Redding City Council
May 5, 2026

Agenda
Regular Meeting
Redding City Council
Council Chambers (Doors open 30 minutes prior)
777 Cypress Avenue,
Redding, CA
May 5, 2026
6:00 PM

1. CALL TO ORDER - MAYOR MIKE LITTAU
A. Pledge of Allegiance
B. Invocation - Lori Moretti, Redding Police and Fire Departments' Chaplain C. Roll Call

2. PRESENTATIONS
2A. Mayor’s Proclamation presented to Ready for Life Foster Care Agency declaring May 2026 as Foster Care Awareness Month in the City of Redding. 2B. Presentation by Tim Bauer, Sports and Events Director for Choose Redding Lodging regarding the Ironman 70.3 event.

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

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 their name through the electronic kiosk, 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.

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 enter your name in the electronic kiosk located in the lobby. 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.gov and 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 May 5, 2026

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 enter your name in the electronic kiosk located in the lobby 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 City Council Minutes: Special Meeting – Closed Session of April 21, 2026; and Regular Meeting of April 21, 2026.

4.5(a). Approve the updated 2026 Redding Electric Utility Security Plan pursuant to Senate Bill 699 (2014) and the California Public Utilities Commission Phase I Decision Order, Instituting Rulemaking, regarding the physical security of electrical corporations.

4.5(b). Authorize and approve the following actions relative to Redding Electric Utility’s Customer Programs Portfolio for the Fiscal Year 2026-27:
(1) Update the Residential Electrification Rebate Program to add Heat Pump HVAC incentives and terminate the Heat Pump Clothes Dryer program; (2) Update the Commercial Electrification Rebate Program to add Heat Pump HVAC incentives and terminate the DC Fast Charging Station and Demand Credit Programs; and
(3) Terminate Single-Family New Construction Electrification Program based on updated State Energy Code requirements

4.6(a). Authorize and approve the following:
(1) Authorize the City Manager, or designee, to increase the contract amount from $364,952.16 to $367,130.00 for fiscal year 2025-2026; (2) Authorize the City Manager, or designee, to execute the Second Amendment with Peerless Building Maintenance, Inc., Contract (C10844) for janitorial services, and increase the contract amount from $364,952.16 to $435,919.84 for fiscal year 2026-2027;
(3) Authorize the City Manager, or designee, to approve any future amendments up to $35,000 per year; and
(4) Find that amending an agreement is not a project as defined under the California Environmental Quality Act, and no further action is required.

Redding City Council May 5, 2026

4.11(a). Authorize and approve the following actions relative to Bid Schedule No. 5681, Country Oaks Water Main Replacement Project:
(1) Award the project to the lowest bidder, Allen Gill Construction, Inc., in the amount of $2,747,792;
(2) Approve an additional $307,000 to cover the cost of administration and inspection fees;
(3) Approve $200,000 for project development costs;
(4) Approve $280,000 to provide construction contingency funding; (5) Authorize the City Manager, or designee, to approve additional increases in either the construction management or construction contingency amounts up to a total of $100,000; and
(6) Find that the project is categorically exempt from review under the California Environmental Quality Act, pursuant to Section 15301 – Existing Facilities.

4.11(b). Authorize and approve the following actions relative to Bid Schedule No. 5684, Clear Creek Wastewater Treatment Plant 2026 Sludge Dredging Project:
(1) Award to Synagro - WWT, Inc., in the amount of $335,006.72; (2) Approve an additional $40,000 to cover the cost of administration and inspection fees;
(3) Approve $12,500 for project development costs;
(4) Approve $33,000 to provide construction contingency funding; (5) Authorize the City Manager, or designee, to approve additional increases in either the construction management or construction contingency amounts up to a total of $10,000; and
(6) Find that the Project is categorically exempt from review under the California Environmental Quality Act, pursuant to Section 15301 - Existing Facilities.

4.11(c). Authorize and approve the following actions relative to the City of Redding Tarmac Road Storm Drain Emergency Replacement Project (Project):
(1) Accept update regarding the Project; and
(2) Pursuant to Public Contract Code Section 22050(c)(1), make a determination by a four-fifths vote that there is a need to continue the emergency work.

4.11(d). Authorize and approve the following actions relative to the Right-of-Way Grants from the United States Department of the Interior, Bureau of Land Management for a portion of Buenaventura Boulevard and for secondary access to the proposed Peaks Subdivision:
(1) Approve and authorize the Public Works Director, or designee, to execute the Right-of-Way Grants; and
(2) Find that this action is categorically exempt from environmental review under the California Environmental Quality Act Guidelines, pursuant to Section 15301 – Existing Facilities.

Redding City Council May 5, 2026

4.11(e). Authorize and approve the following actions relative to Request for Proposals Schedule No. 5666, Construction Management and Inspection Services for the City of Redding Westside Road Bridge over Canyon Hollow Creek Replacement Project:
(1) Award to Webster Engineering, Inc.;
(2) Authorize the Mayor to execute a Consulting and Professional Services Contract for a not-to-exceed fee of $1,064,870.00 with Webster Engineering, Inc., to provide Construction Management and Inspection Services;
(3) Authorize the City Manager, or designee, to approve contract amendments not to exceed $50,000;
(4) Adopt Resolution approving and adopting the 37th Amendment to City Budget Resolution No. 2025-049 appropriating $537,800 of Traffic Impact Fees for the Westside Road over Canyon Hollow Creek Bridge Replacement Project; and
(5) Increase the construction management budget for the Westside Road over Canyon Hollow Creek Bridge Replacement Project by $537,800 to bring the construction management total to $1,250,300 and thus the total project budget to $7,508,026.

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

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. Public Hearing to consider Resolution for submission of 2026-27 Annual Action Plan and Citizen Participation Plan to the United States Department of Housing and Urban Development.

Recommendation:

Conduct a Public Hearing and, upon conclusion:
(1) Adopt Resolution approving the submission of the 2026-27 Annual Action Plan and Citizen Participation Plan to the United States Department of Housing and Urban Development (HUD);
(2) Authorize the City Manager, or designee, to execute all necessary documents and submit the Annual Action Plan and Citizen Participation Plan to HUD; (3) Find that adopting a resolution and submission of a Annual and Citizen Participation Plan is not considered a project under the California Environmental Quality Act; and
(4) Find that adopting a resolution and submission of a Consolidated Plan is an exempt activity under the National Environmental Policy Act under Title 24 CFR 58.34(a)(3).

Redding City Council May 5, 2026

Development Services

6.2. Public Hearing to consider tentative Subdivision Map Application S-2024- 00740, Planned Development Plan PD-2024-00741, and Rezoning Application RZ-2024-00795, by J&L Custom Homes, to subdivide a 1.65-acre parcel located at 4363 Churn Creek Road into 16 parcels, and to rezone the property from “RM-9” Residential Multiple-Family District to “RM-9-PD” Residential Multiple-Family District with Planned Development Overlay.

Recommendation:

Conduct a Public Hearing and, upon conclusion:
(1) Offer Ordinance approving Rezoning Application RZ-2024-00795 from “RM-9” Residential Multiple-Family District to “RM-9-PD” Residential Multiple Family District with Planned Development Overlay for first reading by title only and waive the full reading;
(2) Authorize the City Attorney to prepare and the City Clerk to publish a summary ordinance;
(3) Approve Tentative Subdivision Map Application S-2024-00740 and Planned Development Plan Application PD-2024-00741, Churn Creek Commons Subdivision and Planned Development, subject to the draft Conditions of Approval; and
(4) Determine the project is exempt under the California Environmental Quality Act, upon a determination the necessary findings are in evidence.

Redding City Council May 5, 2026

Fire

6.3. Public Hearing to consider Ordinance amending Redding Municipal Code Title 9 (Health and Safety), to align with updates to the 2025 California Fire Code.

Recommendation:

Conduct a Public Hearing and, upon conclusion:
(1) Introduce Ordinance amending Redding Municipal Code Title 9 (Health and Safety), Chapter 9.20 (Fire Code) by amending Sections 9.20.010 (Adoption),

9.20.020 (Title), 9.20.030 (Supplemental Rules, Regulations, and Standards),

9.20.040 (Fire Prevention Division), 9.20.050 (Self-Inspection), 9.20.060 (Appeals), 9.20.070 (Violation Penalties), 9.20.080 (Enforcement – Citation Authority), 9.20.100 (Open Burning, Recreational Fires, and Outdoor Fireplaces), 9.20.110 (Fire Apparatus Access Roads), 9.20.120 (Premises Identification), 9.20.130 (Fire Hydrants), 9.20.140 (Fire Protection Systems),

9.20.150 (Existing Buildings), 9.20.160 (High-Piled Combustible Storage),

9.20.170 (Fire Safety During Construction and Demolition), 9.20.180 (Regulations for Fireworks), 9.20.190 (Very High Severity Zone Designation and Construction Standard), 9.20.195 (Flammable and Combustible Liquid Storage), 9.20.200 (Referenced Standards), 9.20.210 (Appendix B – Fire Flow Requirements for Buildings), 9.20.220 (Appendix C – Footnote Additions), and 9.20.230 (Appendix D), for first reading by title only, and waive the full reading;
(2) Authorize the City Attorney to prepare, and the City Clerk to publish a summary ordinance according to law; and
(3) Find that this action is exempt from review under the California Environmental Quality Act Guidelines, pursuant to Section 15061 (b)(3) – Common Sense Exemption.

9. REGULAR CALENDAR: REPORTS & COMMUNICATIONS OF DEPARTMENTS,

BOARDS, COMMISSIONS AND COMMITTEES
Assistant City Manager

9.2(a). Oral update regarding agreement with Circle 6 Consulting Inc.

Recommendation:

Informational Only.

Redding City Council May 5, 2026

Public Works

9.11(f). Consider Ordinance amending Redding Municipal Code Title 14 (Utilities), Chapter 14.09 (Water Shortage Contingency Plan).

Recommendation:

Authorize and approve the following relative to the City of Redding Water Shortage Contingency Plan:
(1) Offer an Ordinance amending Redding Municipal Code Title 14 (Utilities), Chapter 14.09 (Water Shortage Contingency Plan) by amending Sections

14.09.030 (Definitions), 14.09.040 (Water Shortage Stages), and 14.09.050 (Water Conservation/Water Shortage Emergency Response Stages) for first reading by title only and waive the full reading, to allow for extended hours for outdoor watering to better accommodate reasonable lifestyle schedules; (2) 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 adoption of the ordinance is exempt from environmental review under the California Environmental Quality Act, pursuant to Section 15061(b)(3) – Common Sense Exemption.

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
Redding City Council May 5, 2026

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: https://www.shastaartscouncil.org/scactv; and the City’s YouTube Channel https://www.youtube.com/cityofredding. Video of the City Council meetings can also be viewed on the City’s web site at https://www.cityofredding.gov/. Open the Services tab, and select City Council Videos.

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
Mayor’s Proclamation presented to Ready for Life Foster Care Agency declaring May 2026 as Foster Care Awareness Month in the City of Redding.

Attachments
Foster Care Awareness Month Proclamation
MEETING DATE: May 5, 2026
ITEM NO. 2A
FROM:
***APPROVED BY***
[email protected]
[email protected]
SUBJECT: 2A--Mayor's Proclamation declaring May 2026 as Foster Care Awareness Month in the City of Redding
Mike Littau, Mayor
Packet Pg. 9
Packet Pg. 10
Attachment: Foster Care Awareness Month Proclamation (2A--Mayor's Proclamation declaring May 2026, as Foster Care Awareness Month)

CITY OF REDDING

REPORT TO THE CITY COUNCIL
Recommendation
Presentation by Tim Bauer, Sports and Events Director for Choose Redding Lodging regarding the Ironman 70.3 event.

MEETING DATE: May 5, 2026
ITEM NO. 2B
FROM:
***APPROVED BY***
[email protected]
[email protected]
SUBJECT: 2B--Presentation by Choose Redding Lodging
Jason Gibilisco, Management
Assistant to the City Manager
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CITY OF REDDING

REPORT TO THE CITY COUNCIL
Recommendation
Approve City Council Minutes: Special Meeting – Closed Session of April 21, 2026; and Regular Meeting of April 21, 2026.

Attachments
Unofficial Minutes - Special Meeting - Closed Session of April 21, 2026 Unofficial Minutes - Regular Meeting of April 21, 2026
MEETING DATE: May 5, 2026
ITEM NO. 4(a)
FROM:
***APPROVED BY***
[email protected]
[email protected]
SUBJECT: 4(a)--Approve City Council Minutes
Sharlene Tipton, City Clerk
Packet Pg. 12
207
04/21/2026
Unofficial Minutes Redding City Council, Special Meeting Civic Center Council Chambers
777 Cypress Avenue
Redding, CA 96001
April 21, 2026, 4:30 PM
The meeting was called to order by Mayor Mike Littau with the following Council Members present: Tenessa Audette, Jack Munns, and Erin Resner. Council Member Dr. Paul Dhanuka arrived at 4:34 p.m.

Also present: Interim City Attorney Mary Anne Wagner, City Manager William Tarbox, Interim Assistant City Manager/Public Works Director Michael Webb, City Clerk Sharlene Tipton, and Executive Assistant II Erin Barnhart.

PUBLIC COMMENT
Tony Trimp spoke on behalf of Hawk Mazzota expressing support for the American Motorcyclist Association (AMA) Supermoto & Golden State Championship Round 3 being held at the Redding Motor Sports Park on June 4-7, 2026.

CLOSED SESSION
At the hour of 4:34 p.m., Mayor Littau announced that the Council would adjourn to Closed Session.

At the hour of 6:12 p.m., Mayor Littau reconvened the Closed Session to Open Session and reported that in reference to:
3A. Closed Session pursuant to California Government Code Section 54956.9(d)(1):

CONFERENCE WITH LEGAL COUNSEL - EXISTING LITIGATION
River Ranch Neighborhood Association v. County of Shasta and City of Redding; Shasta County Superior Court Case No. 26CV-210023
Pursuant to Government Code Section 54957.1(a), the City Council took no reportable action on this item.
3B. Closed Session pursuant to California Government Code Section 54956.9(d)(4):

CONFERENCE WITH LEGAL COUNSEL - ANTICIPATED LITIGATION
Initiation of Litigation - Six potential cases
The City Council unanimously voted to authorize staff to opt into a settlement of litigation with the six remaining defendants in National Opioid settlement litigation. The settlement provides the City of Redding (City) with a proportional share of an estimated $95 million settlement pool that is distributed nationwide, and any funds received by the City must be utilized for specific programs designed to reduce the impacts of the opioids. 3C. Closed Session pursuant to California Government Code Section 54957.6:

CONFERENCE WITH LABOR NEGOTIATOR
Designated Agency Representative: Personnel Director Kari Kibler Employee Organizations:
(1) International Brotherhood of Electrical Workers 1245 AFL-CIO Power Production; (2) International Brotherhood of Electrical Workers 1245 AFL-CIO Maintenance Employees;
(3) United Public Employees of California Local 792 – Technical Employees Unit; and (4) Unrepresented
Pursuant to Government Code Section 54957.1(a), the City Council took no reportable action on this item.

At the hour of 6:04 p.m., Mayor Littau declared the meeting adjourned and continued item nos. 3D through 3F to the end of the regular City Council meeting held on the same date, April 21, 2026, at 6:00 p.m. in the City of Redding Council Chambers located at 777 Cypress Avenue, Redding, CA 96001.

Packet Pg. 13
Attachment: Unofficial Minutes - Special Meeting - Closed Session of April 21, 2026 (4(a)--Approve City Council Minutes) 208
04/21/2026

CONTINUED CLOSED SESSION
At the hour of 6:35 p.m., Mayor Littau reconvened the Special Meeting and announced that the Council would adjourn to Closed Session.

At the hour of 7:30 p.m., Mayor Littau reconvened the Special Meeting to Open Session and reported that in reference to:
3D. Closed Session pursuant to California Government Code Section 54956.8:

CONFERENCE WITH REAL PROPERTY NEGOTIATOR:

Property Location: 6065 Eastside Road; Assessor’s Parcel No. 050-270-012 Agency Negotiator: Public Works Director Michael Webb
Negotiating Parties: City of Redding and David Arrighi, Robert Arrighi, Patricia Arrighi Under Negotiation: Price and Terms
Pursuant to Government Code Section 54957.1(a), the City Council took no reportable action on this item.
3E. Closed Session pursuant to California Government Code Section 54956.8:

CONFERENCE WITH REAL PROPERTY NEGOTIATORS
Property Location: 700 Auditorium Drive, Assessor’s Parcel No. 102-020-026 Agency Negotiator: City Manager William Tarbox
Negotiating Parties: Advance Redding, Inc.

Under Negotiation: Price and Terms
Pursuant to Government Code Section 54957.1(a), the City Council took no reportable action on this item.
3F. Closed Session pursuant to California Government Code Section 54956.8:

CONFERENCE WITH REAL PROPERTY NEGOTIATOR
Property Location: Redding Motorsports Park / Redding Drag Strip, located on Old Oregon Trail, a licensed portion of Assessor’s Parcel Nos. 054- 270-004 and 056-130-031
Agency Negotiator: Community Services Director Travis Menne Negotiating Parties: City of Redding and Redding Drag Strip, Inc.; Redding Motorsports Park; Stillwater MX; Shasta Kart Klub; and Shasta Supermoto Under Negotiation: Price and Terms
Mayor Littau reported the following, by a unanimous vote of the Council: “We (the City Council and staff) have asked the Interim City Attorney to review each agreement for the racetrack groups. We will be reaching out to each group to discuss further action and potential modifications to agreements, each group will have their own track, and we respectfully ask for all groups to work together for the better of the community and use of the facilities owned by the City of Redding. It is our intention for each group to have and use their own tracks exclusively.”
At 7:32 p.m., Mayor Littau re-opened public comment.

Mark Monroe asked for clarification of the reportable action, in which the Council confirmed that it was their intention for each group to have their own agreements and use of their own tracks exclusively.

ADJOURNMENT
There being no further business at the hour of 7:35 p.m., Mayor Littau declared the meeting adjourned.

APPROVED:
______________________________
Mike Littau, Mayor
ATTEST:
___________________________
Sharlene Tipton, City Clerk
Packet Pg. 14
Attachment: Unofficial Minutes - Special Meeting - Closed Session of April 21, 2026 (4(a)--Approve City Council Minutes) 209
04/21/2026
Unofficial Minutes Redding City Council, Regular Meeting Civic Center Council Chambers
777 Cypress Avenue
Redding, CA 96001
April 21, 2026, 6:00 PM
The meeting was called to order at 6:14 p.m. by Mayor Mike Littau with the following Council Members present: Tenessa Audette, Dr. Paul Dhanuka, Jack Munns, and Erin Resner.

Also present: Interim City Attorney Mary Anne Wagner, City Manager William Tarbox, Interim Assistant City Manager/Public Works Director Michael Webb, City Clerk Sharlene Tipton, and Executive Assistant II Erin Barnhart.

The Pledge of Allegiance was led by Council Member Munns.

The Invocation was provided by Reverend Janet Chapman, First Christian Church of Redding.

PRESENTATION
2A. Mayor Littau removed this item from the agenda due to the absence of the scheduled presenter.

Presentation from Shasta County Arts Council’s Youth Poet Angela Ekezie, who represented University Preparatory School as the Shasta County Champion and a Finalist in the 2026 Poetry Out Loud Competition, held on March 8-9, 2026, in Sacramento, California.

PUBLIC COMMENT
Darlene Waltman opined her concerns regarding homelessness, excessive drug use, street design issues, and traffic safety concerns in the Lawncrest Village Subdivision between Cypress, Alfreda Way, and Hartnell Avenue.

Council Member Munns directed Chief of Police Brian Barner to connect with Ms. Waltman.

Mark Monroe thanked the Council for their attention to the issues at the Redding Motorsports Park, and noted that there has been some damage to the supermoto track, costs associated for that have been submitted.

Shannon Polson, a resident of Westwood Village, asked Council to consider a secondary ingress and egress access for the subdivision. Ms. Polson provided a handout, incorporated herein by reference.

Hawk Mazzota, owner-operator of Hawk Mazotta Moto Camp and owner of the Golden state Championship Series: (1) expressed his support for use of the road course, also known as the kart track; and (2) invited the Council to attend the MotoAmerica and American Motorcyclist Association (AMA) Supermoto & Golden State Championship Round 3 being held at the Redding Motor Sports Park on June 4-7, 2026.

Chris Brooks expressed frustration with other clubs wanting to use the kart track without compensation, including reimbursement for damages incurred, and spoke in opposition to the current structure of the Redding Motorsports Park.

In response to Mr. Brooks, Vice Mayor Dr. Dhanuka noted that he understands his concerns and is taking it seriously, however, noted that it does not help to imply something against City staff.

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 City Council Minutes: Special Meeting – Closed Session of April 7, 2026; and Regular Meeting of April 7, 2026.

Packet Pg. 15
Attachment: Unofficial Minutes - Regular Meeting of April 21, 2026 (4(a)--Approve City Council Minutes) 210
04/21/2026
4(b). Accept the following City of Redding Accounts Payable and Payroll Registers:
(1) Accounts Payable Register No. 9 for the period March 1, 2026 through March 31, 2026, in the amount of $23,836,880.75; (2) Register No. 18 for the period February 15, 2026, through February 28, 2026, in the amount of $2,913,216.94; and (3) Register No. 19 for the period March 1, 2026 through March 14, 2026, in the amount of $2,732,252.23; for a summary total of $29,482,349.92.
4(c). Accept City of Redding Proof of Cash and Cash by Fund reports for the month of February 2026.
4(d). Accept the City of Redding Treasurer’s Report for February 2026.

