HomeMy WebLinkAbout _ 9.5(c)--Redding Electric Utility's 2024 Integrated Resource Plan
CITY OF REDDING
REPORT TO THE CITY COUNCIL
Recommendation
Approve the City of Redding Electric Utility’s 2024 Integrated Resource Plan in accordance with
the requirements of the Clean Energy and Pollution Reduction Act of 2015 (Senate Bill 350 or
“SB 350”); and authorize the Electric Utility Director to modify the Integrated Resource Plan, if
necessary, to meet the requirements of the California Energy Commission.
Fiscal Impact
No fiscal impacts are associated with adopting the City of Redding Electric Utility (REU) 2024
Integrated Resource Plan (IRP) Report. The IRP is a planning document only and does not
include procurement elements.
Alternative Action
The City Council (Council) could choose not to accept the IRP and direct staff to provide an
alternative recommendation.
Background/Analysis
Public Utilities Code section 9621, as amended by Senate Bill (SB) 350, required each Publicly-
Owned Utility (POU) with an annual average load exceeding 700-Gigawatt hour (GWh) to
develop and have its governing board adopt an IRP by 2019 and file an updated plan every five
years thereafter. The IRP must demonstrate that the POU will achieve the State's greenhouse gas
reduction targets and Renewables Portfolio Standard (RPS) requirements while addressing other
critical topics like reliability, electrification, and ratepayer impacts. With an annual average load
of 745 GWh, REU is subject to the IRP filing requirements.
MEETING DATE: November 7, 2023
ITEM NO. 9.5(c)
FROM:
***APPROVED BY***
nzettel@cityofredding.org
btippin@cityofredding.org
SUBJECT: 9.5(c)--Consider Redding Electric Utility's 2024 Integrated Resource Plan.
Nick Zettel, Director of
Redding Electric Utility
Report to Redding City Council November 2, 2023
Re: 9.5(c)--Redding Electric Utility's 2024 Integrated Resource Plan Page 2
2019 IRP Report
In 2019, REU submitted its first IRP (referred to as the "2019 IRP") with the California Energy
Commission (CEC). The 2019 IRP focused on reliability and portfolio diversity, with a goal of
maintaining competitively priced electric service to customers over a 20-year planning period.
Shortly before submitting the 2019 IRP for Council approval, the "100 Percent Clean Energy Act
of 2018" (Senate Bill 100 or “SB 100”) was signed into law on September 10, 2018. SB 100
introduced the following requirements:
• Accelerated the 50% renewable energy procurement requirement to 60% of retail sales by
2030;
• Minimum ten-year renewable energy contract term requirements, along with limiting the
percentage of renewable energy permitted to be purchased from short-term contracts; and
• Established a planning goal mandating zero-carbon resources to supply 100% of retail
electric sales by December 31, 2045.
Due to timing differences between the analysis for the 2019 IRP and the signing of bills in 2018,
the 2019 IRP was already completed by the time SB 100 became effective. Therefore, REU
could not incorporate SB 100 impacts into the 2019 IRP. The Council approved the 2019 IRP on
November 6, 2018, and staff filed it with the CEC on April 11, 2019.
2021 Mid-Cycle Update Report
Staff developed the 2021 Mid-Cycle Update (2021 Update), an elective, supplemental report, to
model the 2019 Preferred Plan with updates from SB 100. The 2021 Update utilized refined
modeling practices to better capture energy risk and portfolio management insights. Critical
updates to the 2021 Mid-Cycle report included:
• Incorporated SB 100 updated RPS requirements and the 100% zero-carbon by 2045
planning target;
• Suspended further efforts to develop a 10 megawatt (MW) local solar project due to high
cost and difficulty with site planning and permitting; and
• Incorporated transportation and building electrification programs as recommended in the
Demand-Side Management Integrated Resource Plan (DSM-IRP) report adopted by the
Council on September 21, 2021.
City Council approved the 2021 Mid-Cycle update on October 19, 2021, and provided the
following considerations for the following IRP report submitted to the CEC in 2024:
• Analyze the impacts of the 100% zero-carbon by 2045 target;
• Evaluate the resource adequacy capacity requirements to replace the Redding Power
Plant (Plant) under a zero-carbon scenario;
• Develop transportation and building electrification load forecasts to identify expected
load growth;
• Identify transmission and distribution upgrades needed to ensure the system reliably
delivers power if the Redding Power Plant were retired; and
• Evaluate additional renewable resources beyond those identified in the 2019 IRP.
