets the goal of ensuring system and local reliability…[and report]:

1. Reliability Criteria…the planning reserve margin and how it was determined.

California Energy Commission. Publication Number: CEC-200-2017-004.

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.

2.4.1 Greenhouse Gas Emissions

2.4.1.1 Greenhouse Gas Emissions – Global Warming Solutions Act (AB 32) On January 1, 2007, Assembly Bill 32 (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 Packet Pg. 254 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Purpose and Background 2-10
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 extend 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 1990 levels 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 of the 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 (EV) programs, as further described in Section 5 of this report.

2.4.1.2 Greenhouse Gas Emissions – Emissions Performance Standard (SB 1368) 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 (CO2) per MWh of electricity produced, with limited exceptions for routine maintenance, requirements of pre-existing contractual commitments, or threat of significant financial harm.

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2.4.1.3 Greenhouse Gas Emissions: SB 32 and AB 197
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 1990 level 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.

2.4.2 Renewable Energy

2.4.2.1 Portfolio Standard (SB 350 and SB 1078)
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 Bill 350 (“SB 350”), requires that electricity generated each year from eligible renewable energy resources be at least 50 percent by December 31, 2030.

2.4.2.2 Renewables Portfolio Standard (SBX1-2)
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 of the 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 of total kilowatt hours sold to the utility’s retail end-use customers:

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(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 of the 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.

PCC0: 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 of the contract may be extended if the 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.

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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.

2.4.3 Demand Side

2.4.3.1 Solar Power (SB 1)
On August 21, 2006, Governor Schwarzenegger signed into law California Senate Bill 1 (also known as the “California Solar Initiative”). This legislation requires POUs to establish a program supporting the SB 1 goal to install 3,000 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 Packet Pg. 258 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Purpose and Background 2-14
the program which helped to provide more than 8 MW of installed capacity at over 800 customer locations.7
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.

2.4.3.2 Energy Efficiency (SB 1037; AB 2021)
Senate Bill 1037 (SB 1037) was signed by then Governor Schwarzenegger on September 29, 2005.

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.

2.4.3.3 Energy Efficiency and Demand Side Management
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.

2.4.3.4 Peak Demand (SB 338)
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).

7 City of Redding Report to Redding City Council, 4.5(b)—Adopt Resolutions to Terminate Solar Surcharge, November 7, 2017.

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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.

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. •Sustainability
•Economic Feasibility
•Legal/Moral Consideration
•Aesthetic Consideration
•Invite Participation
•Document Issues/Concerns
•Develop Action Plan
•Communicate Action Plan
•Who are the stakeholders we impact?
•What stakeholders impact us?
•How will this group evolve over time?
•Implement and Evaluate
Report, Communicate Identify
Improvements Refine
Implement,
Review,
Improve
Stakeholder
Mapping
Identify
Material
Issues
Engage and
Develop
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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 of the 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 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.

Figure 2-6 Stakeholder Engagement Participants
IRP
Stakeholder
Process
COR Staff
Consultants Public
Customers
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3.0 Existing Resources and System Description
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 of the 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.

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Table 3-1 Power Supply Resources (Calendar Year 2017)

SOURCE CAPACITY

AVAILABLE (MW)

ANNUAL ENERGY
(GWH)

PERCENT OF
TOTAL ENERGY(1)
Generated Power
Redding Power Station(2) (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(1) 186.6 212 28.5%
Purchased Power
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(1) 151.5 533 71.5
Total (Generated and Purchased) 338.1 745 100.0%
(1) Totals may not add due to rounding.
(2) 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
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Figure 3-1 Power Resource Locations (Self-Owned and PPA Resources) Figure 3-2 Mix of Energy Production by Generation Type, 2017 (Calendar Year) Wind
22%
Natural Gas
25%
Large Hyrdo
48%
Small Hydro
5%
Mix of Energy
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3.1 GENERATING FACILITIES

3.1.1 Redding Power Station
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.

3.1.2 Whiskeytown Project
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 of the 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)
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 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

SOURCE TYPE

CAPACITY

AVAILABLE
(MW)

ANNUAL ENERGY
(GWH)

PERCENT OF

RETAIL SALES
Renewable Resources
Whiskeytown Dam Hydroelectric
(Owned)

3.5 26 3.5%
M-S-R PPA/Big Horn I Wind
Project
Wind
(Purchase)

22.0 (firmed and
shaped MW)
164 22%
WAPA Base Resource
(Small Hydro)
Hydroelectric
(Purchase)

7.6 1%
Zero Carbon Resource
WAPA Base Resource
(Largo Hydro)
Hydroelectric
(Purchase)
128.5 361 48.0%
Local Solar Projects (Zero
Carbon Resource
Solar PV 10.2 89.4 NA (behind the
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.

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3.3 CONTRACTUAL PURCHASES
In addition to owning and operating generating facilities, energy needs are supplemented through contractual purchases, as further described below.