4.5(a). Authorize and approve the following relative to Bid Schedule No. 5682 – Underarm SideBreak Switches and Retro-Fit Kits for the Redding Electric Utility: (1) award Bid Schedule No. 5682 to OneSource Supply Solutions for an annual evaluated contract total of $394,040.15, including sales tax; (2) authorize the Purchasing Officer to extend the bid award annually with OneSource Supply Solutions through February 28, 2031, if mutually agreeable, with all prices, terms, and conditions remaining the same; and (3) authorize the City Manager, or designee, to approve an additional $80,000 per contract term as a contingency for future price increases or to support operational requirements.

4.6(a). Authorize and approve the following actions relative to the State of California Parks and Recreation: Division of Boating and Waterways (Cal Boating) Aquatic Center Grant: (1) accept and ratify the State of California – Natural Resources Agency Department of Parks and Recreation: Cal Boating Aquatic Center Grant in the amount of $42,000; (2) authorize the Director of Community Services, or designee, to execute the grant agreement and associated documents with Cal Boating to implement the Aquatic Center Grant Fiscal Year 2025-26 project; and (3) adopt Resolution No. 2026-028, a resolution of the City Council of the City of Redding, approving and adopting the 34th Amendment to Budget Resolution No. 2025-049 appropriating $42,000 for the Cal Boating Aquatic Center Grant in Fiscal Year 2025-26.

4.6(b). Adopt Resolution No. 2026-029, a resolution of the City Council of the City of Redding, proclaiming Friday, April 24, 2026, as Community Tree Planting Day, otherwise known as Arbor Day, in the City of Redding; and recognizing the City of Redding’s Community Services Department - Parks Division for receiving the Tree City U.S.A. Award and/or the City of Redding Electric Utility for receiving the Tree Line U.S.A. Utility Award.

4.9(a). Adopt Resolution No. 2026-030, a resolution of the City Council of the City of Redding, proclaiming May 4, 2026, as California Peace Officer Memorial Day, May 14, 2026, as Shasta County Peace Officer Memorial Day, and May 15, 2026, as National Peace Officer Memorial Day in the City of Redding.

4.11(a).Authorize and approve the following: (1) approve the acquisition of Public Services Easements at 901 North Market Street (Assessor’s Parcel Number 112-300-004) at no cost to the City of Redding; (2) authorize the Mayor to execute all legal documents necessary to complete the acquisitions; and (3) find this action to be categorically exempt from environmental review under the California Environmental Quality Act Guidelines, pursuant to Section 15305 – Minor Alterations to Land Use Limitations.

4.11(b).Authorize and approve the following actions relative to the Summary Vacation of a portion of Court Street (A-2025-01328): (1) adopt Resolution No. 2026-031, a resolution of the City Council of the City of Redding, summarily vacating a portion of Court Street, Document No. 1999-0028324, Shasta County Records described in Exhibit A and depicted in Exhibit B; (2) find the action consistent with the General Plan; and (3) find the action categorically exempt from environmental review under the California Environmental Quality Act Guidelines, pursuant to Section 15035 - Minor Alterations in Land Use Limitations.

4.11(c).Authorize and approve the following actions related to the purchase of one Tiger Bengal Series Boom Mower mounted on a 2026 John Deere 6M 105 Tractor for the City of Redding’s Streets Division: (1) authorize the purchase using Sourcewell contract pricing, with a net delivered cost of $261,319.56 including all applicable taxes and fees; and (2) authorize the City Manager, or designee, to approve future pricing adjustments, and changes to the terms, as needed, due to inflation and unstable economic conditions up to a total of $30,000.

Packet Pg. 16
Attachment: Unofficial Minutes - Regular Meeting of April 21, 2026 (4(a)--Approve City Council Minutes) 211
04/21/2026

4.11(d).Authorize and approve the following actions relative to the City of Redding Tarmac Road Storm Drain Emergency Replacement Project (Project): (1) accept update regarding the Project; and (2) pursuant to Public Contract Code Section 22050(c)(1), make a determination by a four-fifths vote that there is a need to continue the emergency work.

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

The Vote:

AYES: Council Members – Audette, Dr. Dhanuka, Munns, Resner, and Littau NOES: Council Members – None
ABSTAIN: Council Members – None
ABSENT: Council Members – None
Resolution Nos. 2026-028 through 2026-0031 are on file in the Office of the City Clerk.

ADJOURNMENT
There being no further business at the hour of 6:33 p.m., Mayor Littau declared the meeting adjourned.

APPROVED:
___________________________
Mike Littau, Mayor
ATTEST:
____________________________
Sharlene Tipton, City Clerk
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Attachment: Unofficial Minutes - Regular Meeting of April 21, 2026 (4(a)--Approve City Council Minutes)

CITY OF REDDING

REPORT TO THE CITY COUNCIL
Recommendation
Approve the updated 2026 Redding Electric Utility Security Plan pursuant to Senate Bill 699 (2014) and the California Public Utilities Commission Phase I Decision Order, Instituting Rulemaking, regarding the physical security of electrical corporations.

Fiscal Impact
There is no fiscal impact related to approving revisions to the 2026 Redding Electric Utility (REU) Security Plan. Approval of the 2026 REU Utility Security Plan does not authorize capital improvements or expenditures. Any future physical security improvements identified in the plan would be subject to future City Council (Council) review and budget authorization through the applicable Electric Utility capital or operating budget.

Alternative Action
The Council may reject staff's recommendation and provide alternative direction.

Background/Analysis
Senate Bill 699 (2014) established the California Public Utilities Commission’s (CPUC) regulatory authority over both investor-owned and publicly owned utilities (POUs) with respect to utility physical security. Under that authority, the CPUC issued Decision 19-01-018, which requires POUs to maintain physical security plans for distribution-level facilities, obtain an independent third-party review before plan adoption, secure adoption by the applicable local governing body, and repeat that review and adoption process every five years. As a POU, REU must comply with those requirements, including identifying facilities that may merit special protection and developing measures to reduce identified risks and threats.

MEETING DATE: May 5, 2026
ITEM NO. 4.5(a)
FROM:
***APPROVED BY***
[email protected] [email protected]
SUBJECT: 4.5(a)--Consider approval of the 2026 REU Utility Security Plan for Distribution Level Facilities
Nick Zettel, Director of
Redding Electric Utility
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Report to Redding City Council April 29, 2026
Re: 4.5(a)--REU Utility Security Plan 2026 Page 2
To address the risk of long-term outages at distribution facilities, utilities were required to develop and implement physical security mitigation plans. The first REU Utility Security Plan was approved by the Council on June 1, 2021. The 2026 plan is the required five-year update to that prior plan. It summarizes actions completed since 2021 and identifies additional physical security enhancements for the next planning period.

In compliance with CPUC requirements, the plan was reviewed by an independent third party and validated before returning to the Council for approval. Decision 19-01-018 expressly allows a governmental entity, such as a police department, to serve as the third-party reviewer if it is organizationally separate from the utility and has the appropriate expertise. The Redding Police Department (RPD) meets those criteria and is qualified to perform the third-party review. An RPD captain completed the assessment, which is included as an appendix to the Utility Security Plan. The assessment concluded that the substations reviewed do not require additional physical security mitigation work at this time, while also noting that the capital improvements identified in the plan would improve substation resilience. The updated plan also identifies additional security enhancements, including improved access controls, expanded-metal anti-cut and anticlimb fencing, and upgraded substation lighting.

The City’s Deputy Fire Chief reviewed both the plan and the third-party assessment and validated the Utility Security Plan under the applicable CPUC guidelines. His validation summary is included as an appendix to the plan. If approved by the Council, staff will submit the revised Utility Security Plan to the CPUC by June 1, 2026. Because the plan contains sensitive security information, portions of the document are not available to the public.

Environmental Review
This is not a project defined under the California Environmental Quality Act, and no further action is required.

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

Attachments
Previous Staff Report - REU Utility Security Plan 2021
REU Utility Security Plan 2026 - Redacted
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CITY OF REDDING

REPORT TO THE CITY COUNCIL
Recommendation
Accept Redding Electric Utility’s Public Report on Physical Security for Distribution Level Facilities; and approve the Utility Security Plan pursuant to Senate Bill 699 and the California Public Utilities Commission Phase I Decision Order, Instituting Rulemaking, regarding the physical security of electrical corporations.

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

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

Background/Analysis
Senate Bill (SB) 699 is the existing law which states the California Public Utilities Commission (CPUC) has regulatory authority over both investor and publicly owned utilities (POUs). Under this authority, the CPUC implemented the Phase I Decision regarding physical security of utilities. POUs such as Redding Electric Utility (REU) must adhere to the physical security elements of the CPUC decision. The decision requires electric utilities to identify electric distribution assets that may merit special protection and measures to lessen identified risks and threats. To address the risk of long-term outages to a distribution facility, all utilities were required to develop and implement a physical security mitigation plan. The six-step plan is modeled on the security plan requirements set forth by the North America Electric Reliability Corporation (NERC) Critical Infrastructure Protocol (CIP)-014.

MEETING DATE: June 1, 2021
ITEM NO. 4.5(b)
FROM:
***APPROVED BY***
[email protected] [email protected]
SUBJECT: 4.5(b)--Consider Redding Electric Utility's Report on Physical Security for Distribution Level Facilities and Utility Security Plan Daniel Beans, Director of
Electric Utility
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Attachment: Previous Staff Report - REU Utility Security Plan 2021 (4.5(a)--REU Utility Security Plan 2026) Report to Redding City Council May 25, 2021
Re: 4.5(b)--Redding Electric Utility Security Plan Page 2 In addition to the security plan, REU was required to have the plan reviewed by an independent third party and validated prior to being approved by the Council. Both the third-party reviewer and validating staff were required to have relevant physical security qualifications. The Redding Police Department (RPD) is qualified under the CPUC requirements to review the plan. The assessment of REU’s physical security plan was conducted by an RPD Lieutenant and is included in the Utility Security Plan as an Appendix. In the assessment, RPD noted that the substations did not require additional physical security mitigation work; however, it was noted that the capital improvements outlined within REU’s Utility Security Plan will improve the resilience of all substations. Along with preparing the attached physical security plan, REU staff incorporated additional security enhancements to implement in the future, such as security cameras near REU infrastructure and additional solid perimeter walls for select substations within the City of Redding (City).

The City’s Deputy Fire Chief, Jay Sumerlin, reviewed both the plan and the third-party assessment conducted by RPD. Deputy Fire Chief Sumerlin validated the Utility Security Plan under the guidelines required by the CPUC and his validation summary is provided as an Appendix to the Plan.

If approved by the Council, REU’s Utility Security Plan will be submitted to the CPUC no later than July 10, 2021.

Due to the sensitive information contained in REU’s Utility Security Plan, portions of the document are not available to the public.

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.” • 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
REU's Utility Security Plan (available online)
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Attachment: Previous Staff Report - REU Utility Security Plan 2021 (4.5(a)--REU Utility Security Plan 2026) 1 | P a g e

UTILITY

SECURITY
PLAN
PUBLIC REPORT ON REDDING ELECTRIC UTILITY’S
PHYSICAL SECURITY PROGRAM FOR DISTRIBUTIONLEVEL FACILITIES June 1, 2026
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TABLE OF CONTENTS
I. Overview
A. Goal of Utility Security Plan............................................................................................................. 4 B. Description of Redding Electric Utility ........................................................................................... 4 C. Results of Utility Security Plan Assessment..................................................................................... 4 II. Background.......................................................................................................................................... 5 III. Plan Development Process................................................................................................................. 6 A. Physical Security Principles ............................................................................................................. 6 B. Utility Security Plan Development Process.................................................................................... 7 Step 1: Assessment/Plan Development............................................................................................. 7 Step 1A: Identify Covered Distribution Facilities ............................................................................... 7 Step 1B: Perform Risk Assessment ....................................................................................................... 7 Step 1C: Develop Mitigation Plan...................................................................................................... 7 Step 2: Third-Party Review ................................................................................................................... 7 Step 3: Validation................................................................................................................................. 8 Step 4: Adoption .................................................................................................................................. 8 Step 5: Maintenance........................................................................................................................... 8 Step 6: Repeat Process........................................................................................................................ 8 IV. Identification of Covered Distribution Facilities (Step 1A) ............................................................... 8 A. Identification Factors ...................................................................................................................... 8 B. Identification Analysis ................................................................................................................... 10 V. Risk Assessment (Step 1B).................................................................................................................. 11 A. Methodology ................................................................................................................................. 11 B. Mitigation Measures...................................................................................................................... 11 C. Risk Assessment.............................................................................................................................. 13 Packet Pg. 24
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VI. Covered Distribution Facility Mitigation Plans (Step 1C)................................................................ 15 VII. Independent Evaluation and Response (Step 2)........................................................................... 15 A. Requirements for Qualified Third-Party Review.......................................................................... 15 B. Identification of Third-Party Reviewer ......................................................................................... 15 C. Public Results of Third-Party Evaluation ....................................................................................... 16 D. REU Response................................................................................................................................. 16 VIII. Validation (Step 3)............................................................................................................................. 16 A. Selection of Qualified Authority................................................................................................... 16 B. Results of Qualified Authority Review.......................................................................................... 16 IX. Narrative Descriptions for Utility Security Plan ................................................................................. 16 A. Asset Management Program....................................................................................................... 16 B. Workforce Training and Retention Program............................................................................... 17 C. Preventative Maintenance Plan.................................................................................................. 17 D. Physical Security Event Training................................................................................................... 17 E. Communication Infrastructure Risk Assessment......................................................................... 17 F. Facility Design Features ................................................................................................................ 18

APPENDICES
A. THIRD-PARTY REVIEW OF UTILITY SECURITY PLAN
B. VALIDATION OF UTILITY SECURITY PLAN
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Ensuring the safety of its facilities is a top priority for Redding Electric Utility (REU), and REU prioritizes safety in all aspects of its design, operation, and maintenance practices. The overarching goal of this Utility Security Plan (Plan) is to describe REU’s risk management approach toward distribution system physical security, with appropriate consideration of resiliency, impact, and cost.

REU recognizes the importance of securing the safety and reliability of its electric system and, therefore, REU voluntarily participated in the California Public Utilities Commission’s (CPUC) Physical Security proceeding and has undertaken this assessment. In the spirit of continued voluntary cooperation, REU offers the following in response to CPUC Decision 19-01-018.

This Plan will be reviewed and updated at least every five years from initial adoption. A notification of the program acceptance and notifications of future updates will be submitted to the CPUC within 30 days of adoption of the plan.

REU services 47,273 meters within 61 square miles of service territory. REU has 763 miles of 12kV power lines, 72 miles of 115kV transmission lines, and 12 substations.

The Redding Power Plant and Redding Power Step-Up substation will not be considered during this plan since they are not distribution level facilities.

REU owns and operates eleven (11) 115kV to 12kV distribution substations and one (1) 13.8 kV to 115kV generation step up substation.

Five substations have loads that are critical to the community normally connected to them. Due to varying circumstances (planned or unplanned outages), all substations could have critical loads A. GOAL OF UTILITY SECURITY PLAN
B. DESCRIPTION OF REDDING ELECTRIC UTILITY
C. RESULTS OF UTILITY SECURITY PLAN ASSESSMENT
I. OVERVIEW
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connected and therefore this Plan will treat all of REU’s substations as “covered” under the ruling.

After assessment, no facilities required mitigation plans, however, optional security measures have been identified for future incorporation as time and budget allows.

REU has been operating its electric system for over 100 years. System protection for both public and asset safety has been paramount.

In order to support a statewide improvement of how utilities address distribution level physical security risks, the California Municipal Utilities Association (CMUA), which is the statewide trade association for publicly owned utilities (POUs), coordinated with the state’s investor owned utilities (IOUs) to develop a comprehensive Straw Proposal (Joint IOU/POU Straw Proposal) for a process to identify at-risk facilities and, if necessary, develop physical security mitigation plans. As a member of CMUA, REU staff participated in the development of the Joint IOU/POU Straw Proposal through a CMUA working group as well as through direct meetings with the IOUs. The Joint POU/IOU Straw Proposal set out a process for the following: (1) identifying if the utility has any high priority distribution facilities; (2) evaluating the potential risks to those high priority distribution facilities; (3) for the distribution facilities where the identified risks are not effectively mitigated through existing resilience/security measures, developing a mitigation plan; (4) obtaining thirdparty reviews of the mitigation plans; (5) adopting a document retention policy; (6) ensuring a review process established by the POU governing board; and (7) implementing information sharing protocols.

The Risk Assessment and Safety Analytics (RASA) unit of CPUC’s Safety and Enforcement Division filed a response to the Joint IOU/POU Straw Proposal that recommended various modifications and clarifications, including a six-step process. Additionally, RASA recommended that the utility mitigation plans include: (1) an assessment of supply chain vulnerabilities; (2) training programs for law enforcement and utility staff to improve communication during physical security events; and (3) an assessment of any nearby communication utility infrastructure that supports priority distribution substations.

REU is following the process outlined in California Senate Bill (SB) 699 and issuing this report at this time to reflect its existing commitment to safety and to protecting its customers’ investment by taking reasonable and cost-effective measures in an effort to safeguard key assets of its distribution system.

Article XI, Section 7 of the California Constitution provides certain POUs with the authority to own and operate their own utility systems and self-regulate their operations. REU as such is a municipal utility governed by the Redding City Council who serves as the Utility Commission.

According to the ruling, the goal is “to establish system-wide industry standards that are aimed at addressing the potential risks and threats associated with a long-term outage at a distribution facility on a statewide basis…”, “and…not designed to expand Commission [California Public Utility Commission] investigatory or penalty authority against the POUs.” REU is a department within the City of Redding. For security, crime prevention, and response, REU II. BACKGROUND
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is subordinate to the City of Redding Police Department (RPD).

The Joint IOU/POU Straw Proposal sought to support the creation of a risk management approach toward distribution system physical security, with appropriate considerations of resiliency, impact, and cost. In order to accomplish this risk-based approach, the Joint IOU/POU Straw Proposal identified several principles to guide the development of each individual utility’s program. These principles are the following:

1. Distribution systems are not subject to the same physical security risks and associated consequences, including threats of physical attack by terrorists, as the transmission system.

2. Distribution utilities will not be able to eliminate the risk of a physical attack occurring, but certain actions can be taken to reduce the risk or consequences, or both, of a significant attack.

3. A one-size-fits-all standard or rule will not work. Distribution utilities should have the flexibility to address physical security risks in a manner that works best for their systems and unique situations, consistent with a risk management approach.

4. Protecting the distribution system should consider both physical security protection and operational resiliency or redundancy.

5. The focus should not be on all Distribution Facilities, but only those that risk dictates would require additional measures.

6. Planning and coordination with the appropriate federal and state regulatory and law enforcement authorities will help prepare for attacks on the electrical distribution system and thereby help reduce or mitigate the potential consequences of such attacks.

Additional principles that guide REU include:

7. Increase the level of security through situational awareness and technology as provided by REU’s Wildfire Mitigation Plan – Technology Solutions Program (WMP-TSP) and the Emergency Operations Program (WMP-EOP).

8. Ensure the distribution system provides reliability through redundancy.

9. Provide opportunities to better coordinate with Law Enforcement, specifically RPD.

10. Incorporate the security features described in this plan at new or modified substations.

11. Ensure industry best practices are considered and implemented as appropriate and cost-effective.

III. PLAN DEVELOPMENT PROCESS
A. PHYSICAL SECURITY PRINCIPLES
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The major focus of this Plan is to address the risks and threats of a long-term outage to a distribution facility. Clearly, a long-term outage at any distribution facility poses numerous safety issues.

This Plan describes the range of activities that REU is taking or considering to protect its distribution assets, including its various programs, policies, and procedures. This Plan complies with the requirements of CPUC section 364 for publicly owned electric utilities to prepare a physical security plan by July 10, 2021, and every five years thereafter. The Plan will be iterative, promote continuous improvement, and represent best efforts to implement industry best practices in a prudent and reasonable manner.

REU utilized a multi-step process to develop this Utility Security Plan that is consistent with the Joint IOU/POU Straw Proposal and D.19-01-018. The relevant six steps of that process are the following:

REU staff prepared a Draft Utility Security Plan through the process set forth in Steps 1A, 1B, and 1C.

REU evaluated all distribution-level facilities in its service territory that are subject to its control to determine if any facility meets D.19-01-018’s definition of a “Covered Distribution Facility” using the seven factors identified in the Joint IOU/POU Straw Proposal.

For every individual Covered Distribution Facility identified pursuant to Step 1A, REU will perform an evaluation of the potential risks associated with a successful physical attack on that Covered Distribution Facility, and whether existing grid resiliency, back-up generation, and/or physical security measures appropriately mitigate identified risks.

In developing the Mitigation Plan, REU assessed the potential risks of our identified “Covered Distribution Facilities,” considered the existing protection, and developed further protection measures as necessary to increase facility resiliency.