Report to Redding City Council November 2, 2023
Re: 9.5(c)--Redding Electric Utility's 2024 Integrated Resource Plan Page 3
2024 IRP Report
In preparation for the 2024 IRP development, staff conducted three preliminary studies:
1. Electrification Forecast: Secure the services of Dunsky Energy + Climate Advisors to
develop a comprehensive Building and Transportation Electrification forecast extending
through the 2045 planning horizon;
2. Customer Survey: Contract with GreatBlue Research to conduct a statistically significant
customer survey, determining the community’s future energy resource and program
preferences; and
3. Transmission System Assessment: Sacramento Municipal Utility District (SMUD)
provided an in-depth analysis of REU’s transmission and distribution system to study the
impacts of retiring the Redding Power Plant and relying solely on imported power to
meet customer demands.
After completing the initial studies, REU staff developed the following strategic framework: The
2024 Integrated Resource Plan should meet or exceed the State's clean energy mandates while
balancing reliability and affordability.
In partnership with its contracted consultant, Ascend Analytics, modeling scenarios were
developed that would consider various resource options to identify a scenario that meets the
IRP's strategic framework while remaining flexible and adaptable to State policy changes. The
modeling scenarios are as follows:
• Low "Base Case" (does not meet mandates)
• Mid "Net-Zero Carbon 2045" (meets mandates)
• High "100% Zero Carbon 2045" (exceeds mandates)
The State’s IRP public engagement requirements were exceeded by forming a group of diverse
stakeholders who would ultimately be tasked with identifying the Preferred Plan for the 2024
IRP. The group consisted of community members representing a variety of customer classes and
demographics, and together, they played a critical role in shaping the direction of the 2024 IRP.
A series of technical workshops were held to introduce key concepts of the IRP, including
legislation and regulatory requirements, types of resources and resource planning, modeling
results, and cost analysis, with the final workshop focused on selecting the Preferred Plan used
for the IRP. The stakeholders were interested and engaged, and the staff greatly appreciated the
valued insights and feedback they contributed.
At the conclusion of the workshops, the stakeholder group was tasked with identifying the
Preferred Plan for meeting the goals outlined in the strategic framework (the Base Case was
excluded from consideration due to non-compliance with the State’s clean energy mandates).
Therefore, stakeholders were presented with two distinct scenarios: Net-Zero Carbon 2045 and
100% Zero Carbon 2045 plans. Each plan included detailed information on the potential benefits,
challenges, costs, and implications associated with each scenario. Key characteristics of each
scenario include:
• Net-Zero Carbon 2045: Meets clean energy mandates and targets; allows REU to
continue running the Plant through 2045 by using carbon allowances (or credits) to offset
emissions, allowing the Plant to run for capacity (when economical) while keeping power
supply costs relatively low (plan costs $870 million); and
Report to Redding City Council November 2, 2023
Re: 9.5(c)--Redding Electric Utility's 2024 Integrated Resource Plan Page 4
• 100% Zero Carbon 2045: Exceeds clean energy mandates and targets; the Plant would
not be able to generate after 2045, causing a significant increase in power supply costs
starting in 2040 (plan costs $1.26 billion, including costly transmission system upgrades).
The stakeholder group selected Net-Zero Carbon 2045 as the Preferred Plan for the 2024 IRP,
acknowledging the Plant's crucial role in maintaining reliable and affordable energy for REU’s
customers. A virtual public workshop was held, followed by a customer survey and an open
comment period relating to the draft report. Results from the customer survey affirmed the
stakeholder group's decision. Features of this plan are as follows:
• Add 315 MW of solar by 2041;
• Add 55 MW of 8-hr battery storage by 2041;
• Continue dispatching the Plant as needed for reliability and extreme peak events; and
• Offset emissions through carbon-free procurements and carbon allowances.
The result of the 2024 IRP process is a guidance document, or roadmap, providing direction for
future resource decisions; it is not a procurement document. All future procurement activities
identified above will be evaluated independently and brought to the Council prior to executing
any purchase agreements. This report will be updated at least once every five years and
submitted for the Council's approval.
In accordance with the CEC guidelines, the 2024 IRP must be adopted by the Council no later
than January 1, 2024, and submitted to the CEC by April 30, 2024. Upon the Council's approval,
REU will submit the 2024 IRP to the CEC for review and approval by the assigned deadline. If
the CEC requires changes to the submitted IRP, staff will work under the direction of the Electric
Utility Director to make the updates and resubmit the final draft to the CEC.