3.3.1 Big Horn I Wind Energy Project
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.

If the 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 of the California-Oregon Transmission Project (COTP) transfer capability (discussed below) is used to provide for transmission of the 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.

3.3.2 WAPA Base Resource (Hydroelectric Power)
COR receives a significant portion of its 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 Packet Pg. 267 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Existing Resources and System Description 3-7
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.

3.3.2.1 Impact of Drought
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
FISCAL YEAR (JULY 1-JUNE 30)
ENERGY
(GWH)
2012-13 244
2013-14 178
2014-15 158
2015-16 170
2016-17 338
Estimated 2017-2018 237
Source: City of Redding, Fiscal 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 Packet Pg. 268 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Existing Resources and System Description 3-8
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.

3.3.3 Other (NCPA)
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.

Figure 3-3 Transmission

3.4.1 WAPA Transmission Service and BANC
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 Packet Pg. 269 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Existing Resources and System Description 3-9
Balancing Authority of Northern California (BANC) balancing authority area (BAA) and interconnects with the California Independent 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.

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Figure 3-4 Balancing Area of Northern California (BANC) Members As a member of BANC, COR is responsible for matching customer usage and resources on a moment-by-moment basis. However, BANC operates the transmission system, monitoring power lines to target their operation within the reliable limits of the system, and coordinates operations with neighboring balancing authorities.

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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

CAPACITY

CONTRACT END DATE

CAPACITY
(MW)*

VOLTAGE
(KV) DELIVERY/RECEIPT POINTS
Long-Term Firm Transmission Service
Contract 1 2035 136.8 230 Olinda, Tracy, Elverta, Airport, Keswick (115 kV)
Contract 2 2035 47.2 230
Delivery: Tracy, Cottonwood
Receipt: Airport, Keswick (115 kV)
Short-Term Firm COTP Transmission Service
Contract 1 By request By request 230-500 California-Oregon Border, Southern Terminus (500 kV); Olinda, Tracy (230 kV)
* Delivery point capacity (after losses)
Source: WAPA/CVP Contract for Transmission Service to the City of Redding, California

3.4.2 TANC and California-Oregon Transmission Project
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 TANC’s 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 MW) in the COTP. As a result, COR participates in the use of the COTP as both a member-participant of TANC (115 MW) and as a direct COTP owner (25 MW); 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 Packet Pg. 272 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Existing Resources and System Description 3-12
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).

3.4.3 Tesla-Midway Transmission Service
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.

3.4.4 Other Transmission Assets
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

3.5.1 Distribution Assets
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 of the electric system which more than doubled the 12 kV distribution system using underground cabling. Figure 3-5 shows the interface of the 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) Packet Pg. 273 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Existing Resources and System Description 3-13
 Approximately 17,000 poles
Figure 3-5 Electric Distribution System

3.5.2 Distribution System Adequacy
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.

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Figure 3-6 Reliability Comparison
For a more local comparison, in 2016, PG&E customers in the north valley had an average of 175 minutes without power.

During the Carr Fire—a raging wildfire that tore through Shasta County and blazed into Redding’s city limits—the local transmission system lost 5 out of 6 elements of redundancy. Because of our community-owned generation station and multiple connections to the WAPA grid, our operators were able to avoid a total city-wide blackout.

The distribution system conditions are continually evaluated and appropriate 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:

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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 of the 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 Packet Pg. 276 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Existing Resources and System Description 3-16
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 of the 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.

3.6.1 M-S-R Energy Authority – Gas Prepay
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).

3.6.2 Fixed Price Forward Purchases
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.

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Table 3-5 Natural Gas Purchase Obligations, Fixed Price Hedges YEAR 2018 2019 2020-2023 2024 2025
Decatherm per day (Dth/day)
(Delivery Point is PG&E City Gate)
6,167 5,667 5,000 4,500 4,000
Source: City of Redding

3.6.3 Natural Gas Transportation
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 of the contract period.

3.6.4 Natural Gas Storage
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 extensive 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.

Packet Pg. 278 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Energy and Demand Forecast 4-1

4.0 Energy and Demand Forecast
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 of the 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.

Figure 4-1 5-Year Average Monthly Energy Sales and Peak Demand (2013-2017)

8 System level Resource Adequacy (RA) requirement of 15 percent above the forecast 1 in 2 peak must be met— sometimes referred to as the 50/50 load forecast.
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Average Monthly Energy Sales and Peak Demand (2013-2017) Packet Pg. 279 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Energy and Demand Forecast 4-2
Table 4-1 lists 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
YEAR 1 2013 2014 2015 2016 2017
Number of Customers 2
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
Customers
43,551 43,662 43,832 44,039 44,233
Megawatt-Hour Sales
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 Peak
Demand
(MW)
235 249 232 232 231

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
Packet Pg. 280 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Energy and Demand Forecast 4-3

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 2018 load forecast of energy sales and peak demand levels was done by end user class and involved the following customer classes:
 Residential
 Large Commercial Users
 Small Commercial Users
 Fixed Use
 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.