For every Utility Security Plan cycle, REU will document the results of the identification process, risk B. Utility Security Plan Development Process
STEP 1: ASSESSMENT/PLAN DEVELOPMENT
STEP 1A: IDENTIFY COVERED DISTRIBUTION FACILITIES
STEP 1B: PERFORM RISK ASSESSMENT
STEP 1C: DEVELOP MITIGATION PLAN
STEP 2: THIRD-PARTY REVIEW
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assessment, and Mitigation Plan development performed pursuant to Steps 1A, 1B, and 1C. This documentation in combination with narrative description in Section IX below constitutes REU’s Draft Utility Security Plan. Each Draft Utility Security Plan is submitted to a Qualified Third-Party for Independent Review. The Qualified Third-Party Reviewer will then issue an evaluation that identifies any potential deficiencies in the Draft Utility Security Plan as well as recommendations for improvements. REU will then modify its plan to address any identified deficiencies or recommendations, or will document the reasons why any recommendations were not adopted.

REU’s Utility Security Plan will consist of the Draft Utility Security Plan, the non-confidential conclusions of the Qualified Third-Party Reviewer, and REU’s responses to the Qualified third-party review.

Under guidance of the California Public Utility Commission, validation of REU’s Plan was conducted by the City of Redding Deputy Fire Chief on August 28th, 2025, prior to approval from the City Council. A validation memo is attached as an Appendix to the Plan.

REU’s Utility Security Plan will be presented to and adopted by the Redding City Council at a public meeting.

REU will refine and update the Utility Security Plan as appropriate and as necessary to preserve plan integrity.

REU will repeat this six-step process at least once every five years.

As described in Section III, Step 1A, the Utility Security Plan identification process involves assessing all distribution-level facilities that are subject to the control of REU to determine which facilities are “Covered Distribution Facilities” and require a risk assessment. This Section describes the factors that REU used to evaluate its distribution facilities and the results of its evaluation.

The Joint IOU/POU Straw Proposal defines seven screening factors to determine if a facility is a “Covered Distribution Facility.” Some factors require additional definitions and/or clarifications in STEP 3: VALIDATION
STEP 4: ADOPTION
STEP 5: MAINTENANCE
STEP 6: REPEAT PROCESS
IV. IDENTIFICATION OF COVERED DISTRIBUTION FACILIITES (STEP 1A) A. IDENTIFICATION FACTORS
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order to be applied to REU’s facilities. The following Table provides the Joint IOU/POU Straw Proposal’s Factors as modified/clarified by REU.

Factor Joint IOU/POU Straw Proposal Description Additional Clarification 1 Distribution Facility necessary for crank path,
black start or capability essential to the
restoration of regional electricity service
that are not subject to the California
Independent System Operator’s (CAISO)
operational control and/or subject to North
American Electric Reliability Corporation
(NERC) Reliability Standard CIP-014-2 or its
successors
Facilities subject to CAISO operational
control or subject to NERC CIP 014-2 will be
excluded.
2 Distribution Facility that is the primary source
of electrical service to a military installation
essential to national security and/or
emergency response services (may include
certain airfields, command centers,
weapons stations, emergency supply
depots)
Only sites essential to national security or
emergency responses (For example, this
would exclude recruiting offices)
3 Distribution Facility that serves installations
necessary for the provision of regional
drinking water supplies and wastewater
services (may include certain aqueducts,
well fields, groundwater pumps, and
treatment plants)
Water treatment and wastewater
treatment with throughput equal to or
greater than one hundred (100) million
gallons per day (mgd).
4 Distribution Facility that serves a regional
public safety establishment (may include
County Emergency Operations Centers;
county sheriff’s department and major city
police department headquarters; major
state and county fire service headquarters;
county jails and state and federal prisons;
and 911 dispatch centers)
REU defines “regional public safety
establishment” as any of the following: (1)
Headquarters of a major police or fire
department serving 1.5 million population
with at least 1,000 sworn officers; (2)
County Sheriff’s Department
Headquarters; (3) County Emergency
Operations Center; (4) County/State Fire
headquarters; (5) a California State Prison;
(5) a United States Penitentiary; or (6) a
Federal Correctional Institute.
5 Distribution Facility that serves a major
transportation facility (may include
International Airport, Mega Seaport, other
air traffic control center, and international
border crossing)
In addition to the facilities listed in the
Joint IOU/POU Straw Proposal, REU defines
a “major transportation facility” as any
transportation facility that has (1) an
average of 600 or more flights per day; or
(2) over 50,000 passengers arriving or
departing per day.
6 Distribution Facility that serves as a Level 1
Trauma Center as designated by the Office
of Statewide Health Planning and
Development
No additional clarification.
7 Distribution Facility that serves over 60,000
meters
Applies to the collective sum of meters for
single point failures, which may include
downstream assets.

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In performing this identification analysis, REU assessed all distribution level facilities that are subject to its exclusive control, or if the facility is jointly owned, facilities where the joint ownership agreement identifies REU as the entity responsible for operation and maintenance. The specific types of facilities include the substations.

Table 1 Identification of “Covered Facilities”
Substation Facilities
Airport-Redding
Beltline
Canby
College View
East Redding
Eureka Way
Moore Road
Oregon Street
Sulphur Creek
Texas Springs
Waldon
B. IDENTIFICATION ANALYSIS
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Pursuant to the process identified in the Joint IOU/POU Straw Proposal and D.19-01-018, REU assessed the potential risks associated with a successful physical attack on each of the Covered Distribution Facilities identified in Section IV. For the purpose of this analysis, a physical attack is limited to the following: (1) theft; (2) vandalism; and (3) discharge of a firearm. A “successful physical attack” is limited to circumstances where a theft, vandalism, and/or the discharge of a firearm has directly led to the failure of any elements of the Covered Distribution Facility that are necessary to provide uninterrupted service to the specific load identified in Section IV.

In order to perform this risk analysis, REU evaluated the relative risk that (1) a physical attack on a Covered Distribution Facility will be successful considering the protective measures in place; or (2) the impacts of a successful attack will be mitigated due to resiliency and other measures in place.

D.19-01-018 identifies the specific mitigation measures that a utility should consider when performing this risk analysis. The following table lists these mitigation measures and provides REU’s additional clarifications that are necessary to apply these measures to REU’s territory.

Measure D.19-01-018 Description Additional Clarification 1 The existing system resiliency and/or
redundancy solutions (e.g., switching the
load to another substation or circuit
capable of serving the load, temporary
circuit ties, mobile generation and/or
storage solutions).

No additional clarification.
2 The availability of spare assets to restore a
particular load.

No additional clarification.
3 The existing physical security protections to
reasonably address the risk.

No additional clarification.
4 The potential for emergency responders to
identify and respond to an attack in a
timely manner.

Each facility is evaluated based on
the likelihood that a law enforcement
officer would generally be able to
arrive at the Covered Distribution
Facility within 15 minutes of a report
from the public of a break-in or
attack, or of REU notifying the law
enforcement agency of triggering of
an alarm at the facility.

V. RISK ASSESSMENT (STEP 1B)
A. METHODOLOGY
B. MITIGATION MEASURES
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5 Location and physical surroundings,
including proximity to gas pipelines and
geographical challenges, and impacts of
weather.

REU evaluated this element based on
the proximity of the Covered
Distribution Facility to populated areas
and the extent to which the interior of
the facility is shielded from view and
access due to walls, vegetation, or
other physical obstructions.
6 History of criminal activity at the Distribution
Facility and in the area.

REU evaluated the property crime
rates in the immediate vicinity of the
Covered Distribution Facility and
compared those crimes rates to
property crime rates for the county
and the state to determine if the area
is subject to a higher than average
incidence of property related crimes.
7 The availability of other sources of energy
to serve the load (e.g., customer owned
back-up generation or storage solutions).

No additional clarification.
8 The availability of alternative ways to meet
the health, safety, or security.

No additional clarification.
9 Requirements served by the load (e.g.,
back up command center or water
storage facility).

No additional clarification.

While all “covered” facilities have adequate physical security and resilience, there are additional technologies and cooperation underway in order to increase situational awareness by both utility operations and law enforcement. These enhancements have been defined and budgeted through REU’s Wildfire Mitigation Plan – Technology Solutions Program and Wildfire Mitigation Plan – Emergency Operations Program. Many of these measures were completed by the July 2021 deadline as listed below.

Within the Ruling, there are four strategies where this Plan, through the implementation of the WMP-TSP, and WMP-EOP, and planned capital improvements, will enhance our existing physical security measures:

1. Response Time – Measures to improve the potential for emergency responders to identify and respond to an attack in a timely manner;

2. Deterrent – Measures to discourage unauthorized entry or breach of the facility (e.g., cameras, lights);

3. Access – fences, gates, barriers, or other security devices; and

4. Coordination – Measures to collaborate with law enforcement.

The WMP-EOP includes the implementation of a Department Operations Center (DOC) where all of the information from the cameras, our utility operations SCADA system, GIS systems, and other fire awareness technology are gathered. The DOC becomes a physical place to coordinate with first responders, and the technology of the DOC provides virtual coordination to utility staff and first responders.

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security for REU’s distribution assets.
•
•
•
•
•
•
•
•

Based on the process described in the Joint IOU/POU Straw Proposal and the direction provided in D.19-01-018, REU has determined that of the five Covered Distribution Facilities identified in Section IV, the existing programs and measures effectively mitigate the risks of a physical attack for all of those Covered Distribution Facilities.
•
•
•
•
•
•
•
C. RISK ASSESSMENT
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•
•
•
•
o
o
o
As identified above, all of the Covered Distribution Facilities have existing measures sufficient to effectively mitigate the identified risks of a physical attack.

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transformers and even different substations. Redding’s system currently has spare substation capacity even during our highest peak periods. Due to this capacity, we have been able to take one or more entire substations offline in order to facilitate major system upgrades. That same approach could be used in the event of an unplanned issue.

Redding also has a new and unused substation transformer at the College View Substation that could be relocated and installed in the event of a catastrophic failure. Other inventory includes transformer bushings, CCVTs, protective relays, circuit breakers, and other critical components.

Pursuant to the process identified in the Joint IOU/POU Straw Proposal and D.19-01-018, REU has determined that for the Covered Distribution Facilities subject to REU’s control, the existing mitigation measures sufficiently reduce the risk of a physical security attack:
• Existing Resiliency
• Spare Assets
• Existing Physical Security
• Prompt Emergency Response
• Location
• Criminal History
• Backup Generation
• Alternate Solutions
D.19-01-018 specifies the following criteria for a Qualified Third-Party Reviewer:

Independence: A Qualified Third-Party Reviewer cannot be a division of the POU. A governmental entity can select as the Third-Party Reviewer another governmental entity within the same political subdivision, so long as the entity has the appropriate expertise, and is not a division of the POU that operates as a functional unit, i.e., a municipality could use its police department as its Third-Party Reviewer if it has the appropriate expertise.

Adequate Qualifications: A Qualified Third-Party Reviewer must be an entity or organization with electric industry physical security experience and whose review staff has appropriate physical security expertise, which means that it meets at least one of the following: (1) an entity or organization with at least one member who holds either an ASIS International Certified Protection Professional (CPP) or Physical Security Professional (PSP) certification; (2) an entity or organization with demonstrated law enforcement, government, or military physical security expertise; or (3) an entity or organization approved to do physical security assessments by the CPUC, Electric Reliability Organization, or similar electrical industry regulatory body.

REU has selected RPD as its Third-Party Reviewer. As a municipality, under D.19.01.018, RPD has the appropriate expertise to act as the Third-Party Reviewer.

VI. COVERED DISTRIBUTION FACILITY MITIGATION PLANS (STEP 1C) VII. INDEPENDENT EVALUATION AND RESPONSE (STEP 2)
A. REQUIREMENTS FOR QUALIFIED THIRD-PARTY REVIEW
B. IDENTIFICATION OF THIRD-PARTY REVIEWER
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RPD will conduct the independent review. REU coordinates with RPD and is subordinate for emergency and public safety issues. REU will work closely with RPD for situational awareness and other public safety issues related to this Plan. RPD will review this Plan and provide comments for consideration by REU. If any suggested changes are not incorporated, justification will be documented and included in Appendix A.

The Redding Police Department completed their review of REU’s Utility Security Plan and visited numerous substation sites. The Independent Review is attached as Appendix A.

REU met with the Third-Party Reviewer (RPD) and concurs with the recommendations listed in Appendix A.

Under guidance of the California Public Utility Commission, validation of REU’s Plan was conducted by the City of Redding Deputy Fire Chief prior to City Council approval and is attached as Appendix B.

REU concurs with both the third-party review and validation report conducted by security experts from the Redding Police and Redding Fire Departments.

In 2007 REU began implementing the substation modernization program that was completed in 2019. The program upgraded all substation controls and protection systems with standardized components. This approach reduced the quantity of spare parts needed as the same equipment is used in all substations for controls and protection.

REU has both a central warehouse as well as spare part inventories at each substation. There are spare parts for all substation components, including a 28MVA 115kV/12kV transformer and a 2000A 115kV SF6 circuit breaker, which are the highest cost and longest lead time items.

REU’s 115kV SF6 circuit breakers have a significant service life remaining, allowing for alternative technologies to mature before REU needs new breakers. CARB’s SF6 ruling will not impose major C. PUBLIC RESULTS OF THIRD-PARTY REVIEW
D. REU RESPONSE
VIII. VALIDATION (STEP 3)
A. SELECTION OF QUALIFIED AUTHORITY
B. RESULTS OF QUALIFIED AUTHORITY REVIEW
IX. NARRATIVE DESCRIPTIONS FOR UTILITY SECURITY PLAN
A. ASSET MANAGEMENT PROGRAM
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complications to REU’s service.

REU participates in the Electricity Information Sharing and Analysis Center (E-ISAC) for physical security notifications as well as coordination through various joint power authorities. REU is also a member of the California Utilities Emergency Association (CUEA) for fast response mutual aid.

REU conducts annual salary and compensation studies for recruitment and retention of highly qualified staff. By maintaining well-trained and qualified employees, REU is able to respond quickly to any equipment needs or repairs within the City of Redding substations. Inventory of equipment for substations is monitored and kept on hand to ensure a timely response to any issues that may arise. Since training for technical staff is a high priority, REU has a substation controls training station for testing new products and improving competency for existing equipment used in the substations.

REU performs weekly and monthly inspections of substation equipment, recording gas levels and operation counts, and noting other visible flaws that may need attention. A Work Order tracking system has been implemented to ensure the completion of open work orders. REU has also developed a GO-174 compliant inspection program and implemented the use of IR equipment.

REU’s DOC performs two emergency operations (EOPS) drills each year that incorporate substation security training with all departments in Redding Electric Utility.

It was previously identified that the citywide radio equipment on Southfork Mountain, west of the City of Redding, was subject to both wildfire and snowstorms, which impacted emergency radio communication within the City of Redding. REU has since replaced the citywide radio system for public safety and utility infrastructure. The new radio sites were placed within the city limits, reducing the impacts of poor weather conditions and public safety power shutoffs (PSPS).

B. WORKFORCE TRAINING AND RETENTION PROGRAM
C. PREVENTATIVE MAINTENANCE PLAN
D. PHYSICAL SECURITY EVENT TRAINING
E. COMMUNICATION INFRASTRUCTURE RISK ASSESSMENT
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As part of the risk mitigation to the substations, REU has pursued various security measures for installation.

F. FACILITY DESIGN FEATURES
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REVISION HISTORY
Version
Number
Revision
Date
Summary of Changes

1.0 6/1/21 Initial

2.0 6/1/26 Reviewed and revised report formatting. Removed Exhibits A and D through J; CPUC ruling, maps, SOPs, programs, and fence specifications.

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Attachment: REU Utility Security Plan 2026 - Redacted (4.5(a)--REU Utility Security Plan 2026)

APPENDIX A

THIRD-PARTY

REVIEW OF UTILITY

SECURITY PLAN
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Attachment: REU Utility Security Plan 2026 - Redacted (4.5(a)--REU Utility Security Plan 2026) DATE: August 12, 2025
TO: Director Nick Zettel, Redding Electric Utility
FROM: Captain Chris Smyrnos, Redding Police Department
SUBJECT: REU SB 699 (2014) Utility Security Plan Independent Review On July 30, 2025, I met with Redding Electric Utility (REU) Electric Program Supervisor (Substations) Clint Torrence and was provided with REU’s Utility Security Plan to conduct a thirdparty independent review. This independent review is required under California State Senate Bill (SB) 699 (2014). I have reviewed the Utility Security Plan in its entirety, conducted multiple physical inspections of several of the substations identified in the Plan, and will offer my recommendations.

I have been employed as a law enforcement officer with the City of Redding Police Department for the past 22 years and am currently a captain in charge of the Field Operations Division. My background includes work in all areas of policing, to include Patrol, Dispatch, and Administration.

I previously served in our Neighborhood Police Unit where we regularly met with business and other community members to discuss the physical security of buildings and property. I have investigated numerous crimes involving the unlawful entry of buildings and property and I am familiar with the means and methods used by criminals to commit these violations.

While conducting site survey assessments, several factors are taken into consideration that include:
overall security measures in place, ingress and egress routes, general construction, hazardous materials, internal/external security risks, crime prevention measures, target hardening, situational awareness, and future plans to improve security at these locations.

The City of Redding Utility Security Plan is a comprehensive plan which has been implemented and has taken numerous steps to protect the infrastructure of the City’s electric utility, specifically related to the substations noted below. The Plan clearly identifies the goals of ensuring the safety of its facilities as the top priority for REU. There are multiple REU facilities throughout the City that include a Power Control Center, a Department Operations Center, one (1) Generator Step-up substation, and eleven (11) distribution substations. Although the security requirements of SB 699 (2014) are specific to “Critical Distribution Facilities” I noted in REU’s Security Plan the intent is to ensure all distribution substations are treated the same as related to security. Below is a complete list of REU’s distribution substations.

Substation Facilities
Airport-Redding Substation
Beltline Substation
Canby Substation
College View Substation
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Attachment: REU Utility Security Plan 2026 - Redacted (4.5(a)--REU Utility Security Plan 2026) East Redding Substation
Eureka Way Substation
Moore Road Substation
Oregon Street Substation
Sulphur Creek Substation
Texas Springs Substation
Waldon Substation
-
-
-
-
-
-
-
-
-
Oregon Street and Waldon substations have additional security features in place.

After reviewing the Utility Security Plan and visiting several substations, I recommend continuing to make the improvements outlined in the plan.

As noted in the last security assessment,
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Attachment: REU Utility Security Plan 2026 - Redacted (4.5(a)--REU Utility Security Plan 2026) To complete my review of REU’s Utility Security Plan, I feel it is a detailed and comprehensive plan. The written Plan is comprised of several areas including:
- Overview
- Background
- Plan Development Process
- Identification of Covered Distribution Facilities
- Risk Assessment
- Covered Distribution Facility Mitigation Plans
- Independent Evaluation and Response
- Validation
- Narrative Descriptions for Utility Security Plan
- Appendices
In my opinion, REU’s written Utility Security Plan has adequately provided specific details, making this an effective security plan for the City’s electric utility distribution infrastructure. This Plan provides safety measures needed for critical infrastructure as identified through SB 699 (2014).

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Attachment: REU Utility Security Plan 2026 - Redacted (4.5(a)--REU Utility Security Plan 2026)

APPENDIX B

VALIDATION OF

UTILITY

SECURITY PLAN
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Attachment: REU Utility Security Plan 2026 - Redacted (4.5(a)--REU Utility Security Plan 2026)

INTERNAL

COMMUNICATION

DATE: August 28th, 2025
TO: Director Nick Zettel, Redding Electric Utility (REU) FROM: Deputy Fire Chief Jay Sumerlin, City of Redding
SUBJECT: REU SB 699 (2014) Utility Security Plan Validation as required by the California Public Utilities Commission (CPUC)
On August 13th, 2025, I received a copy of the REU Utility Security Plan, including an independent security review performed by Capt. Chris Smyrnos from the Redding Police Department. In addition, I made a site visit to a substation facility with REU Program Supervisor (Substations), Clint Torrence and found that the substation security complies with the written security plan. The REU substation security measures, as documented in the Plan, are both thorough and appropriate to mitigate criminal activity on or near the distribution facilities.

My knowledge and experience related to emergency operations as well as criminal activity provide me with the appropriate training to validate REU’s Utility Security Plan. I have been employed with theRedding Fire Department asthe Deputy FireChiefforsix years.Beforemy current position, I served another fire agency in Washington State for over twenty-seven years. I have many hours of training in Emergency Planning, Emergency Response to Terrorism, and I am a liaison to the Fusion Center. In addition, I held the Local Emergency Planning Committee Chair and have been part of an FBI Joint Terrorism workgroup in Washington State.

The REU Security plan is well written and comprehensive. In addition, the recommendations for capital improvements outlined in the plan and that of the independent evaluator will enhance site security, adding additional elements of threat detection that will aid law enforcement in protecting the power grid. Therefore, in my review of the REU Utility Security Plan and the independent review conducted by the Redding Police Department, I have determined that the plan and independent review are valid under the guidelines required by the CPUC decision for Publicly Owned Utilities.

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Attachment: REU Utility Security Plan 2026 - Redacted (4.5(a)--REU Utility Security Plan 2026)

CITY OF REDDING

REPORT TO THE CITY COUNCIL
Recommendation
Authorize and approve the following actions relative to Redding Electric Utility’s Customer Programs Portfolio for the Fiscal Year 2026-27:
(1) Update the Residential Electrification Rebate Program to add Heat Pump HVAC incentives and terminate the Heat Pump Clothes Dryer program; (2) Update the Commercial Electrification Rebate Program to add Heat Pump HVAC incentives and terminate the DC Fast Charging Station and Demand Credit Programs; and (3) Terminate Single-Family New Construction Electrification Program based on updated State Energy Code requirements
Fiscal Impact
There is no fiscal impact associated with this item. The Customer Program Portfolio for Fiscal Year 2026-27 is included in the adopted Electric Utility budget and reflects existing appropriations across Public Benefits, Greenhouse Gas, and Low Carbon Fuel Standard funding sources. The recommended program adjustments represent a reallocation of existing resources to more cost-effective measures and do not require a budget amendment. No additional appropriations are requested, and there are no changes to overall program funding levels or multi-year financial commitments.