Environmental Review
This action is not a project as 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
2024 IRP Filing Contents (Final)
City of Redding IRP Report 2024
2024 Integrated Resource Plan | 2024 IRP Filing Contents (SB 350 Requirements)
2024 IRP Filing Contents (SB 350 Requirements)
IRP Filing Contents Per CEC
Guidelines Public Utilities Code Sections in REU IRP
A. Planning Horizon Section 9621(b) (1) and (2) IRP’s planning horizon is 2023-2045 (Throughout
IRP)
B. Scenarios and Sensitivity
Analysis
Section 9621 (d) Section 7, Modeling Assumptions, Tools,
Methodology
C. Standardized Tables N/A Exhibit 9.5 Standardized Tables
1. Capacity Resource
Accountable Table
(CRAT)
N/A Exhibit 9.5 Standardized Tables
2. Energy Balance
Table (EBT)
N/A Exhibit 9.5 Standardized Tables
3. RPS Procurement
Table (RPT)
N/A Exhibit 9.5 Standardized Tables
4. GHG Emission
Accounting Table
(GEAT)
N/A Exhibit 9.5 Standardized Tables
D. Supporting Information N/A Supporting information to supplement data in the
Standardized Tables may be found in the charts,
graphs, and narratives in the IRP
E. Demand Forecast N/A Section 6, Energy Forecast and System Impacts
1. Reporting
Requirements
N/A Exhibit 9.5 Standardized Tables
2. Demand Forecast
Methodology and
Assumptions
N/A Section 6.2, Forecast Methodology and
Assumptions
3. Demand Forecast-
Other Regions
N/A Section 6.2, Forecast Methodology and
Assumptions; and Section 8.4, Sensitivity Cases
F. Resource Procurement
Plan
Section 9621(b) and (d) Section 4, Energy Efficiency, Electrification, and
Demand Response Programs
1. Diversified
Procurement
Portfolio
Section 9621(d)(1)(D) Section 7.2, Modeling Assumptions; and Section
8.4, Sensitivity Cases
2. RPS Planning
Requirements
Section 9621(b)(2) and
Section 399.11
Section 8.2, Scenario Analysis
3. Energy Efficiency
and Demand
Response Resources
Section 9621(d)(1)(A)
Section 9615
Section 4.4, Energy Efficiency and Greenhouse Gas
Reduction; and Section 4.6, Demand Response
Programs
4. Energy Storage Section 9621(d)(1)(B)
Chapter 7.7 (commencing
with Section 2835) of Part
2 of Division 1
Section 4.7, Energy Storage
5. Transportation
Electrification
Section 9621(d)(1)(C) Section 4.2, Transportation Electrification
G. System and Local
Reliability
Section 9621(d)(1)(E) and
Section 9620 (a) and (b)
Section 7.3, Scenario Design; and Section 8.2,
Scenario Analysis
2024 Integrated Resource Plan | 2024 IRP Filing Contents (SB 350 Requirements)
IRP Filing Contents Per CEC
Guidelines Public Utilities Code Sections in REU IRP
1. Reliability Criteria Section 9621(d)(1)(E) and
Section 9620 (a) and (b)
Section 7.3, Scenario Design; and Section 8.2,
Scenario Analysis
2. Local Reliability Area Section 9621(d)(1)(E) and
Section 9620 (a) and (b)
Section 6.4, Transmission System Assessment
3. Addressing Net
Demand in Peak
Hours
Section 9621(c) Section 7.2, Modeling Assumptions; Section 7.3,
Scenario Design; and Section 8.2, Scenario Analysis
H. Greenhouse Gas
Emissions
Section 9621(b)(1) Section 2, Purpose and Background; and Section
4.2, Transportation Electrification
I. Retail Rates Section 9621(b)(3) and
Section 454.52.(a)(1)(C)
and (D)
Section 8.5, Impacts to Redding
J. Transmission and
Distribution Systems
Section 9621(b)(3) and
Section 454.52.(a)(1)(E)
and (F)
Section 5, Existing System and Resource
Description
1. Bulk Transmission
System
Section 9621(b)(3) and
Section 454.52.(a)(1)(E)
and (F)
Section 5.4, Transmission Assets; and Section 6.4,
Transmission System Assessment
2. Distribution System Section 9621(b)(3) and
Section 454.52.(a)(1)(E)
and (F)
Section 5.5, Distribution Assets and Adequacy
K. Localized Air Pollutants
and Disadvantaged
Communities
Section 9621(b)(3) and
Section 454.52.(a)(1)(H)
Section 4.8, Localized Air Pollutants and
Disadvantaged Communities
1-1
CITY OF REDDING ELECTRIC UTILITY
2024|INTEGRATED RESOURCE PLAN
2024 Integrated Resource Plan |Acronyms, Abbreviations, and Definitions List i | Page
Table of Contents
Acronyms, Abbreviations, and Definitions List ............................................................................................ iv
2024 IRP Filing Contents (SB 350 Requirements) ........................................................................................ ix
IRP Project Partners ..................................................................................................................................... xi
Summary of Figures .................................................................................................................................... xii
Summary of Tables ...................................................................................................................................... xv
1. Executive Summary .................................................................................................................................. 1
1.1 Legislative Requirements and Updates ........................................................................................... 2
1.2 Existing Resources and Energy Forecast ......................................................................................... 5
1.3 Modeling and Resource Selection ................................................................................................... 7
1.4 Preferred Plan Evaluation ................................................................................................................ 9
1.5 Conclusion ...................................................................................................................................... 12
2. Purpose and Background ....................................................................................................................... 13
2.1 Background .................................................................................................................................... 14
2.2 Overview of IRP Process ................................................................................................................ 15
2.3 Strategic Framework ...................................................................................................................... 17
2.4 Scenario Development .................................................................................................................. 17
2.5 Stakeholder Process ....................................................................................................................... 18
3. Legislation & Regulation ........................................................................................................................ 22
3.1 State Regulatory Agencies ............................................................................................................. 23