Packet Pg. 281 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Energy and Demand Forecast 4-4
Table 4-2 Load Forecast Assumptions and Input Considerations

CATEGORY DESCRIPTION
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
Saturation & Efficiency/
New Technology
 SAE Inputs - Pacific Region Efficiencies from the EIA’s 2017 Annual Energy Outlook Forecast
 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

4.2.1 Rooftop solar installations
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.

Figure 4-2 Projected Solar Installations vs ITC Tax Credit 0%
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Packet Pg. 282 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Energy and Demand Forecast 4-5

4.2.2 The Electric Vehicle Forecast
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 Level 2 charger; residential incentives are $1,000 plus up to $500 for installing a Level 2 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.

Figure 4-3 Projected Electric Vehicles – COR Service Territory

4.2.3 Energy Efficiency and Demand Response
The load forecast considered a number of energy efficiency and demand reduction measures.

These are further described in Section 5.

4.2.4 Weather Normalization
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.

Packet Pg. 283 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Energy and Demand Forecast 4-6

4.2.5 Service Area Population
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.

4.3.1 Peak and Energy Forecast
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.

4.3.2 System Load Factor
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.

Packet Pg. 284 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Energy and Demand Forecast 4-7
Table 4-3 Projected Net Energy Requirements, Peak Demand Forecast, and Load Factor YEAR

NET ENERGY REQUIREMENTS PEAK DEMAND
LOAD
MWH FACTOR (%)

PERCENT
CHANGE (%) MW

PERCENT
CHANGE (%)
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%
AAGR 2018-2037 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.

Packet Pg. 285 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Energy and Demand Forecast 4-8
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.

Figure 4-4 Energy Requirements Comparison: COR Forecast vs. CEC Forecast for COR 0 100
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Energy Demand: ITRON vs. CEC Comparison
ITRON Redding CEC Redding
Packet Pg. 286 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Customer Programs, Energy Efficiency and Demand Response Resources 5-1

5.0 Customer Programs, Energy Efficiency and Demand
Response Resources
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.10 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 (FY) 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/TN217482_20170508T153251_Appendix_B__20182027_Annual_Targets_All_POUs.xlsx.

Packet Pg. 287 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Customer Programs, Energy Efficiency and Demand Response Resources 5-2 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.
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PUC 9505 Target Redding AAEE Savings Achieved - 2015-2017 Redding SB350 Target Packet Pg. 288 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Customer Programs, Energy Efficiency and Demand Response Resources 5-3  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.

5.2.1 Current Residential Energy Efficiency Programs

5.2.1.1 Residential Deemed Rebates – Committed Savings
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  Whole House Fan
 Wall Insulation upgrade
 Ceiling Insulation upgrade
 Dual Pane Windows Replacing Single Pane Windows

5.2.1.2 Residential Weatherization Program - AAEE
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 Packet Pg. 289 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Customer Programs, Energy Efficiency and Demand Response Resources 5-4 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.

5.2.1.3 Residential Shade Tree Program – AAEE
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 of the tree in a format that is beneficial for integrated resource planning.

5.3 COMMERCIAL REBATES

5.3.1.1 Commercial Deemed Rebates – Committed Savings
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
 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

5.3.1.2 Commercial Calculated Lighting Rebates – Committed Savings The largest commercial program continues to be the calculated commercial lighting program; this program incentivizes customers to upgrade interior and exterior lighting systems.

5.3.1.3 Commercial Custom Program – AAEE
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

5.4.1.1 Current Municipal Programs – AAEE
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:

Packet Pg. 290 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Customer Programs, Energy Efficiency and Demand Response Resources 5-5  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

5.4.1.2 Future Programs
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.

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
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ANNUAL EE PORTFOLIO MARKET POTENTIAL BY END USE
Non-Res Lighting Res Shell Res Pool Pump
Non-Res Cooling Res Cooling Res Refrigeration
Appliances Res Water Heating SB350 Savings Target
Packet Pg. 291 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Customer Programs, Energy Efficiency and Demand Response Resources 5-6  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.

5.5.1 Energy Storage
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.

Packet Pg. 292 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Customer Programs, Energy Efficiency and Demand Response Resources 5-7 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 MW) 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.

5.5.2 Additional Solar and Intermittency Analysis
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 of the 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.

Packet Pg. 293 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan Customer Programs, Energy Efficiency and Demand Response Resources 5-8

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 met 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 it is 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

12 A Level 2 charger provides 240 VAC and charges in 4-8 hours, the equivalent of 12-20 miles per hour of charge.

Packet Pg. 294 Attachment: Previous Staff Report - September 21, 2021, item no. 4.5(e)--Accept the 2021 Demand-Side Management Integrated Resource Plan The Need for Additional Resources and Resource Options 6-1

Redding City CouncilFebruary 15, 2022

Redding City Council
February 15, 2022