Alternative Action
Council may reject staff's recommendation and provide alternative direction.

Background/Analysis
Staff has completed a comprehensive evaluation of the Customer Program Portfolio to assess program performance, participation levels, and cost-effectiveness consistent with the DemandMEETING DATE: May 5, 2026 ITEM NO. 4.5(b)
FROM:
***APPROVED BY***
[email protected] [email protected]
SUBJECT: 4.5(b)--Approve Redding Electric Utility's Recommended FY27 Customer Programs Portfolio Update
Nick Zettel, Director of
Redding Electric Utility
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Report to Redding City Council April 30, 2026
Re: 4.5(b)--Approve Redding Electric Utility's Recommended FY27 Customer Programs Portfolio Update Page 2
Side Management Integrated Resource Plan (DSM-IRP) approved by Council in September 2021.

The evaluation included a review of all current program offerings:
• Residential:
o Heat Pump Water Heater - $1,000;
o Heat Pump Clothes Dryer - $200;
o Single-Family New Construction - $1,800;
o Income-Qualified E-Bike Voucher - $1,150;
o Income-Qualified EV Voucher - $3,000; and
o Residential Electrification Assistance Program (REAP). • Commercial:
o Heat Pump Water Heater - $1,000;
o DC Fast Charging Rebate - $6,000; and
o Public Charging Demand Credit (varies).

The analysis indicates that program performance has varied across Redding Electric Utility’s portfolio, with the most successful programs demonstrating strong participation, costeffectiveness, and direct customer benefit. Transportation electrification programs, particularly electric vehicle and e-bike incentives, have seen high participation, reflecting strong customer demand and immediate, tangible benefits. The Residential Electrification Assistance Program (REAP) has also been successful in reaching income-qualified customers by providing a streamlined, direct-install approach that reduces barriers to participation and maximizes available external funding.

In contrast, programs such as heat pump clothes dryers and commercial DC fast charging incentives have experienced low participation due to higher upfront costs, limited financial return, and, in some cases, performance concerns. Overall, programs that offer clear cost savings, ease of participation, and alignment with market trends have proven to be the most effective.

Based on these findings, staff recommend discontinuing underperforming programs, including the heat pump clothes dryer program and DC fast charging station incentives, and adding residential and commercial heat pump HVAC incentives. HVAC incentives would improve installation affordability and deliver clear, immediate value to customers, an approach that consistently drives higher participation in our most utilized programs. Additionally, changes to the 2025 California Energy Code now require heat pump equipment in new single-family construction, eliminating the need for utility incentives for those measures. These changes align program offerings with customer demand, regulatory requirements, and cost-effectiveness criteria.

The proposed budget allocations result in a reduction of $175,000 in FY27 and $149,250 in FY28, as shown in Table 1 below. These funds will remain in the Public Benefits account and be available for other eligible programs. Pending approval of the recommended program updates, the budget allocations would be modified as follows to reflect the changes:

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Report to Redding City Council April 30, 2026
Re: 4.5(b)--Approve Redding Electric Utility's Recommended FY27 Customer Programs Portfolio Update Page 3
Program Name Funding Source
Approved
FY27
Budget
Proposed
FY27
Budget
Proposed
FY28
Budget
DSM-Admin Fees Public Benefits $15,000 $15,000 $15,750
Neighborly Licenses $15,000 $15,000 $15,750
Low-Income Programs Public Benefits $400,000 $400,000 $400,000 REAP $400,000 $400,000 $400,000
Building Electrification Public Benefits $225,000 $150,000 $175,000 Residential $100,000 $100,000 $125,000
Heat Pump Water Heater $50,000 $50,000 $62,500
Heat Pump Clothes Dryer $50,000 N/A N/A
Heat Pump HVAC N/A $50,000 $62,500
Commercial $125,000 $50,000 $50,000
New Construction $75,000 N/A N/A
Heat Pump Water Heater $50,000 $25,000 $25,000
Heat Pump HVAC N/A $25,000 $25,000
Transportation Electrification Low Carbon Fuel
Standards Program
275,000 $175,000 $175,000
EV Vouchers $150,000 $150,000 $150,000
E-Bikes $25,000 $25,000 $25,000
DC Fast Charging Stations $100,000 N/A N/A
Total 915,000 $740,000 $765,750
Table 1 – FY27 and FY28 Customer Program Budget Allocations The recommended updates improve the overall efficiency of the portfolio while maintaining support for high-performing programs such as electric vehicle and e-bike vouchers and REAP.

The adjustments also ensure that available funding sources are used effectively without increasing overall program costs or requiring additional budget authority.

Environmental Review
This is not a project defined under the California Environmental Quality Act, and no further action is required.

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
Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs
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Report to Redding City Council April 30, 2026
Re: 4.5(b)--Approve Redding Electric Utility's Recommended FY27 Customer Programs Portfolio Update Page 4
Previous Staff Report - 02-15-22 - 4.5(b)--Agreement with EGIA for Rebate Processing Services Previous Staff Report - 06-12-24 - 9.5(b)--Residential Electrification Assistance Program Previous Staff Report - 04.07.26 - GHG and Energy Procurement Program FY27 Customer Program Portfolio Update - 04.29.26
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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] btippin@cityofredding. org
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
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Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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
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Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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. 57
Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve Table of Contents i
Demand-Side Management

INTEGRATED RESOURCE PLAN
CITY OF REDDING | SEPTEMBER 2021
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Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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. 59
Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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. 60
Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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
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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
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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
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1.0 Executive Summary
This report documents the City of Redding Electric Utility Department’ s (REU) “ Demand- Side Management Integrated Resource Plan” ( DSM-IRP). The DSM-IRP uses a process similar to Redding’ s integrated resource planning process but is focused on Demand- Side ( behind the meter) resources rather than supply- side resources. The DSM- IRP process helps support REU’ s mission of providing reliable, costeffective service by identifying an optimal Demand- Side Management plan that achieves regulatory requirements, community and customer needs, and system reliability.

1.1 DSM-IRP PROCESS AND RECOMMENDATION
The DSM-IRP followed a five-step process described below.

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. 64
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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. 65
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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
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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 Calculator 1
is used to develop an avoided cost
forecast for natural gas rates.

The “ 2017 CMUA Savings Estimation POU Technical Reference Manual” 2is 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
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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.

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Figure 4-1: Timeline of Key Legislative Actions Impacting DSM-IRP Planning Packet Pg. 73
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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 programs to its customers and the CEC. This bill is foundational for POUs to treat energy efficiency and demand reductions as a priority resource over supply- side options so long as the demandside options are cost-effective feasible, and reliable.

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. 74
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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
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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, was signed by then-Governor Brown on September 10, 2018. SB 100 further modifies RPS requirements from 50 percent by 2030 ( set by SB 350) to 60 percent. It creates the policy of planning to meet all of the State’ s retail electricity supply with a mix of RPS-eligible and zero-carbon resources by December 31, 2045, thereby achieving a 100 percent clean energy supply. While the specific RPS targets change, the core language of public utility code sections related to energy efficiency and resource planning does not.

On September 10, 2018, SB 100 was signed into law. It accelerates the RPS obligations for retail sellers, including POUs, as follows:
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 originates from several sources. The three major categories of funding are from Public Benefits, Greenhouse Gas, and Low Carbon Fuel Standard funds. Each type of funding has specific regulations, reporting requirements, and other conditions that must be met in order to use them. The following sections summarize the funding types that Redding uses or are available to use. While this section will reference specific programs, details about each program are available in Section 4.2 of this document.

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 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 allowances 7 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 activities 8 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, 2019 9. 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 nonrate revenues or the City must develop a record indicating that the cost of these contracts is a reasonable cost of serving others, as by displacing demand for expensive marginal supplies, reducing load on REU facilities, increasing local resiliency in the event transmission of power from outside the City is interrupted, etc. Whether and to what extent such justifications are reasonable is a question for the City, its rate-making staff and consultants, and the City Council.”
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:
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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
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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.

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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.

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Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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 customers for the purchase or lease of new electric vehicles. Incentives are also available to help offset the installation costs of a commercial Level 2 vehicle charging station. To date, the City has issued seven rebates for commercial vehicle purchases and three rebates for commercial charging.

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

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.

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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. 93
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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 Packet Pg. 94
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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. 95
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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. 100 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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
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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.

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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. 104 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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.

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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
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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.

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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.

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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
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0.00 0.01

0.02 0.03

0.04 0.05

0.06 0.07

0.08 0.09

0.10 kWhAvoided Cost Forecast
Energy Transmission Losses Distribution Losses RPS Procurement Packet Pg. 111 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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 purchases from the DOE and WAPA. The STATE surcharge or Energy Commission tax was established in 1975 by the State Board of Equalization, pursuant to Sections 40031 et seq., of the Revenue and Taxation Code of the State of California, to provide funding for the CEC18.

The following charts show the rates and costs that were used in analysis. 18 City of Redding Schedule of Rates – Section A 21-22. https:// www.cityofredding. org/ Home/ ShowDocument? id=22899 Packet Pg. 112 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve Appendices 54

0.00 0.02

0.04 0.06

0.08 0.10

0.12 0.14

0.16 0.18
kWhREU 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
thermPG&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
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0.00 1.00

2.00 3.00

4.00 5.00

6.00 galGasoline Rate Forecast
Vehicle Gasoline

0.00 20.00

40.00 60.00

80.00 100.00
120.00
140.00
160.00
Carbon AllowanceCarbon Allowance Value
Forecast
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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)
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The Benefit ( Bp) and Cost ( Cp) terms are further defined as follows:

BP = 1 +
1Nt= 1 +
1 +
1=1 C =
1 + 1Nt=1
Where: BRt = Bill reductions in year
t Bit = Bill increases in year tTCt = Tax credits in year t INCt = Incentives paid to the participant by
the sponsoring utility inyear t3
PCt = Participant costs inyear tinclude: Initial
capital costs, including sales tax4
Ongoing operation and maintenance costs, including fuel costs Removal costs, less salvage
value Value ofthe customer' stime in arranging for installation, if significant PAat = Participant avoided
costs inyear tfor alternate fuel devices (costs
of devices not chosen) Abat = Avoided bill from alternate fuel in year tThe first summation in theBp 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 bycosting period to reflect load impacts and/orrate schedules, which vary substantially by time of dayand season. The formulas
for these variables are as follows: Ii=1 (
1 + Use BRt formula, but
with
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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
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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 = 1 + 1Nt=
1 + 1 +1= 1 CRIM =
1 +
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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:

Ii= 1 + (
1 UACat = ( Use UACt formula, but with marginal costs
and costing periods
appropriate for the alternate fuel utility.)
1)) Ii=1 + (
1))) 1 Where: Only terms not previously defined are included here.] ENit = Reduction innet energy use in costing period i in year t DNit = Reduction innet demand incosting period iin year t MC:

Eit = Marginal cost of energy incosting period iin year t MC:

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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 1 + 1N t=
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CTRC
1 + 1Nt=
1 LCRC 1 + 1Nt=1 IMP = 1
1 + d)t1 Nt=1 ( Where Iequals peak
period) All terms are defined inthe 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 thefirst and second
summations should be used. Formulas for the Program Administrator Cost Test (PACT) The PACT formulas for thenet
present value, the
benefit- cost ratio
and levelized cost
are
presented below: NPVpa = Bpa - Cpa BCRpa = Bpa/Cpa
LCpa = LCpa/IMP Where: NPVpa = Net present value of Program Administrator costs BCRpa = Benefit- cost ratio ofProgram Administrator benefits and costs LCpa = Levelized cost per unit
of Program Administrator costs of
the resource Bpa = Benefits of the program Cpa =
Costs ofthe
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Cpa =
1 + 1Nt=
1 LCpc = 1 + 1Nt=1All variables
are defined inthe 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 inthe TRC test, plus costs and benefits that affect society asa 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. Itis 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 isto indicate whether the benefits ofan 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 allthe impacts of the TRC test, plus the additional impacts on society. Note that the CaSPM refers to the SCT asa “variation” ofthe TRC test (CPUC 2001). Since then, many jurisdictions and many studies have referred to
the SCT asaseparate test with different implications. The SCT is useful foridentifying the total universe of economic impacts of investment in EE resources. Itis particularly apt for jurisdictions that have particular interest in arange of societal considerations, such as environmental or economic development concerns, in addition toaninterest in minimizing utility system and efficiency program participant costs. Formula for Calculating the Cost of Conserved Energy The CCE is analogous tothe often used levelized cost of energy orlevelized cost of electricity LCOE), Packet Pg. 122 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve Appendices 64
Where:
d is the discount rate or cost of capital used to value future expenses in current year dollars ( 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 togenerate the
electricity ( isthe energy generated in
yeary. Since energy efficiency represents acounterfactual amount of saved energy measured from abaseline rather than energy produced, the cost of conserved energy requires reference to abaseline. Specifically for a scenario, X, compared toa baseline Bwe can define: Where the superscripts refer tothe 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 Toolto Prioritize Energy Efficiency Investments”, NREL found this cost of conserved energy metric tobe superior to payback time, net present value of benefits, benefit- to-cost ratio, internal rate of return, and other cost metrics because itavoids explicitly assuming future energy prices. By instead expressing the cost as an equivalent energy price, itfacilitates comparison of measures tovolatile energy prices, other measures, and local ortime- 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 ifthey are used inthe payment stream in the above equation. Finally note that itis straightforward to approximate the payback time from CCE; if we take the measure lifetime as L and the energy price asPthe payback Packet Pg. 123 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve Appendices 65
NREL has apublicly available tool that calculates the cost of conserved energy for energy efficiency measures. When analyzing multiple energy efficiency measures, this tool createsastaged 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 toleast potential energy savings in that scenario [ i.e., 0 The NREL software tool creates estimates
of energy savings foranenergy efficiency measure or program portfolio by progressively comparing each measure with all lower CCE measures and reducing the savings toavoid “double counting” any
savings that are already attributed to lower CCE measures.

Methodology forIncluding
Savings ofNon-Electric Fuels inCost-Effectiveness Tests There are standard methodologies for considering savings of non-electric fuels inenergy 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 alarge 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 nonelectric fuels should be included inbenefit/ cost test calculations ininstances
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 Non-Electric Fuel Savings
Program Administrator Cost Test Non-electric
fuel savings are considered only for
fuels that the utility sells
tocustomers (
for example,
utilities that provide electricity and natural gas). Avoided costs Participant Test Yes, include
nonelectric fuel savings. Retail ratesRate Impact Measure Test Non-electric fuel savings are considered only for
fuels that the utility sells
tocustomers ( for example, utilities
that provide electricity and natural gas).

The Redding
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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.

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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 =
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Ratepayer Impact Measure Test
BRIM =
Nt= 1 +
CRIM =
1 + 1N t= 1 +
1 +1
E= 1
1 + 1Nt= 1
Total Resource Cost Test BTRC = 1 + 1Nt=
1 + 1 +1 1=CTRC =
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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. 128 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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 change in 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
Packet Pg. 129 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve Appendices 71

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. 130 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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. 131 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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 IRP@reupower. com.

Packet Pg. 132 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve Appendices 74
Packet Pg. 133 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU 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. 134 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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 Unit5 Tons (55-64
kBtuh)- 15 SEER 8.5 HSPF
5 Ton $ 1,171 ($ 944) ($ 497) 15
HP Split Unit-< 5 Tons ( 55
kBtuh)- 15 SEER9 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 rooftop1 Building $ 19,457 ($ 28,277) ($ 475) 30 Residential Solar rooftopstorage
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. 135 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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 MOTOR7 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, TIER2

ADVANCED
7 Power Strip $ 155 ($ 384) ($ 191) 5

REFRIGERANT CHARGE W/ COIL
CLEANING5 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 Discount1 Program $ 0 ($ 85,758) $01 Packet Pg. 136 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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 Replacement3 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 Forklift1 Forklift $ 43,829 $ 15,810 $ 145 10
ClassV Forklift1 Forklift $ 48,444 $ 17,556 $ 147 10
DHW Electrification to Baseline
Fuel Substitution - Gas to 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 Tractor1 Unit ($ 13,682) $ 36,136 $ 6,103 10 Electric Airport Belt Loader1 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. 137 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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 Dryer1 Dryer ($ 100) $ 474 $ 839 12 Gas Clothes Dryer to HP DryerMF
1 Dryer ($ 100) $ 474 $ 839 12
Gas to Electric Resistance Oven1 Oven $ 31 $ 127 $ 409 20 Gas to Electric Resistance OvenMF
1 Oven $ 18 $ 76 $ 409 20
Gas to Electric Resistance Stove1 Stove $ 42 $ 381 $ 478 20 Gas to Electric Resistance StoveMF
1 Stove $ 25 $ 229 $ 478 20
HP DHW Grocery1 Water Heater ($ 1,777) $ 8,107 $ 190 10 HP DHW Hotel1 Water Heater ($ 3,632) $ 13,208 $ 208 10
HP DHW Motel1 Water Heater ($ 1,489) $ 6,180 $ 191 10
HP DHW Office Large1 Water Heater ($ 1,602) $ 4,894 $ 206 10 HP DHW Office Small1 Water Heater $ 342 $ 1,466 $ 166 10 HP DHW Retail Single Story
Large
1 Water Heater ($ 527) $ 3,472 $ 164 10
HP DHW Retail Small1 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. 138 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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-PHEV1 Vehicle $ 6,895 $ 3,573 $ 168 12 Large Light Duty Vehicle-PHEVCOM
1 Vehicle $ 1,426 $ 4,076 $ 191 12
Light Duty Truck-BEV1 Vehicle ($ 25,999) $ 5,060 $ 138 12 Light Duty Truck-BEV-COM1 Vehicle ($ 35,711) $ 5,772 $ 158 12 Medium Light Duty Vehicle-BEV1 Vehicle ($ 1,046) $ 3,869 $ 115 12 Medium Light Duty Vehicle-BEVCOM
1 Vehicle ($ 6,840) $ 4,413 $ 131 12
Medium Light Duty VehiclePHEV
1 Vehicle $ 2,134 $ 2,711 $ 152 12
Medium Light Duty VehiclePHEV-COM
1 Vehicle ($ 2,819) $ 3,093 $ 173 12
Small Light Duty Vehicle-BEV1 Vehicle $ 9,106 $ 3,130 $ 122 12 Small Light Duty Vehicle-BEVCOM
1 Vehicle $ 1,029 $ 3,570 $ 139 12
Small Light Duty Vehicle- PHEV1 Vehicle $ 2,547 $ 2,056 $ 146 12 Small Light Duty Vehicle- PHEVCOM
1 Vehicle ($ 1,464) $ 2,345 $ 167 12
LED Street Light Replacement1 Program ($ 205,071) $ 91,637 $ 183 10 Packet Pg. 139 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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 02004006008001,
0001, 2001, 4001, 600
2031MWHFiscal 2022 2023 2024 2025 2026 2027 2028 2029 2030 Year (FY) 2021 Energy Effiency Goals vs. Estimated Net Energy Savings EnergyEfficiency Building Electrification Council Approved Goals (2021) Packet Pg. 140 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve

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***
dbeans@cityofredding. org btippin@cityofredding. org
SUBJECT: 4.5(a)-- Authorization to submit Redding Electric Utility's Energy Efficiency Potential Forecast Study.

Daniel Beans, Director of
Electric Utility
Packet Pg. 141 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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. 142 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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. 143 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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%
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2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 %
of Annual GWh SalesMWhRes Incremental Market Potential Non-Res Incremental Market Potential Total Incremental Potential asa % ofTotal
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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. 145 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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 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. 146 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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 es tablish statewide targets to support the state’ s goal to double energy efficiency savings by 2030. Furthermore, the results of the For ecast 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 gigawatt - hours, based on a three- year average commencing January 1, 2013. 0 500
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2031MWhApproved 2022 2023 2024 2025 2026 2027 2028 2029 2030 Goals and 2021 Market Potential
Goals approved by Council 2018 Market Potential 2021
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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
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2029MWhCEC 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Targets and Approved Goals
Goals approved by Council 2018 CEC Target
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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 Sol ar 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 increasing ly 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. 149 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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.
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2031MWhCurrent 2022 2023 2024 2025 2026 2027 2028 2029 2030 Goals and Recommended Goals
Goals approved by Council 2018 Recommended Goals
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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. 151 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve Table of Contents i
Black & Veatch Holding Company
2018. All rights
reserved. 2019 | INTEGRATED RESOURCE PLAN
Cityof Redding
Packet Pg. 152 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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. 153 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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. 154 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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. 155 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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. 156 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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. 157 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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. 158 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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. 159 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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
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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
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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.