3.2 Federal Oversight Agencies ........................................................................................................... 25
3.3 Changes from 2019 IRP.................................................................................................................. 26
4. Energy Efficiency, Electrification, & Demand Response ....................................................................... 31
4.1 Demand-Side Management Integrated Resource Plan ................................................................. 32
4.2 Transportation Electrification ........................................................................................................ 37
4.3 Building Electrification ................................................................................................................... 41
4.4 Energy Efficiency and Greenhouse Gas Reduction ....................................................................... 42
4.5 Future Programs ............................................................................................................................ 44
4.6 Demand Response Programs ......................................................................................................... 44
2024 Integrated Resource Plan |Acronyms, Abbreviations, and Definitions List ii | Page
4.7 Energy Storage ............................................................................................................................... 44
4.8 Localized Air Pollutants and Disadvantaged Communities ........................................................... 45
5. Existing System and Resource Description ............................................................................................ 47
5.1 Generating Facilities ...................................................................................................................... 48
5.2 Power Purchase Agreements ........................................................................................................ 50
5.3 Renewable Energy Resources ........................................................................................................ 54
5.4 Transmission Assets ....................................................................................................................... 57
5.5 Distribution Assets and Adequacy ................................................................................................. 63
5.6 Natural Gas Commodity, Transportation and Storage .................................................................. 66
5.7 Wholesale Energy Trading ............................................................................................................. 67
5.8 Western Energy Imbalance Market (EIM) ..................................................................................... 67
5.9 Extended Day-Ahead Market (EDAM) ........................................................................................... 68
6. Energy Forecast and System Impacts .................................................................................................... 69
6.1 Historical Energy Use and Peak Demand ...................................................................................... 70
6.2 Forecast Methodology and Assumptions ...................................................................................... 72
6.3 Forecast Results ............................................................................................................................. 77
6.4 Transmission System Assessment ................................................................................................. 80
6.5 Comparison to CEC Forecast ......................................................................................................... 82
7. Modeling Assumptions, Tools, Methodology ........................................................................................ 84
7.1 Modeling Tools .............................................................................................................................. 85
7.2 Modeling Assumptions .................................................................................................................. 87
7.3 Scenario Design .............................................................................................................................. 95
8. Evaluation & Results .............................................................................................................................. 98
8.1 Economic Evaluation Framework .................................................................................................. 99
8.2 Scenario Analysis............................................................................................................................ 99
8.3 Preferred Plan Selection .............................................................................................................. 110
8.4 Sensitivity Cases ........................................................................................................................... 114
8.5 Impacts to Redding ...................................................................................................................... 119
8.6 Conclusion of Evaluation and Results .......................................................................................... 121
9. Appendix .............................................................................................................................................. 122
2024 Integrated Resource Plan |Acronyms, Abbreviations, and Definitions List iii | Page
9.1 Ascend Analytics Resource Planning Modeling ........................................................................... 123
9.2 Study Summaries ......................................................................................................................... 136
9.3 Demand-Side Management IRP (DSM-IRP) ................................................................................. 144
9.4 Renewables Portfolio Standard Procurement and Enforcement Plan ....................................... 148
9.5 Standardized Tables ..................................................................................................................... 163
2024 Integrated Resource Plan |Acronyms, Abbreviations, and Definitions List iv | Page
Acronyms, Abbreviations, and Definitions List
AAEE Additional Achievable Energy Efficiency
AAFS Additional Achievable Fuel Switching
AAGR Annual Average Growth Rate
AB Assembly Bill
AC Alternating Current
ACF
AMI
Advanced Clean Fleet
Advanced Metering Infrastructure
Avangrid Avangrid is an intermediate contracting entity that purchases energy
from Big Horn and provides it to M-S-R PPA.