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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. 3Incorporated 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
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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
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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, itis 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 in2026 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 itis 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. 170 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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
2030Emissions ( 2022 2023 2024 2025 2026 2027 2028 2029 MMTCO2e)
Year REDDING

POWER GREENHOUSE GAS

OUTLOOK SCENARIO
H Total Emissions
Goal
0%
10%
20%
30%
40%
50%
2030 60%2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2031RPS
Requirement (%) Year
RENEWABLE OUTLOOK Requirement Preferred Plan
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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. 173 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Executive Summary 1-13
Table 1-5 Detailed CPWC Results for the Preferred Plan, ScenarioH Packet Pg. 174 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Executive Summary 1-14
Table 1-6 Renewable Energy and REC Adequacy in the Preferred Plan, ScenarioH Packet Pg. 175 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU 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 resource options that, together, may constitute a long-term plan. Most commonly, detailed computer models that simulate utility operation on an hour-by-hour basis are used to develop the long-term costs of various Scenarios.

Eight Scenarios are developed and compared in an IRP analysis to determine the best long-range plan for the utility. Supply- side options typically include the evaluation ofconventional resources, RE resources, and distributed energy resources; however, in the IRP, only RE resources were evaluated based on the RE targets 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
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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.

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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. 178 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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 inthe SB 350 and PUB 9621 requirements.

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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 itis 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 in2030.4 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 inthe 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

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, 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.

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 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.

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- 200-2017- 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. 186 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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 ifthe original contract was for 15 years or more.

For the 2017- 2020 period, a minimum of 75 percent of the RE must be classified as a PCC1 resource and a maximum of 10 percent can be a PCC3 resource.

To meet the RPS requirements, the Council passed Resolution 2011-197 “Resolution of the City Council of the City of Redding to Revise the Renewable Portfolio Standard for the City of Redding’ s Electric System” on December 20, 2011. The resolution adopted RPS targets of 20 percent averaged) from 2011-2013; 25 percent in 2016, and 33 percent in 2020 and thereafter. 6 In meeting these targets, COR is allowed to apply Excess Procurement ( see Appendix E; Optimal Compliance Measures) from one compliance period to subsequent periods and the Council adopted a Cost Limitation such that the annual RPS expenditure should not require rate increases of more than 1.5 percent per year at any time during the life of the considered RPS procurement, and the 6 RPS Policies & Procedures, RPS- 001 Renewables Portfolio Standard Procurement and Enforcement Plan (Version 3) REU Resources Division, June 5, 2018, pp. 3-12.

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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. 190 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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 itis 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.

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 report annually to its customers and to the CEC its investment in energy efficiency and demand reduction programs.

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. Itis 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 itto 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, itis 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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3 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 in1991. 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, itis 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 itto 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. 199 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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, itis 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. 200 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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. 201 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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. 204 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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; itis 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 3-5shows 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. 205 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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 insupport 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, itis 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. 208 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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.

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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.
0 30
60 90
120
150
180
210
240
270
0 10
20 30
40 50
60 70
80 90
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Peak Demand (MW)Energy Sales (GWh)Average Monthly Energy Packet Pg. 211 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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
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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, itis 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.

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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%
5%
10%
15%
20%
25%
30%
35%
0 500
1000
1500
2000
2500
3000
3500
2017 2018 2019 2020 2021 2022
ITC (%) Solar Installations ( kW)Solar Installations ( kW) Packet Pg. 214 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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. 9It 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.

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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 ifthe 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.

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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 inits 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. 217 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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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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. 219 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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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AND AAEE PUC 9505 Target Redding AAEE Savings Achieved - 2015-2017 Redding Packet Pg. 220 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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 inutility 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. 221 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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. 222 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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, itis 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, itis 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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Net MWhProgram Year ANNUALEEPORTFOLIO MARKET POTENTIAL
BY END USE Non-Res Lighting Res Shell
Res Pool Pump Non-Res Cooling Res
Cooling Res Refrigeration Appliances Res Water Heating
Packet Pg. 223 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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 itis 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. 224 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve 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.

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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 itis anticipated that petrol vehicles will be replaced by EVs where and when it is practical.

COR has procured or help procure the following:

One electric bus for Redding Area Bus Authority – supplied monies to help RABA secure full grant amount
Three electric “ Mean Green” lawn mowers for the City of Redding Facilities Maintenance Department
Three electric carts for the City of Redding Police Department Two electric carts for the City of Redding Parks Department 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. 226 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve The Need for Additional Resources and Resource Options 6-1

6.0 The Need for Additional Resources and Resource Options The development of the load forecast allows a comparison of capacity requirements with existing and additional near-term resources. The result will highlight the adequacy of existing and nearterm additional resources and their ability to meet energy needs and comply with RE requirements during the 2018- 2037 planning period; this determination will be done for a scenario that contemplates continued operation of existing resources to meet future requirements.

Sufficient existing and near- term capacity resources exist to meet its projected peak demand and planning reserve requirements over the study period. However, additional RE resources will be necessary to meet RPS requirements and added RE resources will promote further GHG emission reductions. The need for additional renewable resources established in this section leads to the development of several Scenarios that are modeled and presented from an economic cost and RE perspective in Section 8.

6.1 EXISTING SYSTEM CAPACITY BALANCE
Capacity balance is shown in Figure 6-1 for the Existing System Scenario. This Scenario assumes no additions to the system are added through 2037 and reflects the expiration of the Big Horn wind purchase after 2031.

The figure indicates sufficient generation capacity exists to meet capacity needs throughout the planning horizon; the excess generation capacity ranges from a high of 38 MW to 10 MW during the 2018-2037 planning period. (Section 8 will present a similar capacity balance for the preferred plan; the figure is a simplified summary of the CRAT table included in Appendix A for the preferred option.)
Packet Pg. 227 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve The Need for Additional Resources and Resource Options 6-2 Figure 6-1 Capacity Sufficiency for the “ Existing System” Scenario, 2018- 2037 0 50
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6 Western Whiskeytown Big Horn Peak Load Planning
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6.2 EXISTING SYSTEM SCENARIO ENERGY REQUIREMENTS AND RENEWABLE

ENERGY LEVELS
Figure 6-1 provides additional information about the adequacy of the Existing System Scenario.

Table 6-1 indicates the total generation from resources, purchases, and sales that occur under the Existing System Scenario. As seen in Figure 6-2, the Station’ s 1x1 and 2x1 natural- gas fueled combined cycle units are most active in the power market over the planning period, and market purchases account for a significant amount of COR’ s energy requirements.

Figure 6-3 indicates the ability to meet its RE targets if no additional RE resources are added. In the figure, a year in which a shortfall in RE occurs is displayed by the stacked bar chart not meeting the red line.

As indicated in Figure 6-3, if no additional RE resources are added, RE targets starting in 2019, would not be met and the shortfall would continue through 2037. The shortfall would become increasingly severe, such that in 2030, only a 30 percent RE contribution would be received as compared to the 50 percent requirement. For the remainder of the 2037 study period, the shortage would dramatically increase once the Big Horn wind PPA expiries in 2031. Looking at the REC outlook, itis clear that the Existing System Scenario results in a deficiency of REC.

Figure 6-3 is very significant because it shows that, while the Existing System can meet capacity requirements and energy needs, itis not acceptable in that it does not comply with the obligations necessary to meet the targeted RE levels.

Figure 6-4 lists data pertaining to the GHG emissions under the Existing System Scenario. These emissions are compared to the proposed CARB limits under the low and high targets proposed by CARB staff in July 2018. The 2030 targets proposed are between 57,000 (low target) and 101,000 high target) of MTCO2e. Figure 6-4 indicates that under the Existing System Scenario, 2030 emissions are projected to be105,408 MTCO2e; this is in excess of the low and high targets proposed by CARB staff. This means that, from an environment and GHG ( and RE) perspective, the Existing System Scenario is not a viable plan.

Based on the shortcomings of the Existing System Scenario, several additional Scenarios were developed and evaluated as part of this IRP process. The objective was to balance resource adequacy, economics, stakeholder input, and meet obligations for RE and GHG reductions. These scenarios are presented in Section 8.

Packet Pg. 229 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve The Need for Additional Resources and Resource Options 6- 4 Table 6-1 Existing System Energy Sufficiency
Packet Pg. 230 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU The Need for Additional Resources and Resource Options 6-5 Figure 6-2 Energy Balance for the Existing System, Scenario G 0 100,000
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Packet Pg. 231 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU The Need for Additional Resources and Resource Options 6-6 Figure 6-3 REC Adequacy in Existing System Scenario
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EXISTING SYSTEM Big Horn Western Small Whiskeytown Banked RPS Packet Pg. 232 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU The Need for Additional Resources and Resource Options 6-7 Figure 6-4 Existing System Scenario Projected GHG Emissions 0 20,000
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Packet Pg. 233 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU The Need for Additional Resources and Resource Options 6-8

6.3 SUPPLY SIDE RESOURCE TECHNOLOGY COSTS AND CHARACTERISTICS In consideration of the objective of achieving low electric costs, long-term reliability, and fuel diversity to lower risk of dependence on a single source, a list of multiple resource options were developed to evaluate as candidates to serve future resource needs. All incremental options considered in the analysis were RE solar or wind resources. These options are discussed further in this section.

6.3.1 Renewable Energy
To obtain indicative RE PPA pricing, several locations were selected for modeling, with alternative price and performance estimates developed for each location. In total, five different modeling profiles were developed for different solar projects representing potential project sizes that could be located within each region. The projects are described in Table 6-2 and were sized to reflect sample projects of differing proportions.

The solar projects in Table 6-2 were assumed to consist of single axis tracking systems ( SAT). SAT systems tend to have better output in the late afternoons when generation is often the most valuable. The solar production for each location was modeled with SAM’ s Detailed PV modeling module and used weather data representing each location. The inverter loading ratio (ratio of module capacity to inverter capacity) was assumed to be 1.3. Typical SAT systems have inverts of

1.25 to 1.30 today and are optimized for project location. The capacity factor was calculated based on the AC project capacity. Additionally, the long-term degradation of the systems was assumed to be 0.7 percent per year.

It is noted that, independent of, and prior to the IRP process, analysis indicated that the addition of a 10 MW PV PPA in the 2021 timeframe would be beneficial. The project is being pursued through the NCPA. While the exact cost and performance will be determined through competitive bidding, the Site 1 project in Table 6-2 is considered to be proxy for the project. The Project is currently in Phase Two ( out of three) in development and this phase includes all pre-construction engineering, design, and environmental review tasks. On June 5, 2018, the Council approved the Phase Two activities that include the following actions:
1) Authorize participation in Phase Two of NCPA Solar Project 1 including, approving the Second Phase Agreement, the Power Management and Administrative Services Agreement, and the Amended and Restated Facilities Agreement; 2) Authorize the City Manager, or designee, to execute the agreements and any associated amendments and administer the project;
3) Adopt Resolution approving the 34th Amendment to City Budget Resolution No. 2017- 057 transferring needed funds for phase two. 13 Due to the relatively advanced stage of this project, all scenarios developed in Section 8 of this IRP incorporate the 10 MW PV project in 2021, with the exception of the Existing System Scenario. The economic analysis in Section 8 will demonstrate that the addition of the project not only contributes to achieving RE and GHG targets, but the project is cost-effective when compared to the Existing System Scenario. For this reason, the addition of the Solar Project in 2021 (and not the 13 City of Redding Report to the City Council, 4.5(a)— Authorization to Participate in Phase Two of NCPA Solar Project 1, Daniel Beans, Director of Electric Utility,
Packet Pg. 234 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve The Need for Additional Resources and Resource Options 6-9 Existing System Scenario) is considered to be the Base Case Scenario, and additional scenarios are developed around this near- term addition to meet RPS requirements and to evaluate the economics of additional resource options.

Table 6-2 Solar Systems and Modeled Performance

SITE LOCATION

PROJECT

CAPACITY
MWAC]
MODULE

CAPACITY
MWDC)

CAPACITY
FACTOR
DC)

CAPACITY
FACTOR
AC)

DEGRADATION
ANNUAL %)
1 North CA 10 13 21.5% 27.9% 0.7%
2 OR/ CA 100 130 20.8% 27.0% 0.7%
3 Arizona 100 130 25.5% 33.1% 0.7%
4 Central Valley 20 26 23.5% 30.6% 0.7%
5 Central Valley 100 130 22.9% 29.8% 0.7%
Source: Black & Veatch
Two wind projects were also evaluated as developments within possible future planning Scenarios.

The wind project assumptions are shown in Table 6-3. Wind projects now tend to be 100 MW or more, so it was not realistic to model smaller wind farms. It was assumed, however, that COR could purchase less than the full output of a large wind farm.

Wind capacity factors were derived from analysis performed for various geographic energy zones as part of the California Public Utility Commission’ s (CPUC) Renewable Portfolio Standard ( RPS) Calculator effort, to which Black & Veatch contributed. No degradation was assumed for wind farms.

The location of the solar and wind projects used in this RFP is shown in Figure 6-5. The location impacts the project capacity factor, capital cost, and transmission cost.

Packet Pg. 235 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve The Need for Additional Resources and Resource Options 6-10 Table 6-3 Wind Systems and Modeled Performance

SITE LOCATION

PROJECT

CAPACITY
MWAC]

CAPACITY

FACTOR ( AC)

DEGRADATION
ANNUAL %)
6 North CA 100 30.0% 0.0%
7 Arizona 200 30.0% 0.0%
Source: Black & Veatch
Figure 6-5 Location of Renewable Resource Project Candidate Units in the IRP Packet Pg. 236 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve The Need for Additional Resources and Resource Options 6-11

6.3.1.1 Cost Assumptions
RE project costs vary depending on system size, year installed, and location costs. The capital costs provided represents an all-in installed cost, or total capital expenditures ( CAPEX), including EPC14, owner' s costs, developer fees, interconnection, financing fees, and construction interest. This total cost is used as the capital cost when calculating the levelized cost of energy ( LCOE) generation. As part of the CAPEX, Black & Veatch also assumed that interconnection costs for solar and wind would vary by size, as shown in Table 6-4 and Table 6-5. Actual interconnection cost will be highly site specific. The total operating expenses, including O& M, property taxes, equipment replacement, and other administrative costs assumed in the analysis are generic and do not attempt to capture locational differences across the various project’ s sites.

Table 6-4 2020 Cost Assumptions for Solar SAT Systems ( Nominal$)

SITE LOCATION

PROJECT

CAPACITY
MWAC]
INTERCONNECTION
COST
M)

CAPITAL
COST
KWAC]

CAPITAL
COST
KWDC]
FIXED
O& M
COSTS
KWAC]
FIXED
O& M
ESCALATION

ANNUAL)
1 North CA 10 $ 0.5 $ 1,770 $ 1,362 $ 26 2.5%
2 OR/ CA 100 $ 5 $ 1,440 $ 1,108 $ 26 2.5%
3 Arizona 100 $ 5 $ 1,380 $ 1,062 $ 26 2.5%
4 Central Valley 20 $ 1 $ 1,730 $ 1,331 $ 26 2.5%
5 Central Valley 100 $ 5 $ 1,580 $ 1,215 $ 26 2.5%
Source: Black & Veatch
Table 6-5 2020 Cost Assumptions for Wind Systems ( Nominal$)

SITE LOCATION

PROJECT

CAPACITY
MWAC]

CAPITAL COST
KWAC]

FIXED O& M
COSTS
KWAC]

FIXED O& M

ESCALATION

ANNUAL)
6 North CA 100 $ 1,700 $ 35 2.5%
7 Arizona 200 $ 1,550 $ 35 2.5%
Source: Black & Veatch
14 EPC stands for “ engineer, procure, and construct”. Additional trade tariffs were imposed on imported solar cells in January of 2018, resulting in increases in module costs. However, the new tariffs are set to decline over the next four years, and module costs are expected to continue to fall. Thus, module costs are assumed to be simila r to 2017 levels by 2020.

Packet Pg. 237 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve The Need for Additional Resources and Resource Options 6-12 To determine the estimated cost of 2030 projects, it was assumed that capital costs would decline 1 percent per year in real terms for wind and solar technologies amid an inflationary environment of 2.5 percent per year. The escalated technology costs for 2030 are shown in Table 6-6 and Table 6-7 below.

Table 6-6 2030 Cost Assumptions for Solar SAT Systems ( Nominal$)

SITE LOCATION

PROJECT

CAPACITY
MWAC]
INTERCONNECTION
COST
M)

CAPITAL
COST
KWAC]

CAPITAL
COST
KWDC]
FIXED
O& M
COSTS
KWAC]

FIXED O& M

ESCALATION

ANNUAL)
1 North CA 10 $ 0.64 $ 2,049 $ 1,576 $ 33 2.5%
2 OR/ CA 100 $ 6.4 $ 1,667 $ 1,282 $ 33 2.5%
3 Arizona 100 $ 6.4 $ 1,598 $ 1,229 $ 33 2.5%
4 Central Valley 20 $ 1.28 $ 2,003 $ 1,541 $ 33 2.5%
5 Central Valley 100 $ 6.4 $ 1,829 $ 1,407 $ 33 2.5%
Source: Black & Veatch
Table 6-7 2030 Cost Assumptions for Wind Systems ( Nominal$)

SITE LOCATION

PROJECT

CAPACITY
MWAC]

CAPITAL
COST
KWAC]

FIXED O& M
COSTS
KWAC]

FIXED O& M

ESCALATION

ANNUAL)
6 North CA 100 $ 1,968 $ 45 2.5%
7 Arizona 200 $ 1,794 $ 45 2.5%
Source: Black & Veatch

6.3.1.2 Levelized Cost of Energy (LCOE)
To model the LCOE of each of the representative projects, Black & Veatch assumed a third- party independent power producer ( IPP) structure where PPA pricing is based on the LCOE. A number of financial incentives were incorporated into the modeling, as discussed below. As a tax exempt entity, COR cannot directly use the investment tax credit, however, by contracting with an IPP under a PPA, COR can share in the tax credit through the PPA pricing.

Packet Pg. 238 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve The Need for Additional Resources and Resource Options 6-13

6.3.1.3 Financial Assumptions
The 2018 Tax Reform bill changed the federal corporate tax rate from 35 percent to 21 percent while still allowing state income taxes to be tax deductible, resulting in the composite income taxes for California, Arizona, and Oregon as shown below.

Table 6-8 Assumed Federal and State Income Tax Rates

CALIFORNIA ARIZONA OREGON
Federal Income Tax 21% 21% 21%
State Income Tax 8.84% 6.97% 7.70%
Composite Income Tax 28.0% 26.5% 27.1%
Source: Black & Veatch

6.3.1.4 Tax Credits
The Consolidated Appropriations Act, signed in December 2015, extended the investment tax credits ITC) that apply to solar technologies and wind. Wind project owners can opt for the ITC in lieu of the production tax credit (PTC), which was also extended, but wind typically benefits more from PTC at better wind sites. The credits do decline over time, as shown in Table 6-9. The availability of tax credits shapes the strategy of purchasing wind and solar from private developers through a PPA instead of self-building since COR is a tax exempt.

ITC is a credit taken as a percentage against the capital cost of a RE system. The capital cost basis allowed is defined by the IRS. If the project owner opts for the ITC, the depreciation basis will need to be reduced by 50 percent of the ITC (e.g., 30 percent ITC, therefore => Depreciation Basis would be 85 percent of the capital cost) PTC is an inflation- adjusted per-kilowatt- hour ( kWh) tax credit for electricity generated by qualified energy resources and sold by the taxpayer to an unrelated person during the taxable year. The duration of the credit is 10 years after the date the facility is placed in service.

For 2020, solar projects can receive a 30 percent ITC against the total capital cost of their project, if the project “begins construction” by the end of 2019. For this analysis, it was assumed that the solar projects begin construction in 2019 and come on-line in 2020 to take advantage of the 30 percent ITC. Otherwise the incentive drops to 26 percent in 2020. By 2030, the ITC drops to 10 percent.

While wind project owners can select between the ITC and the PTC, the drop in the benefits of the ITC occur sooner, so by 2020, there are no incentives available for wind, unless construction started in 2019. In this case, it was assumed that construction starts in 2019 and wind owners take advantage of the PTC at a rate of $9 per MWh, escalated at inflation for the first 10 years of the project. By 2030, wind does not receive any production tax credits, as displayed in Table 6-9.

Packet Pg. 239 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve The Need for Additional Resources and Resource Options 6-14 Table 6-9 Tax Credit Assumptions

TECHNOLOGY

CONSTRUCTION
START)
12/ 31/ 19 12/ 31/ 20 12/ 31/ 21 12/ 31/ 22 FUTURE
YEARS
Solar PV 30% 26% 22% 10% 10%
Large Wind
Estimated PTC per
MWh)
9 N/ A N/ A N/ A N/ A
Source: Black & Veatch

6.3.1.5 Accelerated Depreciation
Historically, solar and wind projects have been able to utilize a 5-year accelerated depreciation schedule ( MACRS) that helped improve project economics. The 2018 Tax Reform bill now allows RE projects to take 100 percent tax depreciation on the total cost of the project in year 1. Industry experts believe, while quite generous, few investors would be able to take full advantage of this new depreciation schedule, so the modeling in the analysis assumed a 5-year MACRS schedule, where approximately 90 percent of the total capital cost would be depreciable.

6.3.1.6 Cost of Capital
IPPs have multiple methods of funding RE projects. For modeling purposes, it was assumed that the debt/ equity structure for both solar and wind projects would be as shown Table 6-10. In recent years, the cost of capital for RE projects has dropped substantially in terms of lower interest rates on debt as well as lower equity return requirements by investors. The debt term was modeled for 20 years, while the life of the project was 25 years in the analysis performed.