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
BE
BESS
Building Electrification
Battery Energy Storage System
BPA Bonneville Power Administration
BPS
CAISO
Bulk Power System
California Independent System Operator
CalEnviroScreen
CalEPA
California Communities Environmental Health Screening Tool
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
CCS
CEC
Carbon Capture and Sequestration
California Energy Commission (also Energy Commission)
CEC Guidelines The CEC document, Publicly Owned Utility Integrated Resource Plan
Submission and Review Guidelines (July 2017)
CO Carbon Monoxide
CO2 Carbon Dioxide
CO2e Carbon Dioxide Equivalent
COD
COI
Commercial Operation Date
California-Oregon Intertie
2024 Integrated Resource Plan |Acronyms, Abbreviations, and Definitions List v | Page
Combined Cycle A combined-cycle power plant uses both a gas and steam turbine
together to produce more electricity from the same fuel
COR City of Redding
COSL City of Shasta Lake
COTP California-Oregon Transmission Project
CPUC California Public Utilities Commission
CPWC Cumulative Present Worth Cost
CRAT Capacity Resource Accounting Table (CEC Standardized Table)
CSD Community Service and Development
CV Central Valley
CVP Central Valley Project
DAC
DC
California-designated disadvantaged communities
Direct Current
Decarbonization
Decatherm (Dth)
Electrification
Dekatherm; Measurement of heat equivalent to one MMBTU
DMS
DSM-IRP
DOE
Distribution Management System
Demand-Side Management Integrated Resource Plan
Department of Energy
DSM Demand-Side Management; refers to initiatives that encourage
consumers to optimize energy usage
Dth
Dth/day
Decatherm (Measurement of heat equivalent to one MMBTU)
Decatherm per Day
EBT Energy Balance Table (CEC Standardized Table)
EDAM
EE
EER
EIA
Extended Day-Ahead Market
Energy Efficiency
Eligible Renewable Energy Resources
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
EUE
EV
Expected Unserved Load
Electric Vehicle
FERC Federal Energy Regulatory Commission
2024 Integrated Resource Plan |Acronyms, Abbreviations, and Definitions List vi | Page
Fuel-Substitution
Fuel-Switching
FY
Replacing natural gas, propane, or other heating fuels with electricity
(building electrification)
Replacing gasoline or diesel fuels with electricity (transportation
electrification)
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
Index+
Integrated Energy Policy Report
A contract structure where energy with attributes such as a Renewable
Energy Credit is purchased at a price based on a market index plus an
additional fixed amount for the attribute. The attribute is assigned to the
purchaser and the energy is settled in an energy market at its index price.
IPP Independent Power Producer
IRP Integrated Resource Plan
IRP Filing POU Adopted IRP Accompanied By The Required Supporting Information
JPA Joint Powers Agency
LCFS
LCOE
Low Carbon Fuel Standards
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
LOLH
LTP
MACRS
Lossof Load Hours
Long-Term Procurement Requirements
Modified Accelerated Cost Recovery System – the current tax
depreciation system in the US
MMBTU One Million British Thermal Units (1,000,000 BTU)
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
2024 Integrated Resource Plan |Acronyms, Abbreviations, and Definitions List vii | Page
MT
MTCO2e
Metric Ton
Amount of a Greenhouse Gas whose atmospheric impact has been
standardized to one unit mass of carbon dioxide, based on the global
warming potential of the gas
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
OMS
OSI-SCADA
PACI
PBR
PEV
Outage Management System
Open Systems International- Supervisory Control and Data Acquisition
Pacific AC Intertie
Portfolio Balance Requirements
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
REU
RPS
City of Redding Electric Utility
Renewables Portfolio Standard
RPS Eligible Renewable resource with under 30MW capacity
RPT RPS Procurement Table
SAE Statistically Adjusted End-Use
SB Senate Bill
SB 100
SB 350
Senate Bill 100, De Leon. 100 Percent Clean Energy Act of 2018
Senate Bill 350 (De León, Chapter 547, Statutes of 2015)
SB 1020 Senate Bill 1020, Laird. Clean Energy, Jobs, and Affordability Act of 2022
2024 Integrated Resource Plan |Acronyms, Abbreviations, and Definitions List viii | Page
SB 1037 Senate Bill 1037. Energy Efficiency (2005)
Scenario Portfolio expansion plans developed and compared
SMUD
SNR
SOTP
Sacramento Municipal Utility District
Sierra Nevada
South of Tesla Principles
TAC Transmission Access Charge
TANC
TE
TPUD
Transmission Agency of Northern California
Transportation Electrification
Trinity Public Utilities District
UG
USBR
VAR
United States Bureau of Reclamation
Volt-Amp Reactive
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
2024 Integrated Resource Plan |2024 IRP Filing Contents (SB 350 Requirements) ix | Page
2024 IRP Filing Contents (SB 350 Requirements)
IRP Filing Contents Per CEC
Guidelines Public Utilities Code Sections in REU IRP
A. Planning Horizon Section 9621(b) (1) and (2) IRP’s planning horizon is 2023-2045 (Throughout
IRP)
B. Scenarios and Sensitivity
Analysis
Section 9621 (d) Section 7, Modeling Assumptions, Tools,
Methodology
C. Standardized Tables N/A Exhibit 9.5 Standardized Tables
1. Capacity Resource
Accountable Table
(CRAT)
N/A Exhibit 9.5 Standardized Tables
2. Energy Balance
Table (EBT)
N/A Exhibit 9.5 Standardized Tables
3. RPS Procurement
Table (RPT)
N/A Exhibit 9.5 Standardized Tables
4. GHG Emission
Accounting Table
(GEAT)
N/A Exhibit 9.5 Standardized Tables
D. Supporting Information N/A Supporting information to supplement data in the
Standardized Tables may be found in the charts,
graphs, and narratives in the IRP
E. Demand Forecast N/A Section 6, Energy Forecast and System Impacts
1. Reporting
Requirements
N/A Exhibit 9.5 Standardized Tables
2. Demand Forecast
Methodology and
Assumptions
N/A Section 6.2, Forecast Methodology and
Assumptions
3. Demand Forecast-
Other Regions
N/A Section 6.2, Forecast Methodology and
Assumptions; and Section 8.4, Sensitivity Cases
F. Resource Procurement
Plan
Section 9621(b) and (d) Section 4, Energy Efficiency, Electrification, and
Demand Response Programs
1. Diversified
Procurement
Portfolio
Section 9621(d)(1)(D) Section 7.2, Modeling Assumptions; and Section
8.4, Sensitivity Cases
2. RPS Planning
Requirements
Section 9621(b)(2) and
Section 399.11
Section 8.2, Scenario Analysis
3. Energy Efficiency
and Demand
Response Resources
Section 9621(d)(1)(A)
Section 9615
Section 4.4, Energy Efficiency and Greenhouse Gas
Reduction; and Section 4.6, Demand Response
Programs
4. Energy Storage Section 9621(d)(1)(B)
Chapter 7.7 (commencing
with Section 2835) of Part
2 of Division 1
Section 4.7, Energy Storage
2024 Integrated Resource Plan |2024 IRP Filing Contents (SB 350 Requirements) x | Page
5. Transportation
Electrification
Section 9621(d)(1)(C) Section 4.2, Transportation Electrification
G. System and Local
Reliability
Section 9621(d)(1)(E) and
Section 9620 (a) and (b)
Section 7.3, Scenario Design; and Section 8.2,
Scenario Analysis
1. Reliability Criteria Section 9621(d)(1)(E) and
Section 9620 (a) and (b)
Section 7.3, Scenario Design; and Section 8.2,
Scenario Analysis
2. Local Reliability Area Section 9621(d)(1)(E) and
Section 9620 (a) and (b)
Section 6.4, Transmission System Assessment
3. Addressing Net
Demand in Peak
Hours
Section 9621(c) Section 7.2, Modeling Assumptions; Section 7.3,
Scenario Design; and Section 8.2, Scenario Analysis
H. Greenhouse Gas
Emissions
Section 9621(b)(1) Section 2, Purpose and Background; and Section
4.2, Transportation Electrification
I. Retail Rates Section 9621(b)(3) and
Section 454.52.(a)(1)(C)
and (D)
Section 8.5, Impacts to Redding
J. Transmission and
Distribution Systems
Section 9621(b)(3) and
Section 454.52.(a)(1)(E)
and (F)
Section 5, Existing System and Resource
Description
1. Bulk Transmission
System
Section 9621(b)(3) and
Section 454.52.(a)(1)(E)
and (F)
Section 5.4, Transmission Assets; and Section 6.4,
Transmission System Assessment
2. Distribution System Section 9621(b)(3) and
Section 454.52.(a)(1)(E)
and (F)
Section 5.5, Distribution Assets and Adequacy
K. Localized Air Pollutants
and Disadvantaged
Communities
Section 9621(b)(3) and
Section 454.52.(a)(1)(H)
Section 4.8, Localized Air Pollutants and
Disadvantaged Communities
2024 Integrated Resource Plan |IRP Project Partners xi | Page
IRP Project Partners
Ascend Analytics Modeling software company contracted by REU for portfolio modeling
services
Curve Developer Software developed by Ascend Analytics to forecast market gas and
power prices
Dunsky Energy +
Climate Advisors
Consultant contracted by REU to develop the Building and
Transportation Electrification Forecast through 2045
GreatBlue
2022 Comprehensive Residential and Commercial Customer Survey
Itron, Inc.