Table 6-10 Cost of Capital Assumptions for Solar and Wind

FINANCIAL FACTOR SOLAR WIND
Debt Percentage 50 60
Debt Interest Rate ( percent) 4.5% 4.5%
Debt term ( Years) 20 20
Economic life (Years) 25 25
Cost of equity ( after tax) ( percent) 10% 10%
Source: Black & Veatch

6.3.1.7 Levelized Cost of Energy
The LCOE for the renewable projects with commercial on-line dates in 2020 and 2030 resulting from the input assumptions and analysis are shown in the tables below. As displayed in Table 6-11, Table 6-12, and Table 6-13, the LCOE represents what is assumed to be a fixed price, 25-year PPA.

Packet Pg. 240 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve The Need for Additional Resources and Resource Options 6-15 Renewable Energy Projects LCOE ( Nominal$) 2020 COD
Table 6-11 Renewable Energy Projects LCOE ( Nominal$) 2020 COD SITE
TECHNOLOGY LOCATION

PROJECT

CAPACITY
MWAC]

CAPACITY
FACTOR
AC)

CAPITAL
COST
KWAC]
ITC OR
PTC

NOMINAL
LCOE
RESULT
MWH)
1 Solar SAT North CA 10 27.9% $ 1,770 30% $ 53
2 Solar SAT OR/ CA 100 27.0% $ 1,440 30% $ 48
3 Solar SAT Arizona 100 33.1% $ 1,380 30% $ 38
4 Solar SAT Central Valley 1 20 30.6% $ 1,730 30% $ 48
5 Solar SAT Central Valley 2 100 29.8% $ 1,580 30% $ 46 6 Wind North CA 100 30.0% $ 1,700 $ 9/ MWh $ 60
7 Wind Arizona 200 30.0% $ 1,550 $ 9/ MWh $ 56
Source: Black & Veatch
Table 6-12 Renewable Energy Projects LCOE ( Nominal$) 2030 COD SITE
TECHNOLOGY LOCATION

PROJECT

CAPACITY
MWAC]

CAPACITY
FACTOR
AC)

CAPITAL
COST
KWAC]
ITC OR
PTC

NOMINAL
LCOE
MWH)
1 Solar SAT North CA 10 27.9% $ 2,049 10% $ 85
2 Solar SAT OR/ CA 100 27.0% $ 1,667 10% $ 75
3 Solar SAT Arizona 100 33.1% $ 1,598 10% $ 59
4 Solar SAT Central Valley 1 20 30.6% $ 2,003 10% $ 76
5 Solar SAT Central Valley 2 100 29.8% $ 1,829 10% $ 73 6 Wind North CA 100 33.1% $ 1,968 $ 0 $ 75
7 Wind Arizona 200 33.1% $ 1,794 $ 0 $ 70
Source: Black & Veatch
Since the ITC and PTC vary year by year, the following table shows the year by year LCOE for projects that come on-line for that year, assuming construction start dates of the previous year.

Packet Pg. 241 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve The Need for Additional Resources and Resource Options 6-16 Table 6-13 Project Nominal LCOE 2020 to 2030
YEAR 1 2 3 4 5 6 7
Solar SAT Solar SAT Solar SAT Solar SAT Solar SAT Wind Wind North CA OR/ CA Arizona
Central
Valley
Central
Valley North CA Arizona
2020 $ 53 $ 48 $ 38 $ 48 $ 46 $ 60 $ 56
2021 $ 58 $ 52 $ 41 $ 52 $ 50 $ 70 $ 65
2022 $ 65 $ 57 $ 45 $ 58 $ 55 $ 70 $ 66
2023 $ 75 $ 66 $ 52 $ 67 $ 65 $ 71 $ 66
2024 $ 77 $ 67 $ 53 $ 69 $ 66 $ 71 $ 67
2025 $ 78 $ 69 $ 54 $ 70 $ 67 $ 72 $ 67
2026 $ 79 $ 70 $ 55 $ 71 $ 68 $ 72 $ 68
2027 $ 81 $ 71 $ 56 $ 72 $ 69 $ 73 $ 68
2028 $ 82 $ 72 $ 57 $ 73 $ 70 $ 73 $ 69
2029 $ 83 $ 73 $ 58 $ 75 $ 71 $ 74 $ 69
2030 $ 85 $ 75 $ 59 $ 76 $ 73 $ 75 $ 70
Source: Black & Veatch
Note: The above cost only includes energy; transmission is not included

6.4 ENERGY EFFICIENCY

6.4.1 Building Standards
California has continually increased the energy efficiency of new construction and appliances since the Warren Alquist Act (Act) of 1974. These efficiency standards ( Title 24) have since been updated to mandate Zero Net Energy ( ZNE) residential new construction starting in 2020. ZNE homes require energy efficiency that will be achieved through implementing a high efficiency envelope ( insulation, windows, etc.), and efficient Heating, Ventilation, and Air Conditioning HVAC) units. The remaining energy consumption must be offset by distributed generation, predominantly rooftop solar generation, sized so that the annual building consumption ( excluding natural gas) is approximately equal to building’ s electricity generation. Effective in 2030, all new commercial construction will also be required to meet the ZNE standard. In addition, the Act requires that fifty percent of existing commercial buildings be retrofitted to ZNE by 2030 and fifty percent of new major renovations of state buildings be ZNE compliant by 2025. The increased energy efficiency standards will contribute to a lack of load growth in future years.

Packet Pg. 242 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve The Need for Additional Resources and Resource Options 6-17

6.5 ENERGY STORAGE
As explained in Section 5.5, COR has been heavily involved in the TES market for years and has invested more than $6 million in TES technologies.

Technology changes have led to increasing interest in the use of batteries in the energy market.

Battery Energy Storage Systems ( BESS), which can be independent systems not linked to EVs, can be useful in a broad variety of grid-beneficial applications including use as a capacity resource, for load shifting, and frequency and voltage support.

The CEC has recommended that POU’ s consider the role of storage in addressing over- generation of RE when solar energy production exceeds local demand. In California, this can occur particularly during the daytime peak solar production periods. If the excess RE is used to charge a BESS system, the stored energy can be used during the evening ramping period and allowing utilities to avoid GHG emissions that would otherwise be produced ifthe energy demand was met by conventional thermal resources.

A major benefit of BESS is the ability to provide multiple services in one location to meet the needs of the grid. BESS can be configured to respond to grid needs in less than a second, thereby providing the capability for a faster response time than conventional generation resources. Some of the concepts being considered for BESS applications include:

Load Shifting: In load shifting applications, BESS are charged with lower priced energy which can help mitigate curtailment of excess renewable generation— when renewable generation exceeds demand— and the stored energy used at a later time, such as during evening ramping periods.

Peaking Supply: The power output capacity of BESS can be used to meet capacity resource adequacy requirements and replace conventional peaking capacity to provide short-term power needs during periods of peak demand.

Frequency Regulation and Voltage Support: BESS can be used to mitigate load and generation imbalances and maintain grid frequency and voltage needed for grid stability.

Spinning Reserve: BESS can be utilized to provide energy needs within 10 minutes, as an alternative to conventional generation that must be kept online and synchronized to the grid in anticipation of a need.

Firming of Intermittent Resources: BESS can be used to “firm” energy production of a variable energy resource— such as solar or wind generation— and provide a more predictable energy profile to the grid.

Transmission Upgrade Deferral: BESS may offer a way to defer or avoid transmission upgrades.

BESS applications are often selected for primary use in either a power or energy application. Power applications tend to be of shorter duration ( approximately 15 minutes to one hour) with operational profiles involving frequent rapid responses or cycles. Energy applications generally require longer duration ( approximately 1 hour or more).

Packet Pg. 243 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve The Need for Additional Resources and Resource Options 6-18

6.5.1 Performance and Cost Assumptions for Energy Storage Because lithium ion batteries are widely accepted as a proven technology for BESS applications, a lithium ion battery was chosen as the technology for this analysis. Table 6-14 highlights the BESS performance parameters used in the IRP analysis.

Table 6-14 Representative Performance Parameters for Lithium Ion Battery Systems

PARAMETER LI-ION
Facility Capacity Power Rating, MW 5
Discharge Duration at Rated Capacity, hours 4
Facility Energy Rating, MWh1 20
Round- Trip Efficiency, percent 85%
Estimated life, cycles ~ 5,000
Installed Levelized Capital Cost, $/ kW- yr2 $ 533
Fixed O& M Costs, $/ kW- yr $ 20
Variable O& M Costs, $/ kWh ( charge or discharge) $ 0.001 to 0.005 Notes:

1. The rating is based on installed project size.

2. Battery cost scales with MWh, whereas balance of plant and PCS costs tend to scale with power ( MW). Because of this, installed costs tend to have a wide array of values.

Source: Black & Veatch
Packet Pg. 244 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve Modeling Assumptions, Tools, and Methodology 7-1

7.0 Modeling Assumptions, Tools, and Methodology

7.1 MODELING ASSUMPTIONS

7.1.1 Load forecasts
The load forecast used for the IRP analysis was presented in Table 4-3 of Section 4.0.

7.1.2 Natural Gas and Average Market Prices
For the purposes of economic analysis, a projection of natural gas fuel prices and power energy prices were required ( see Figure 7-1, Figure 7-2, and Figure 7-3). The methods used to produce these prices by Ascend Analytics Curve Developer and PowerSimm software suite are described in Section 7.2 below.

Spot market prices for gas and power are simulated in the PowerSimm construct. Table 7-1 demonstrates the average annual simulated spot gas and power prices ( mean, 5th, and 95th percentiles of the simulations) delivered to PG& E City Gate and NP-15 respectively. These prices drive model given that COR dispatches their own units, or transacts with these markets, to find the most economic electricity supply.

Table 7-1 Natural Gas and Market Energy Prices Assumed in the IRP YEAR

SPOT NATURAL GAS PG& E CG AVG ANNUAL POWER MARKET
ENERGY PRICE* $

AVG CARBON ALLOWANCE
PRICE $
5% MEAN 95% 5% MEAN 95% 5% MEAN 95%
2018 2.72 2.91 3.13 35.96 40.38 45.61 14.84 14.99 15.16 2019 2.34 2.82 3.38 25.37 38.50 55.91 15.02 15.59 16.17 2020 2.28 2.80 3.39 26.25 41.36 64.10 15.25 16.23 17.31 2021 2.27 2.87 3.67 25.25 45.05 70.64 15.70 17.06 18.60 2022 2.18 2.96 3.86 26.17 47.75 74.57 17.65 18.86 20.23 2023 2.27 3.05 3.90 29.02 49.74 74.64 18.98 20.27 21.75 2024 2.12 3.16 4.34 30.93 51.59 81.67 20.40 21.79 23.38 2025 2.26 3.25 4.61 30.83 53.87 83.02 21.93 23.43 25.14 2026 2.27 3.34 4.71 31.66 55.76 86.98 23.57 25.18 27.02 2027 2.04 3.42 5.27 35.24 57.73 91.15 25.34 27.07 29.05 2028 1.98 3.51 5.59 35.17 59.78 93.66 27.24 29.10 31.23 2029 2.25 3.59 5.55 38.30 61.94 90.38 29.29 31.29 33.57 2030 1.91 3.68 5.77 37.64 64.21 100.48 31.48 33.63 36.08 2031 1.89 3.81 6.83 36.04 66.57 117.45 33.84 36.15 38.79 2032 2.02 3.90 6.83 38.81 69.07 115.55 36.38 38.87 41.70 Packet Pg. 245 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve Modeling Assumptions, Tools, and Methodology 7-2
YEAR

SPOT NATURAL GAS PG& E CG AVG ANNUAL POWER MARKET
ENERGY PRICE* $

AVG CARBON ALLOWANCE
PRICE $
5% MEAN 95% 5% MEAN 95% 5% MEAN 95%
2033 2.05 4.00 6.52 42.49 71.69 111.11 39.11 41.78 44.83 2034 1.95 4.10 7.03 39.63 74.41 121.38 42.04 44.91 48.19 2035 2.04 4.20 8.55 44.99 77.31 123.11 45.20 48.28 51.80 2036 2.04 4.31 8.24 48.73 80.34 123.41 48.59 51.90 55.69 2037 1.95 4.41 7.76 51.97 83.56 126.09 52.23 55.80 59.87 The Average Market Energy Price data in the last three columns are average annual hourly values.

Source: Black & Veatch
Figure 7-1 Power Forward Price
0 20
40 60
80 100
120
140
20182019202020212022202320242025202620272028202920302031203220332034203520362037Price ($/ MWh)
Year POWER
FORWARD PRICE POWER | P5 POWER | MEAN
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Figure 7-2 Gas Forward Price
Figure 7-3 Carbon Allowance Forward Price
0 1
2 3
4 5
6 7
8 9
20182019202020212022202320242025202620272028202920302031203220332034203520362037Price ($/ dth)
Year GAS
FORWARD PRICE GAS | P5 GAS | MEAN
GAS |
P95
0 10
20 30
40 50
60 7020182019202020212022202320242025202620272028202920302031203220332034203520362037Price ($/ allowance)Year
CARBON ALLOWANCE FORWARD PRICE CARBON ALLOWANCE | P5 CARBON ALLOWANCE | Packet Pg. 247 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve Modeling Assumptions, Tools, and Methodology 7-4
As reported in Table 7-1, these prices are annual equivalents or averages for the stated year. When performing the economic analysis of this report, the actual analysis prices used were hourly, on/ offpeak, daily, or monthly as was appropriate and included the natural gas market, electric power market ( NP15, COB), and California Carbon Allowance ( CCA) market.

7.1.3 Discount Rate
The analysis utilized a 2.5 percent discount rate. This discount rate was applied to future costs and revenues to determine estimated future net costs of serving load on a net present value basis.

7.2 ASCEND ANALYTICS PLANNING SUITE – TOOLS FOR MODERN RESOURCE

PLANNING
The Ascend Analytics Planning Suite is a set of software programs consisting of Curve Developer CurveDev) market harvesting and modeling, PowerSimm Planner ( PowerSimm) production cost model for system operations simulation, among other tools. The suite is designed, maintained, and supported by Ascend Analytics and was used for the IRP.

7.2.1 CurveDev and PowerSimm – Tools for Market Prices
Forecasting market prices by CurveDev begins by harvesting forward price quotes from the Intercontinental Exchange ( ICE). This is done for markets available at PG& E City Gate, California Carbon Allowance, NP15, and MidC. As there are no ICE quotes for COB, this value is derived from historical relationships to the NP15 and MidC price. Beyond the time horizon covered by the harvested broker quotes to the end of the study period, a 2.5% annual increase is used for gas and energy prices and 7.5% for carbon prices. Together, the broker harvest and post processing represents a single price curve for each market and are summarized annually in Table 7-1.

Studies in this report use harvested data as of June 25, 2018. PowerSimm will pull in the latest price curve from CurveDev up until this date, and use this as the mean for all simulated prices. For stochastic studies, PowerSimm also pulls in the 90 business days prior to the June 25th harvest date of the study when simulating prices. The 90 days of data is used to calculate the correlations between markets and dates, as well as the volatility of each market. This information is then used to simulate a distribution of prices that matches the historical correlations and volatilities, while still scaling the mean to the most recent price curve. These prices were rolled- up to produce the annual data as presented in Table 7-1.

Additional information on CurveDev and PowerSimm’ s methods and capabilities can be found in Appendix D.

7.2.2 CurveDev and PowerSimm – Tools for Modern Resource Planning Combined, CurveDev and PowerSimm tools form a platform for modern resource planning, in an era of increasing uncertainty in electricity supply driven by the deployment of variable renewable generation. The uncertainty in electric supply brings with it risk that will affect the cost and viability of potential projects needed to meet state-mandated renewable portfolio standards. Not only does PowerSimm provide the appropriate mean cost estimates under multiple correlated scenarios, but is also able to monetize ( assess an equivalent cost of) the risk. This assessment, known as the “risk premium”, can be equated to an insurance premium used to protect against uncertainty that could be caused by weather, market prices of gas or power, and variability of nondispatchable resources. While PowerSimm can report an abundance of useful output data, for Packet Pg. 248 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve Modeling Assumptions, Tools, and Methodology 7-5
economic assessments of potential candidate plans, itis sufficient to compare the system annual mean cost and the annual risk premium together.

Additional information on CurveDev and PowerSimm’ s method and capabilities can be found in Appendix D.

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8.0 Evaluation and Results
In this section, the economic analysis performed for the system is described. In general, the analysis is aimed at minimizing system costs— a sentiment that was of utmost importance to Stakeholders— while also meeting the several targets that have arisen under the state RPS and environmental policies described in Section 2, including the following goals:

Low cost and reliability
50 percent renewable energy by 2030 and meet intermediate goals per SB 350 Increased energy efficiency per SB 350
2030 GHG within the July 2018 CARB staff recommended targets ( low of 57,000 MTCO2e and high of 101,000 MTCO2e per SB 350)
Based upon past experience and Stakeholder input, an important target has been identified:
selecting a resource planning scenario that reasonably balances multiple types of RE resources.

Specifically, to achieve a balance in PV and wind resources over the planning horizon is vital as a balanced portfolio may reduce risks associated with over- reliance on a single technology. Portfolio diversity protects customers from contingencies such as market fuel and power prices, fuel and power availability, as well as changes to the load and resources. Also, a balanced wind and solar PV energy generation combination is deemed to be a better fit to hourly system energy demand profile than a plan heavily weighted toward either wind or solar. A balanced wind and solar PV energy generation profile is also considered prudent for a number of other reasons.

As one example, just as there is a reluctance to develop additional hydroelectric renewable resources because of concerns about possible adverse impacts on fish and other wildlife, some industry stakeholders and several COR Stakeholders have expressed concerns about over reliance on wind generation due to the possible impact on avian populations. Thus, in addition to the above bulleted items, staff developed and ranked Scenarios with the objective of achieving a balance between wind and PV RE generation.

8.1 ECONOMIC EVALUATION FRAMEWORK
The aim of the economic analysis is to meet these requirements while minimizing the long-term present worth cost of incremental power to customers. This cost is commonly called the cumulative present worth cost (CPWC) of a Scenario. The CPWC includes “ incremental” costs, which refers to the power supply costs incurred directly or indirectly through interaction with the market and power producers during the 2018- 2037 evaluation period. Incremental costs do not include existing fixed costs or common costs such as general and administrative costs, as these are considered sunk costs or costs common to all future Scenarios. However, the capital costs associated with new resources are included as are variable costs incurred ( directly or indirectly) in a resource plan.

Due to reliance upon interaction with the power market, itis important that an economic analysis projecting future power costs model interaction with the market and project the costs and revenues associated with purchases from, or sales into, the market. A plan that relies heavily on assumed market purchases may incur risks associated with future power energy market prices increasing at a rate higher than assumed in the analysis. Therefore, to reduce the risk of higher retail rates associated with unexpected increases in future power energy market prices, plans with lower Packet Pg. 250 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve Evaluation and Results 8-2
market purchases are preferable to plans with higher market purchases, all other factors being equal. Details about the modeling approach used to derive the CPWC are included in Section 8.2.

8.2 SCENARIO ANALYSIS
In the IRP, the CPWCs of several competing Scenarios were determined. A Scenario included one or more of seven potential solar and wind projects, first developed in Section 7, having the specifications summarized in Table 8-1. The selection of projects listed in Table 8-1 was based on the understanding from Section 6 that additional renewable resources will be required.

A total of eight Scenarios were evaluated through detailed modeling; these consisted of the Existing System Scenario ( identified as Scenario G), plus seven Scenarios that involved adding RE resources.

The various Scenarios evaluated are displayed in Table 8-2, which also lists the specific projects from comprising each Scenario.

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Table 8-1 RPS Project Definitions
PROJECT 1 PROJECT 2 PROJECT 3 PROJECT 4 PROJECT 5 PROJECT 6 PROJECT 7 Name Local PV
w/ Bat
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 &
VERBS 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%
Source: Black & Veatch
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Table 8-2 IRP Scenario and Projects

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
Levelized Cost of Energy ( LCOE) figures at stated at the plant bus bar and do not include transmission costs.

Source: Black & Veatch
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8.3 CONSOLIDATED RESULTS
The consolidated CPWC results for the Scenarios evaluated are shown in Table 8-3. To facilitate interpretation, the results are presented as a “heat map” in which the best Scenario in any category is highlighted in dark green; Scenarios considered favorable but not the best in a category are shaded light green; Scenarios that are significantly less favorable than the best in a category are shaded light yellow, followed by rose colored and red colored shades signifying increasingly significant and unfavorable results compared to the best Scenario result in the category.

The Base Case Scenario in which 10 MW of local solar is added in 2021 is listed first in Table 8-3.

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). There are two key conclusions related to the Base Case Scenario.

First, by comparing the Base Case with the Existing System Scenario ( Scenario G) CPWC, itis clear that the Base Case has a lower CPWC. This helps to illustrate why adding the Solar Project ( from Table 8-1) provides benefit from a cost perspective and also by adding RE benefits over Scenario G.

This comparison explains the reason for identifying the Solar Project as the next resource addition and why this is considered to be the Base Case rather than the Existing System Scenario.

A second, very important conclusion about the Base Case Scenario is that, even though it achieves a higher RE percentage than Scenario G, it nevertheless falls short of meeting the 2030 RE target of 50 percent. In fact, it achieves only 33 percent RE level in 2030 and also for the 2018-2030 period.

Moreover, the Base Case Scenario is still very heavily reliant on wind energy ( 71 percent of all RE) even with the addition of the Solar Project in 2021. Due to these results, the Base Case is understood to contain the next project to be undertaken, but itis not considered to be the final mix of resources over the planning horizon. The need for additional renewable resources on the system beyond the 2021 solar addition led to the development of the remaining Scenarios in Table 8-3. All of these, with the exception of Scenario G, involved the 2021 Solar Project, but also included additional RE resources after 2021.

Scenario H is the only plan identified in Table 8-3 as having green or light green shading in all categories. Based on the overarching objective to balance economics, reliability, portfolio diversity, and environmental targets, Scenario H is considered to be the best overall plan in the 2019 IRP.

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 ( in some years, the plan relies on banked RECs); and has a reasonably balanced mix of RE contributions— 53 percent from wind and 36 percent from solar.

In terms of lowest CPWC, Scenario D may appear on its surface to be the best plan as itis both costeffective and at 65 percent RE, it exceeds the mandated 2030 RE levels. However, this plan falls short in 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.

Scenario C also achieves a very high percentage of RE in 2030 (65 percent) but is not economic and also suffers from a high reliance on wind energy. Scenario F is economically competitive and achieves 59 percent RE contribution, but the scenario is over-reliant on wind energy resources.

Scenario E reaches 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 Packet Pg. 254 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve Evaluation and Results 8-6
and reaches 61 percent in 2030. Nevertheless, the drawback of Scenario E is one of economics, as it achieves the favorable RE characteristics at a cost that is 6.5 percent higher than the least cost Scenario D.

In least cost planning studies, itis common to consider a CPWC difference between two plans to be in the 1.5 percent to 2.5 percent range. The uncertainties involved in the SB 350 IRPs arguably increases this range, and a CPWC difference of 2.0 percent to 3.0 percent can reasonably be considered within the margin of error. 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 the preferred plan, Scenario H.

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Table 8-3 Heat 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.

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8.4 DETAILED RESULTS OF THE PREFERRED EXPANSION PLAN

8.4.1 Capacity and Energy Adequacy of Scenario H
Capacity balance for the preferred Scenario H expansion plan is shown in Figure 8-1. This figure is organized in the same manner as was done for the Existing System Scenario in Section 6.

As seen at the top of Figure 8-1 and Figure 8-2, existing sufficient resources and generation capacity are expected to meet energy needs throughout the planning horizon under Scenario H. The excess generation capacity ranges from 18 MW in 2018 to 43 MW in 2034 the planning period, once the RE projects are stated in terms of their firm capacity.

Table 8-4, Figure 8-1, and Figure 8-2 reflect the addition of three renewable projects, the 2021 Solar Project ( rated at 10 MW of which 3.5 MW is firm), a second solar project in 2026 having a firm output of 21 MW, and a 2034 wind project having a firm output of 7 MW. The information in this table is simplified but reflects the comprehensive CRAT table included in Appendix A.

Table 8-4 and Figure 8-2 shows how the energy requirements will be met under Scenario H. Under the recommended plan, the 1x1 and 2x1 combined cycle projects are the only two generating units producing a significant amount of energy at the Station, while all RE projects are actively producing energy consumed by customers or sold into the market. Due to this market interaction, net sales are projected into the market starting in 2026 and for several of the subsequent years in planning period. It is seen in the table that the final two RE projects coming on-line in 2026 and 2034 are important contributors to the energy balance as soon as they go into commercial operation.

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Figure 8-1 Capacity Balance in the Preferred Expansion Plan, Scenario H 0 50
100
150
200
250
300
350
2037Capacity ( 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 MW)
Year

CAPACITY SCENARIO
H Unit 1 Unit 2 Unit 3 Unit 4 Unit
5 Unit 6 Western Whiskeytown Big Horn Local
PV CV PV NorCal Wind REU Peak Load Planning
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Figure 8-2 Loads and Resources Balance in the Preferred Expansion Plan, Scenario H 200000
0 200000
400000
600000
800000
1000000
2037Energy ( 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 MWh)
Year LOAD AND

RESOURCES SCENARIO
H Western Whiskeytown Big Horn Unit 1 Unit
2 Unit 3 Unit 5 Unit 6 1x1
2x1 Local PV CV PV NorCal Wind Net Market REU
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Table 8-4 Energy Balance in the Preferred Expansion Plan, ScenarioH Packet Pg. 260 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Evaluation and Results 8-12

8.4.2 Renewable Energy and GHG Emissions of Scenario H
The addition of three RE projects in the recommended expansion plan, Scenario H, results in the ability to meet the RPS requirements. This is shown in Figure 8-3 that reports the RE outlook during the 2018 through 2037 planning period.

As seen in the figure, Scenario H remains at or above the goal in all years with the allowances of banking RECs. Importantly, the figure shows that Scenario H maintains a positive REC balance over the entire planning period, meaning that, on the whole, the plan exceeds the cumulative RE credits during the planning horizon and never goes into a cumulative REC deficit in any year during the 2018- 2037 planning horizon.

Figure 8-4 shows a projection of the GHG emissions in the form of MTCO2e during the planning horizon for the preferred expansion plan, Scenario H. Under this plan, there would be 99,335 MTCO2e in 2030. This level of emissions is below the high target of 101,000 in the CARB staff recommendations for the COR ( although itis above the 57,000 MTCO2e set as the lower end of the targeted range).

8.4.3 The Detailed CPWC Sheet for Scenario H
Table 8-3 presented the CPWC of all Scenarios. The CPWC shown for Scenario H was $580,966,000.

In Table 8-8, the derivation of the Scenario H CPWC is shown by year and by the components that contribute to the CPWC of all plans.

At the top of Table 8-5, information about the addition of new renewable projects is listed. The project list for Scenario H includes the 10 MW local PV project added in 2021, the 60 MW PV project in 2026, and the 65 MW wind project added in 2034 (all MW ratings are maximum plant output ratings, reductions are made to arrive at the firm ratings used in the capacity balance). The first year production and levelized cost of energy ( LCOE) is also listed in this portion of the table.

Below the input section in Table 8-5 are the yearly cost and revenue components that comprise the annual costs. The categories include supply costs related to self-generation plus power purchase costs ( from PPAs and the spot market) and wholesale sales revenue earned from sales into the market. The Total System Cost listed as a column heading includes the net cost once supply costs and wholesale sales are taken into account. Thus, in2018, the Total System Cost is $35.5 million.

Over time, the Total System Costs for each year trend upward, although there are years in which significant market revenues results in a decrease from the previous year ( see for example, the year 2031). In the final year of the planning horizon, the 2037 Total System Cost is projected to be $47.1 million.

To derive the CPWC of Scenario H, the Total System Cost for each year is discounted to 2018 at the assumed 2.5 percent discount rate and summed. By the end of the planning horizon, the CPWC of Scenario H is $580.966 million as seen in the bottom of the CPWC column in Table 8-5 and as also reported in Table 8-3.

8.4.4 Additional Discussion of Merits, Scenario H
Section 8.3 explained the development of the competing Scenarios considered and the rationale for selecting Scenario H as the preferred option. Some additional discussion of the Scenario H merits is provided in this section.

While the CEC Guidelines only require the future planning studies to extend to 2030, consideration of additional years beyond 2030 were encouraged. A 20-year plan that has the benefit of Packet Pg. 261 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve Evaluation and Results 8-13
measuring the relative merits of various Scenarios beyond the next 12 years until 2030. While the 2037 difference in CPWC between Scenario H and the least cost option, Scenario D from Table 8-3, is 2.8 percent, at the 2030 mark, the difference is only 2.1 percent and well within the range of uncertainty ( while there is no definitive rule, in this analysis, CPWC results within no more than 2 to 3 percent are considered to be insignificant differences between plans). Thus, the CPWC results should be interpreted as showing that, while Scenario D is lower in absolute CPWC, the difference with Scenario H is on the margin of insignificance and while the CPWC is an important factor in plan selection, additional non-economic factors play a vital role in the selection of the preferred Scenario.

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, with the next project 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 Scenario D, however, offers less flexibility in that, beyond the 2021 solar addition that is also added in Scenario H, the plan consists of only one 85 MW wind addition in 2026. While economical to add this large wind project, the plan results inan unbalanced mix of solar and wind generation as indicated by the 84 percent wind and 6 percent solar mix of RE for Scenario D as indicated in Table 8-3. It is important to achieve a balance in PV and wind resources over the planning horizon, since a balanced portfolio may reduce risks associated with over- reliance on a single technology. Also, a balanced wind and solar PV energy generation combination is deemed to be a better fit to the hourly system energy demand profile than a plan heavily weighted toward either wind or solar.

As noted earlier, due to reliance upon interaction with the power market, this analysis considers future interactions and estimates the costs and revenues associated with purchases from, or sales into, the market. A plan that relies heavily on assumed market purchases or sales may incur risks associated with future power energy market prices increasing at a rate higher than assumed in the analysis if more heavily reliant on market purchases, or risks associated with future power energy market prices being lower than assumed in the analysis if more heavily reliant on market sales.

Therefore, to reduce the risk of higher retail rates associated with unexpected increases or decreases in future power energy market prices, plans with lower exposure to market volatility are preferable to plans with higher market purchases or sales, assuming others factors are equal.

Scenario H is also better than Scenario D with regards to the heavy reliance on wind and the end effects of meeting future RE targets. Scenario D fails to meet the RPS requirements just beyond the planning horizon, ultimately requiring the procurement of an additional renewable project prior to the end of the planning window. For example, Scenario D relies on banked RECs during the last three years of the planning period and additional renewable resources would be required to Packet Pg. 262 Attachment: Previous Staff Report - 09-21-21 - 4.5(e)--2021 DSM-IRP Report and Adjustments to REU Customer Programs (4.5(b)--Approve Evaluation and Results 8-14
maintain RPS compliance after 2039. In contrast, Scenario H is above 50 percent in each of the final four years ( 2034- 2037) and meets ongoing RPS requirements in 2038 and beyond.

In summary, Scenario H is expected to have a slightly higher cost than Scenario D, however, it carries less exposure to extreme market conditions, brings less regulatory risk, provides better hourly production, and exhibits more resource diversity, thus meeting portfolio objectives.

Figure 8-3 Renewable Energy and REC Adequacy in the Preferred Expansion Plan, Scenario H 0 50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
450,000
RPS
Requirement (RECs)
Year RENEWABLE
OUTLOOK SCENARIO HBig Horn Western Small
Whiskeytown Local PV CV PV NorCal Wind Using Banked
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Figure 8-4 GHG Emissions in the Preferred Expansion Plan, Scenario H Figure 8-5 Renewable Outlook
0 20,000
40,000
60,000
80,000
100,000
120,000
140,000
2030Emissions ( 2022 2023 2024 2025 2026 2027 2028 2029 MMTCO2e)
Year REDDING

POWER GREENHOUSE GAS

OUTLOOK SCENARIO
H Total Emissions
Goal
0%
10%
20%
30%
40%
50%
2030 60%2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2031RPS
Requirement (%) Year
RENEWABLE OUTLOOK Requirement Preferred Plan
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Table 8-5 Detailed CPWC Results for the Preferred Expansion Plan, Scenario H Desc: Optimized Balanced Mix
Size ( MW) First Year
Local PV w/Bat 10 2021 24,440 58.00$
CPW Discount Rate: 2.5% NorCal/ OR PV
Base Year for CPW $: 2018 AZ PV
Westland PV
CV PV 60 2026 156,629 68.00$
NorCal/ OR Wind 65 2034 170,820 77.08$
AZ Wind
Cumulative
System REU Risk and Total REU Wind Generation Total Present Present Transmitted Cost of Sup- Generation Hydro Wind Import Purchase + Generation Sales Sales Export System Worth Worth Year Energy ply Energy Costs Costs Costs Costs Production Revenue Revenue Revenue Revenue Cost Cost Cost GWh ($ 1,000)($ 1,000)($ 1,000)($ 1,000)($ 1,000)($ 1,000)($ 1,000)($ 1,000)($ 1,000)($ 1,000)($ 1,000)($ 1,000)($ 1,000) 2018 767.535 25,503 10,251 4,973 12,239 7,936 60,901 10,561 7,379 5,272 2,178 35,512 35,512 35,512 2019 767.119 24,411 7,054 6,525 12,239 8,909 59,138 7,217 8,523 5,026 1,883 36,488 35,598 71,110 2020 766.632 26,082 8,398 6,788 12,265 8,673 62,206 8,875 9,086 5,478 2,705 36,061 34,324 105,434 2021 763.013 28,227 10,298 7,061 13,507 8,030 67,124 11,286 9,724 7,253 4,425 34,436 31,978 137,411 2022 761.992 29,596 12,496 7,346 13,498 8,286 71,222 14,816 10,247 7,604 7,017 31,538 28,572 165,983 2023 762.510 30,646 13,419 7,642 13,489 9,480 74,676 15,817 10,539 7,855 7,337 33,128 29,281 195,264 2024 767.096 31,690 13,842 7,950 13,509 9,710 76,701 17,128 10,674 8,089 7,981 32,830 28,309 223,573 2025 768.249 32,901 14,180 8,270 13,472 10,713 79,536 18,771 11,150 8,355 8,818 32,442 27,293 250,866 2026 770.535 33,848 13,665 8,603 26,418 9,654 92,188 19,234 11,303 15,315 13,789 32,548 26,714 277,579 2027 773.399 34,785 13,915 8,950 26,414 9,581 93,645 20,329 11,582 15,641 14,364 31,730 25,407 302,986 2028 778.734 35,897 14,153 9,310 26,472 12,050 97,882 19,612 11,838 16,005 13,603 36,824 28,767 331,753 2029 780.769 36,894 15,090 9,685 26,414 12,365 100,449 20,050 12,247 16,360 13,720 38,071 29,015 360,769 2030 782.358 37,897 15,478 10,075 26,420 13,522 103,391 21,901 12,145 16,705 15,001 37,640 27,987 388,756 2031 784.084 38,917 13,482 10,481 23,663 11,895 98,438 24,517 13,203 15,689 16,398 28,631 20,770 409,525 2032 788.191 40,085 15,846 10,903 14,235 17,429 98,499 24,411 13,222 9,172 10,779 40,915 28,957 438,482 2033 789.134 41,143 16,279 11,343 14,217 18,957 101,938 24,413 13,239 9,391 10,512 44,383 30,645 469,127 2034 792.330 42,320 13,158 11,799 32,393 14,010 113,681 24,901 14,097 18,991 18,089 37,603 25,330 494,457 2035 796.280 43,553 14,871 12,275 32,599 15,947 119,245 25,844 13,811 19,435 18,401 41,753 27,440 521,897 2036 802.497 44,988 14,220 12,769 32,885 17,108 121,970 24,429 14,301 19,911 17,188 46,141 29,584 551,481 2037 804.309 46,245 14,388 13,284 33,046 17,601 124,564 24,909 14,822 20,304 17,392 47,136 29,485 580,966 NPV: 549,144 207,150 143,615 320,874 186,047 1,406,830 290,366 181,805 187,835 165,858 580,966 580,966 580,966 Supply Cost Wholesale Sales
COR V11 Scenario H Mean Results
Portfolio
1st Yr Energy
MWh)
LCOE
MWh)
Economic and Financial Parameters
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8.5 SENSITIVITY CASES
As discussed previously in Section 8, the PowerSimm Resources Planning Suite, developed by Ascend Analytics, was used to evaluate alternative resource additions to the portfolio that satisfy RPS requirements. PowerSimm employs a probabilistic approach in which the modeling results for a single Scenario include a range of possible outcomes based on agitations of input variables subject to uncertainty and for which correlated probability distributions are generated for the input. This method results in more than single deterministic output variables, but probability distributions on all the key output variables. This means that multiple, single variable sensitivity runs are not needed to understand the impact of uncertainty in one or more key input variables. For example, regarding fuel prices, the CPWC results reported in Figure 7-2 are based on random expected draws of fuel prices, correlated with random expected draws of other input variable, resulting in a 95 percent to 5 percent probability distribution range on the output variables. This means that fuel prices selected in the random expected draws are within a band expected to include the maximum fuel price 95 percent of the time and the low fuel price is not expected to go below the low fuel price more than 5 percent of the time. The results reported inthis section are based on the mean results of all runs resulting from multiple draws on the stochastic input variables and simulated by the model.

8.6 RETAIL RATES AND THE PREFERRED EXPANSION PLAN
Forecasts project power portfolio costs to increase by approximately $ 20 million ( nominal) from 2018-2037, or 2.25 percent annually ( less than 1 percent when adjusted for inflation). Of this $20 million, approximately $ 15 million is due to the following power purchases related to environmental compliance:
60 MW share of Central Valley Solar beginning in 2026; despite the utility owning lower cost thermal generation, additional resources are required to meet state mandates. 65 MW share of Northern California/ Oregon Wind beginning in 2034 despite the utility owning lower cost thermal generation, additional resources are required to meet state mandates.

Due to forecasted retail sales in 2038 being within 3 percent of 2018 retail sales ( energy efficiency measures reducing base load growth), a $20 million increase in annual power portfolio costs represents an increase from today’ s rates of approximately 15 percent, or less than 1 percent annually ( this is less than CPI). Due to the expected limited impact on rates from power supply costs over the forecast period, a separate report or study was not conducted. Any future update to COR’ s IRP will continue to appropriately evaluate rate impacts related to power supply costs. While Power Supply is a significant portion of the utility’ s budget ( see Figure 8-6), itis not the only driver for rate changes. Other factors not included inthis study such as debt service, personnel costs, maintaining the distribution system, and increasing reserves to manage financial risk associated with intermittent resources, will have significant impacts on the revenue requirement. In addition, while the 2018 Carr Fire had a substantial impact on the community, the COR had adequate reserves to fund infrastructure restoration efforts ( zero rate impact). Figure 8-7 shows the projected portfolio cost of Scenario H and the level of retail sales through 2037.

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Figure 8-6 Budget Categories by type in Fiscal Year 2019 Figure 8-7 Cost of the Preferred Expansion Plan, Scenario H 23%
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8.7 THE PREFERRED PLAN IN CONSIDERATION OF FUTURE CONDITIONS AND RISKS
A number of factors could emerge in the energy industry, or in the economy, that could impose new conditions or risks not contemplated in this SB 350- based analysis. Some of these factors include new legislation and regulations that impact utility operation and could include the following:

SB 100 (The 100 Percent Clean Energy Act of 2017) – SB 100 further modifies RPS requirements from 50 percent by 2030 ( set by SB 350) to 60 percent, and creates the policy of planning to meet all of the state’ s retail electricity supply with a mix of RPSeligible and zero- carbon resources by December 31, 2045, thereby achieving a 100 percent clean energy supply.

On September 10, 2018, SB 100 was signed into law. COR anticipated that SB 100 would likely be signed by the Governor and as such, has begun some preliminary analysis on the potential impacts this law may have on RPS requirements into the planning horizon. The additional analyses, including detailed system modeling, is required to adequately evaluate all the potential impacts of the newly increased RPS obligations.

SB 100 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.

For the last several years, COR’ s approach to RPS requirements ( changes/ increases in those requirements) has been to evaluate resources into the future to ensure compliance obligations are fully met. SB 100 carries with it a new level of RPS requirements of over 50 percent by 2030 which presents a more complex balancing of the power supply mix than what COR has considered inthe past. SB 100 becomes effective in January 2019 and with that, regular updates to the modeling that supports the power supply strategy will continue and will fully integrate the requirements of SB 100 within that process in 2019 and beyond.

AB 813 (Electric Regionalization) – The bill would open the door for the CAISO to expand its membership to include other balancing authorities across the 14 western states. This regionalization bill would require approval from the state before any California transmission owner, retail seller, or local publicly- owned utility joins a multistate regional transmission system organization. Bill proponents believe regionalization would reduce rates and costs, ensure consistent reporting and tracking of RE targets and achievements, and reduce transmission rates. Opponents believe that the bill would harm the independence of state policy including the progress made in California toward its RE standards, which are generally more aggressive than in other states.

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SB 1110 ( Safeguarding Public Utility Ratepayers from Bond Debt authored by Senator Bradford) – This bill protects COR from construction debt of power plants built in the early 2000’ s in response to the energy crisis. In the early 2000’ s— when many California cities were struggling with how to serve their communities with electricity and experiencing brown outs— Council, with decisive action, approved the speedy construction and operation of the state- of-the-art low emission, gas- fired generation that COR now owns. This action brought safety in delivering electricity, increased reliability, and an enhancement to the local economy with approximately 25 full-time positions earning favorable wages.

With construction of these safe, efficient, and reliable power generating facilities, debt was incurred. Currently, bond indebtedness is approximately $ 106 million dollars; which is scheduled to be paid in full by 2030.

SB 1110 was signed into law on September 20, 2018, providing protection of resource investments as our state traverses the path of 100 percent RE mandates by the 2040’ s, and would allow the continued operation of these reliable and efficient facilities at a level that would allow us to finish paying for our assets without causing financial harm to our community.

Each of these laws or regulations could impact the decision process, as could economic growth that is significantly higher or lower than anticipated in this IRP. In anticipation of possible changes in future conditions and risks, the IRP has been developed such that it affords flexibility, balance, and margin. The recommended plan does not require an immediate commitment to projects needed well into the planning horizon. In fact, following the 2021 planned addition of the 10 MW Solar Project, incremental RPS resources are not projected to be added until sometime after 2023. The renewable projects under consideration can be developed in a relatively short time; as a result, COR can confirm that future developments identified in this IRP remain beneficial prior to making a firm commitment to these projects.

The recommended Scenario H is balanced in that it mixes solar and wind RE resources better than other Scenarios considered. This is important because, while the economic analysis did incorporate a probability analysis of possible production profiles for these two technologies, there are also nonquantifiable risks that suggest a balanced RE portfolio may help to mitigate future uncertainties.