Consultant contracted by REU to develop the Utility’s comprehensive
load forecast
SMUD (Sacramento Municipal Utility District) Contracted to conduct the
Transmission Assessment Study
2024 Integrated Resource Plan |Summary of Figures xii | Page
Summary of Figures
Figure 1-1: REU Current Portfolio RPS Outlook ............................................................................................... 6
Figure 1-2: REU Current Portfolio Carbon-Free Energy .................................................................................. 7
Figure 1-3: Carbon Profile Net-Zero Carbon 2045 ........................................................................................ 10
Figure 1-4: Energy Supply Stack – Net-Zero Carbon 2045 ............................................................................ 10
Figure 3-1: Regulatory Oversight of REU ....................................................................................................... 23
Figure 4-1: CEC Targets, AAEE/FS, and Approved Goals .............................................................................. 33
Figure 4-2: DSM-IRP Five-Step Process .......................................................................................................... 34
Figure 4-3: City Council Approved Goals vs. Estimated Energy Savings ....................................................... 36
Figure 4-4: Cumulative Savings: Forecast, Savings Achieved, & Goals ......................................................... 37
Figure 5-1: Initial Term Costs vs. Extension Term Cost Components ........................................................... 51
Figure 5-2: WAPA Costs - Historical and Forecast ......................................................................................... 53
Figure 5-3: 2019 IRP Scenario H v. SB 100 Renewable Requirements with Ineligible RECs Removed ......... 55
Figure 5-4: 2019 IRP Scenario H vs. SB 1020 Carbon-Free Targets ............................................................... 56
Figure 5-5: REU Existing Transmission ........................................................................................................... 58
Figure 5-6: Balancing Area of Northern California (BANC) Members ........................................................... 60
Figure 5-7: Electric Distribution System ........................................................................................................ 63
Figure 5-8: Reliability Comparison ................................................................................................................. 64
Figure 6-1: 5-Year Average Monthly Energy Sales and Peak Demand (2018-2022) ..................................... 70
Figure 6-2: Average Daily Load Profile by Month (2018-2022) ..................................................................... 71
Figure 6-3: Projected Solar Installations ........................................................................................................ 74
Figure 6-4: Projected Light-Duty Electric Vehicles – REU Service Territory .................................................. 76
Figure 6-5: Projected Medium Duty Electric Vehicles –REU Service Territory ............................................. 76
Figure 6-6: Load Forecast Comparison .......................................................................................................... 79
Figure 6-7: Peak Load Forecast Comparison ................................................................................................. 80
Figure 6-8: Energy Requirements Comparison: REU Forecast vs. CEC Forecast for REU ............................. 82
Figure 6-9: Peak Demand Comparison: REU Forecast vs. CEC Forecast for REU .......................................... 83
Figure 7-1: Carbon Forward Price .................................................................................................................. 87
Figure 7-2: In-State Energy Imports Forward Price ....................................................................................... 88
Figure 7-3: In-State Energy Exports Forward Price ........................................................................................ 88
2024 Integrated Resource Plan |Summary of Figures xiii | Page
Figure 7-4: Out-of-State Energy Forward Price ............................................................................................. 89
Figure 7-5: Natural Gas Forward Price........................................................................................................... 89
Figure 8-1: Carbon-Free Energy – Base Case ............................................................................................... 100
Figure 8-2: Carbon-Free Energy – Net- Zero Carbon 2045 ......................................................................... 101
Figure 8-3: Carbon-Free Energy – 100% Zero Carbon 2045........................................................................ 101
Figure 8-4: Renewable Energy Compliance – Base Case ............................................................................. 102
Figure 8-5: Renewable Energy Compliance – Net-Zero Carbon 2045 ........................................................ 103
Figure 8-6: Renewable Energy Compliance – 100% Zero Carbon 2045 ...................................................... 103
Figure 8-7: Planning Reserve Margin – Base Case ....................................................................................... 104
Figure 8-8: Planning Reserve Margin – Net-Zero Carbon 2045 .................................................................. 105
Figure 8-9: Planning Reserve Margin – 100% Zero Carbon 2045 ................................................................ 105
Figure 8-10: Energy Supply Stack – Base Case............................................................................................. 107
Figure 8-11: Energy Supply Stack – Net-Zero Carbon 2045 ........................................................................ 108
Figure 8-12: Energy Supply Stack – 100% Zero Carbon 2045 ..................................................................... 109