This could include, for example, the possibility of opposition to a renewable technology in the future, that new incentives, taxes, or operational charges ( such as integration costs) could materialize and favor one technology over the other. By planning for a balanced portfolio, Scenario H is a way to protect against unforeseen developments that could favor wind over solar, or vice versa.

Finally, the recommended Scenario H provides margin in the sense that, as seen in Figure 8-3, the plan will produce more than the minimum RE required to meet the existing RPS targets. This margin provides a risk reduction benefit should SB 100, or another law or regulation, require a more aggressive pursuit of RE.

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8.8 THE PREFERRED PLAN WITH CONSIDERATION OF LOCALIZED AIR

POLLUTANTS AND DISADVANTAGED COMMUNITIES
COR is not aware of any officially designated disadvantaged communities in its service territory.

Nevertheless, there are many areas served that are considered low income. To help serve the needs of low-income groups, the following strategies are utilized to maximize education and participation of low-income customers in the Low-Income Energy Efficiency Program ( LIEEP) program.

Program policies are specifically designed to facilitate coordination with the PG& E Energy Savings Assistance Program and with the California Department of Community Services and Development’ s CSD) Weatherization Program. For example, CSD measure feasibility guidelines and installation standards have been adopted, and adopted PG& E ESA and CSD program participation as a categorical qualifier for the LIEEP Program. This seamless integration minimizes duplicative efforts, maximizes return on program marketing efforts, and delivers maximum benefits to our income- qualified customers.

The local non-profit weatherization provider who implements the PG& E ESA Program and CSD programs in Shasta County, also handles implementation of LIEEP.

COR partners with multiple mission driven, non- profit organizations to market the suite of resources available to income qualified customers including weatherization, a rate discount program, and an emergency bill assistance program.

Continuation of these programs, or similar programs and efforts, is anticipated to continue as a means to educate and assist low-income customers in the future. The preferred Scenario H is deemed to be in the interest of low-income customers, and all other customers, in that it achieves a balance between affordability ( having a CPWC less than 3 percent higher than the lowest cost Scenario) and environmental benefits ( meeting 2030 RPS requirements and within the GHG limits recommended by CARB staff).

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Figure 8-8 Cal Enviro Disadvantaged Communities Map
This figure was created by CalEnviro. For more details, visit https:// oehha.ca.gov/ calenviroscreen. 15 15 Red represents the most disadvantaged communities while green represents the non -disadvantaged communities.

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9.0 Conclusions and Recommended Expansion Plan
This Report discussed the development of the IRP and presented the results. The IRP was developed to benefit and create value for customers and to deliver exceptional services through the strength and dedication of its employees. This overriding objective is achieved by providing reliable and safe service at low (cost- conscious) rates, while complying with environmental mandates and objectives.

The development of the IRP took over one year and was the result of collaborative efforts by COR staff, Black & Veatch, Itron, Ascend Analytics, and Stakeholders. Customers had important input and played a vital role in the planning process. As a result, the recommended Scenario is considered to be a plan that balances many different views and perspectives, and is also a robust plan that will provide low costs, flexibility, environmental compliance, and manageable risks over the 2018- 2037 planning period. This Report is designed to be a guiding document, not a procurement plan.

The recommended Scenario is identified in this report as Scenario H. This plan features the addition of the 10 MW ( maximum rating, not firm) local Solar Project in 2021, followed by an additional 60 MW of solar capacity in 2026, and a 65 MW wind facility in 2034. This plan is low cost— within 2.8 percent of the lowest overall plan on a cumulative basis but within 2.1 percent through 2030; it allows the flexibility to adjust the size and timings of the 2026 and 2034 resource additions as conditions warrant; itis compliant with the targets for RE (50 percent in 2030 and all intermediate targets), 2030 GHG emissions proposed in the summer of 2018 by CARB; and the plan assumes continued investment in energy efficiency and demand reduction programs.

All of these objectives are met while also providing a reliable power plan that meets the planning reserve requirements. The details of Scenario H are presented in the discussion and accompanying tables and figures in Section 8. The four tables required in the CEC Guidelines are provided in Appendix A. These tables support the conclusion that Scenario H is a viable plan that meets the POU objectives and requirements for an IRP.

This IRP will be updated as conditions warrant, most likely every two to three years but, in any case, no longer than the five year limit established in the CEC Guidelines. Given the relatively short lead time for RE resources and the dynamics of the power sector, future IRP updates will be able to adjust to changing conditions as needed and will help ensure that the resource plan continues to serve the needs of its valued customers.

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Appendix A. CEC Standardized Tables for the Adopted
Resource Scenario
The CEC Guidelines require four standardized tables to be part of the IRP Filing. The standardized tables presented in this Appendix for the recommended Scenario H are as follows:

Administrative Information: Summary of contact information for persons who prepared standardized tables
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.

Energy Balance Table ( EBT): Annual total energy demand and annual estimates for energy supply from various resources.

RPS Procurement Table ( RPT): A detailed summary of a POU resource plan to meet the RPS requirements.

GHG Emissions Accounting Table ( GEAT): Annual GHG emissions associated with each resource in the POU’ s portfolio to demonstrate. 16
16 Page A-4
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A A2
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A A3
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A A4
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A A5
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A A6
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B B1
Appendix B. Stakeholder Feedback Form Results
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B B2
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Appendix C. Intermittency Analysis
Black & Veatch completed a stochastic analysis of COR’ s load and generation to estimate the 95 percent confidence interval of the deviation of actual hourly load less generation ( Net Load) compared to scheduled hourly Net Load. In the analysis, Black & Veatch also included a case where a 10 MW fixed tilt Solar Project ( Solar Project) was included in COR’ s Net Load.

The stochastic analysis was completed utilizing Palisade Corporation’ s @RISK software; @Risk is a Microsoft Excel add-in which completes stochastic analyses similar to Crystal Ball. The 95 percent confidence intervals with and without the Solar Project were compared to assess if the addition of the Solar Project significantly increased the confidence interval. The key data and assumptions used in the analysis are summarized below.

Five minute load and generation data for 2014 through 2017 was utilized for the analysis The analysis was completed on a monthly basis to consider seasonality of load and generation
Five minute load data was assumed to follow a normal distribution utilizing the historical mean and standard deviation for 2014 through 2017
Five minute generation data was assumed to follow a log normal distribution utilizing the historical mean and standard deviation for 2014 through 2017 The generation from the Solar Project from 2014 through 2017 was estimated using US Climate Reference Network ( CRN) data for a site located 20 miles NW of Redding Airport applied in a NREL Solar Advisor Model ( SAM) simulation of a 10 MW fixed tilt Solar Project Scheduled load and generation for each five minute period was assumed to be the historical mean for 2014 through 2017
Actual load and generation in each five minute period was estimated stochastically using the distributions defined
Deviation from schedule on a five minute basis was calculated as the difference between the actual Net Load and scheduled Net Load; actual Net Load greater than scheduled yielded a positive value, actual load less than scheduled yielded a negative value The hourly deviation from schedule was calculated as the average of the five minute values The stochastic analysis estimated 95 percent confidence intervals for hourly load deviation and hourly load less generation for each month
Further information on the development of the generation data for the Solar Project is included in Attachment A.

Figure C-1 and Figure C-2 below illustrate typical 5 minute input distributions for the COR load and generation; the January 7 a.m. three minute load and generation input distributions without the additional of the generation from the Solar Project have been included.

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C C2
Figure C1 January7 a.m. Stochastic Load Distribution
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Figure C- 3 and Figure C- 4 illustrate representative 95 percent confidence intervals for the actual versus scheduled Net Load; the 95 percent confidence interval for January 7 a.m. Net Load has been included.

Figure C-3 January 7 a.m. Load less Generation Deviation from Schedule In comparing the stochastic Net Load deviation from schedule with and without the addition of the Solar Project, in general Black & Veatch found that there was very limited difference between the 95% confidence intervals for each case. Figure C- 4 compares the 95% confidence intervals for Net Load with and with and without inclusion of the Solar Project in July; this month was selected as it is a period of high solar generation where it would be expected that the addition of solar would have more influence on the Net Load deviation from schedule.

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Figure C- 4 July Net Load Deviation with and without Solar Project Generation It can be seen that across the day there is very limited difference between the 95% confidence intervals for Net Load with and with and without inclusion of the Solar Project. Very similar results were seen in the other months of the year; charts for each month are included in Attachment B.

Black & Veatch suggests that a next step could be to schedule a call to discuss the results above and any further analysis which COR would like to complete. Some further analysis which could be completed could include:

Estimating the impact of increasing solar capacity ( e.g. in 10 MW increments) to the results above.

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Attachment A: Solar Project Generation Data

INTRODUCTION
Black & Veatch developed a representative historical solar energy production profile for a 10 MW PV plant located in Redding, CA. The historical production was simulated at a sub-hourly level with 5-min time steps for the period of 2014- 2017.

SOLAR RESOURCE ASSESSMENT
The historical ground solar resource data accessed in this study is from the US Climate Reference Network ( CRN) site located near Redding, CA. The CRN station location is located 20 miles NW of Redding Airport ( representative project location) at an elevation of approximately 1440 feet. The US CRN sites measure high quality observations of several meteorological parameters including solar radiation, ambient temperature, wind speed, precipitation etc., at 5-minute intervals. The measured data has been processed for any errors and the quality controlled data was used for the purposes of this study.

USCRN DATA OBSERVATION AND CORRECTIONS
Due to the high elevation of the Redding USCRN location, measured data obtained was reviewed to ensure its compatibility for robust solar energy simulation use. To assess the suitability of solar irradiance data from the CRN location, Black & Veatch compared long term satellite based GHI irradiance for Redding Airport site against the GHI obtained from US CRN site. Long- term trends appeared to be very similar at both these locations. Based on our review of the Redding CRN data the following trends were observed,
A slightly lower GHI was observed at the CRN site due to more frequent cloud formation associated with closer proximity to the Klamath Mountain range.

There appeared to be sensor shading due to the Klamath Mountains to the west of the station location and can be noticed on a clear day during late summer afternoons.

Therefore, any drop in the simulated production during late afternoon can be attributed to this shading effect inthe input irradiance profile and should be taken into consideration when comparing late afternoon PV energy production with coincidental system load data.

This dataset from the CRN site was selected as a representative solar resource dataset due to overall high quality, high temporal resolution and proximity of the location of interest. Additionally, to represent the temperature profile accurately at the airport location an altitude temperature correction of +1.5 C has been applied to the Redding CRN air temperature data to correct for the altitude difference between the Redding CRN and airport site ( approximately 1000 ft. altitude difference). No corrections have been applied to the CRN irradiance or wind speed data.

SOLAR PV PRODUCTION MODELING
Black & Veatch used NREL System Advisor Model to simulate the energy production of a 10 MW Solar Project. The system design information assumed during this simulation process is shown in the table below. All the system DC and AC loss assumptions were selected such that it represents a 10 MW ground mount utility- scale project.

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System Type and Location Fixed-Tilt – Redding, CA
System DC Capacity ( kWac) 10,000
DC/ AC Ratio 1.3
Mounting Type Fixed – Tilt 30 facing south
Ground- Coverage Ratio 33%
Module Type Crystalline – Silicon (335 W)
Inverter Type Central Inverters 2000 kW
Based on the analysis, Black & Veatch infers the following:

The output energy production appears to capture the solar resource variability at the subhourly level.

The output energy production profile does not capture the spatial variability across the entire PV array, and therefore assumes generation to be a point source. This variability however tends to smoothen out as the PV array size increases.

Due to high temporal resolution of the input temperature profile, high frequency production variation is noticed around solar noon during certain clear sky days. This variation however has very less magnitude and in fact cannot be noticed during the days when project is clipping. This high frequency spikes in production can also be seen in actual production data at sub-hourly level, but this effect is dampened to uneven spatial temperature distribution across the array and data averaging at the meter.

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Attachment B: Stochastic Model Results
The stochastic model results comparing the 95% confidence intervals for Net Load with and with and without inclusion of the Solar Project for each month are summarized in the figures below.

Figure C- 5 January Net Load Deviation with and without Solar Project Generation Figure C-6 February Net Load Deviation with and without Solar Project Generation

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Figure C- 7 March Net Load Deviation with and without Solar Project Generation Figure C- 8 April Net Load Deviation with and without Solar Project Generation

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Figure C- 9 May Net Load Deviation with and without Solar Project Generation Figure C- 10 June Net Load Deviation with and without Solar Project Generation

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Figure C- 11 July Net Load Deviation with and without Solar Project Generation Figure C- 12 August Net Load Deviation with and without Solar Project Generation

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Figure C- 13 September Net Load Deviation with and without Solar Project Generation Figure C- 14 October Net Load Deviation with and without Solar Project Generation

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Figure C-15 November Net Load Deviation with and without Solar Project Generation Figure C-16 December Net Load Deviation with and without Solar Project Generation

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Appendix D. Ascend Analytics Methodology

FORWARD PRICING
PowerSimm simultaneously simulates multiple strips of forward curves into the future where parameters for the stochastic processes and the covariate factors are estimated from historic data.

PowerSimm builds a system of simultaneous equations that captures the stochastic component of each individual forward contract and the covariate relationship between neighboring contract months, other commodities, and other factors ( such as interest rates and exchange rates). The state- space modeling framework satisfies the criteria for developing a Cash Flow at Risk solution by producing simulations of prices that are realistic, benchmark well to historic data, and produce a payoff of cash flows consistent with market option quotes at multiple strike prices. The consistency of simulated prices with market expectations remains the principal benchmark criteria for forward market simulations.

Forward contracts may have institutionally determined and specified drift terms. The drift term is a percent change from the current forward price to the final evolved forward price. For example, a forward contract with a current price of $50 and a drift of 10% would have a final evolved price of

55. As a base simulation assumption, PowerSimm creates convergence between the initial forward price and the final forward price. This is the equivalent of a zero drift term. Even with a very limited number of assumptions the convergence criteria of F0= FT will be satisfied.

The process flow for forward price simulation is shown in Figure D-1.

Figure D-1 Forward Price Simulation Process
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Input Data
PowerSimm requires a history of forward price quotes for each delivery month to simulate market prices into the future. A minimum of 30 transaction dates for each delivery date is required for forward curve simulation.

PowerSimm has the ability to weight the historic data used in the parameter estimation process to give more weight to more recent events or reduce the impact of outlier events. The default historic weighting formula for forward market data used for parameter estimation follows a linearly declining function. It provides a weight of 1095 for the most recent observation, 1094 for the second most recent, and so on, until it reaches a value of 365 ( which corresponds to three years).

All historic quotes older than three years old receive a value of 365. Thus, yesterday’ s quote receives three times the weight in the parameter estimation process as a value that is three years old.

Output Data
Output from the forward price simulation consists of fully evolved forward prices for each forward curve, simulation repetition, and delivery date in the study. The mean forward price for each delivery date is scaled to match the most recent available market forward curve data as of the run time of the study.

SPOT ELECTRIC PRICES
Methodology
The application of the fundamental drivers of electricity has influence on the daily and hourly formation of prices.

Regional electricity prices are primarily a function of daily gas prices and daily reserve margins as shown in Figure D-9. Each variable explains about 50% of the variability in prices and jointly they explain about 90% of the variability. The split regression of Figure D-9 contains a relatively modest amount of noise in the electricity price of +/- $5/ MWh when reserves are greater than 15%. When daily reserves are less than 6 percent, the unexplained noise “ switches” to a higher regime and captures uncertainty inprices of +/- $40/ MWh. High electricity prices can also be caused by spikes in daily gas prices. The spikes in daily gas price carry a direct linear relationship to electricity prices. The joint relationship between high gas prices and low reserve margins follows from regional analysis.

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Figure D-2 Joint relationship of daily reserve margins and gas prices to electric prices Simulation of spot electricity prices includes three key components:

1. Simulation of the uncertainty in the parameter estimates and the covariate relationship of uncertainty inthe parameter estimate;

2. Simulation of the exogenous variable through a series of simultaneous vector autoregressive equations;

3. Simulation of residual error.

Variables describing the supply stack, such as the percentage of gas fired generation were determined to be statistically insignificant and were removed from the model.

The simulated values for price are conditional upon the path-dependent weather and load simulations. The mean or median of the realized daily on-peak and off-peak spot prices are bucketed into monthly time steps and scaled so that the mean is equal to the monthly forward price.

Spot electric prices are typically simulated once a week, as new utility and system load values become available. The job management system oversees the appropriate execution of the simulations by way of the Process Flow Editor in the PowerSimm UI.

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Process Flow
The process flow for simulation of electric market prices is shown in Figure D-3. The triangles on the left of the figure represent the historic data from which relationships between fundamental variables and electricity prices are determined. The linked simulations of each predictive variable are shown in the rectangular boxes to the right of the triangular inputs. Explanatory variables are linked to electricity prices through a structural state space model.

Figure D-3 PriceSimm Process Overview Diagram
Input
The input data consists of the following:

Historic hourly load data
Historic hourly or daily hydro generation
Daily gas prices
Transmission imports and exports ( optional)
Daily reserve margins ( optional)
Supply stack characteristics ( optional)
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Weighting of Input Data
The default function for the weighting of historic spot market data used for parameter estimation is flat weighting ( all historical data is weighted equally). Alternatively, the historical spot prices can be weighted according to a linearly declining function. This weighting system provides an initial weight for the most recent input spot prices of 730 and 729 for the two-day-old prices. The weights decline daily under the same pattern for two years until they reach a value of 365. All historic quotes older than two years receive a value of 365. Thus, yesterday’ s quote receives twice the weight in the parameter estimation process as a value that is two years old. Users can adjust the default weighting formula through the UI
Output
The hourly spot price simulation produces daily on-peak and off-peak electric prices and hourly spot electric prices. The prices that are output are scaled to the final evolved forward prices from the corresponding forward price simulation module. More specifically, the average monthly spot price by peak period will be equal to the market forward price as of the scheduled run time of the study in which the forward price simulation was run.

SPOT GAS PRICES
Design Definition
Developing accurate spot gas price simulations is critical for determining the cost of service, risks, and hedging strategies. A simulation approach is advantageous where a specified number of likely events ( realizations) can be used in conjunction with exogenous system shocks such as extreme weather events. The combination of market electric prices and spot gas prices is critical to accurately capturing the cost of generation and driving dispatch of generation assets. For each portfolio in PowerSimm, there will be only one central gas delivery point. The other points will be treated as basis points from the delivery point. In most cases, this construct will lead to Henry Hub as the central gas delivery point.

Operational Business Process and Schedule
The generation of new spot prices is run approximately once every month or quarter as new utility and system hydro data becomes available. The Job Management system oversees the appropriate execution of the simulations and provides users with summary statistics based on the last updated input data.

Process Flow
The process flow for gas price simulation is shown below in Figure D-4.

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Figure D-4 Spot Gas Price Process Flow
Input Data
Estimation of the parameters to simulated spot gas prices utilizes input of historical gas spot prices, weather, and daily on-peak and off-peak electric prices. The simulated weather is input into the model on a simulation basis.

Output Data
The output data is identical to the daily historic input dataset except that itincludes the requested number of spot price simulations for the requested simulation length. This dataset also includes the simulation date and time update along with a link table to describe the parameters used to run the simulation.

Weighting of Data
The historic spot market data used for parameter estimation follows a linearly declining function.

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

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

LMP & BASIS PRICE SIMULATION
Design Definition
LMP hourly prices and spot gas basis prices share the same simulation structure. Prices are measured in terms of the difference from a central hub. By treating LMP prices as basis prices, we focus on capturing the uncertainty in basis prices between the delivery point and the hub price while maintaining the same correlation between nodal points and the central hub. Simulation of basis addresses market conditions where historic data exists to support estimation of time series relationships. For markets with historic data, itis important to preserve the time series relationships between structural variables such as system load and spot prices.

Operational Business Process and Schedule
Approximately once every month or quarter, generation of new basis prices is run as new utility and system hydro data becomes available. The job management system oversees the appropriate execution of the simulations to provide users with summary statistics based on the last updated input data.

Process Flow
The process flow for spot basis price simulation is shown below in Figure D-5.

Figure D-5 Spot Basis Price Process Flow
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Input Data
Simulation of spot gas prices requires input of historical gas spot prices and daily on-peak and offpeak electric prices.

Output Data
The output data is identical to the daily historic input dataset except that itincludes the requested number of basis simulations for the requested simulation length. This dataset also includes the simulation date and time update along with a link table to describe the parameters used to run the simulation.

Methodology
Gas Basis and Daily Electric Prices
Daily gas prices are linked to daily electric on-peak and off-peak prices through the residual error structure.

Hourly Electric Basis
The simulation of hourly electric basis prices follows the following time series model structure where each hour has its own equation.

Hour1 = Lag1( Hour24) + OffPeakPrice + OnPeakPrice + DayOfWeek + MA1 + error Hour2 = Hour1 + OffPeakPrice + OnPeakPrice + DayOfWeek + MA1 + error Hour3 = Hour2 + OffPeakPrice + OnPeakPrice + DayOfWeek + MA1 + error Hour4 = Hour3 + OffPeakPrice + OnPeakPrice + DayOfWeek + MA1 + error Hour5 = Hour4 + OffPeakPrice + OnPeakPrice + DayOfWeek + MA1 + error Hour24 = Hour23 + OffPeakPrice + OnPeakPrice + DayOfWeek + MA1 + errorand similarly for OffPeakPrice.