Figure 8-13: Levelized Annual CWPC by Scenario, $/MWh ........................................................................ 110
Figure 8-14: Carbon Emission Outlook for Preferred Plan with Operating Constraints ............................. 114
Figure 8-15: High Load Scenario Load Forecast .......................................................................................... 115
Figure 8-16: Energy Supply Stack – High Load Scenario .............................................................................. 116
Figure 8-17: Planning Reserve Margin – Net-Zero Carbon Diverse Portfolio ............................................. 117
Figure 8-18: Renewable Energy Compliance – Net-Zero Carbon Diverse Portfolio ................................... 118
Figure 8-19: Carbon-Free Energy – Net-Zero Carbon Diverse Portfolio ..................................................... 118
Figure 8-20: REU Fiscal Year 2023 Budget Breakdown ............................................................................... 120
Figure 9-1: Dispatch outputs over a three-day period plotted against load ............................................... 123
Figure 9-2: ARS Schematic ........................................................................................................................... 124
Figure 9-3: PowerSimm Flow Chart ............................................................................................................. 125
Figure 9-4: Multiple simulations of daily maximum dry bulb temperature across a single year. .............. 127
Figure 9-5: Multiple simulations of load over a single week. ...................................................................... 128
Figure 9-6: Load vs Temperature ................................................................................................................. 129
Figure 9-7: Multiple simulations of solar generation over a single week. .................................................. 130
Figure 9-8: Multiple simulations of wind generation over a single week. .................................................. 131
2024 Integrated Resource Plan |Summary of Figures xiv | Page
Figure 9-9: Multiple simulations of hydro generation over a single week. ................................................ 132
Figure 9-10: Multiple simulations of forward prices. .................................................................................. 134
Figure 9-11: Simulations for spot prices over a single week ....................................................................... 134
2024 Integrated Resource Plan |Summary of Tables xv | Page
Summary of Tables
Table 1-1: SB 100 RPS Procurement Targets ................................................................................................... 4
Table 1-2: REU Calendar Year 2022 Energy Resources ................................................................................... 6
Table 1-3: Potential Resources for Selection .................................................................................................. 8
Table 1-4: Selected Resources for Scenarios ................................................................................................... 9
Table 1-5: CPWC for Scenarios with Resource Cost ...................................................................................... 11
Table 1-6: REU Predicted Energy Cost Rates in 2045 .................................................................................... 11
Table 2-1: Scenario Development .................................................................................................................. 18
Table 3-1: SB 100 RPS Procurement Targets ................................................................................................. 27
Table 3-2: SB 100 Portfolio Balancing Requirements .................................................................................... 28
Table 4-1: 2021 REU Council-approved EE Goals .......................................................................................... 32
Table 4-2: Cost-Effectiveness Tests Used for Program Evaluation ............................................................... 35
Table 5-1: Calendar Year 2022 Energy Resources ......................................................................................... 48
Table 5-2: Historic Deliveries from WAPA CVP .............................................................................................. 52
Table 5-3: Current (Calendar Year 2022) Clean Energy Resources ............................................................... 54
Table 5-4: Contracted PCC1 REC Deliveries ................................................................................................... 57
Table 5-5: WAPA Transmission Service Summary Information ..................................................................... 59
Table 5-6: Natural Gas Fixed Price Hedges .................................................................................................... 66
Table 6-1: Historic Customer, Sales, and Demand Data ................................................................................ 72
Table 6-2: Load Forecast Assumptions and Input Considerations ................................................................ 73
Table 6-3: Projected Net Energy Requirements, Peak Demand Forecast, and Load Factor ........................ 78
Table 7-1: Forward Energy Price Assumptions .............................................................................................. 90
Table 7-2: Forward Gas, Carbon, and REC Price Assumption ........................................................................ 91
Table 7-3: Potential Resources ...................................................................................................................... 92
Table 7-4: Renewable PPA Price Forecast, $/MWh ....................................................................................... 93
Table 7-5: Renewable Fuel Price Forecast, $/Dth ......................................................................................... 93
Table 7-6: Resource Effective Load Carrying Capability as % of Nameplate Assumptions ........................... 94
Table 7-7: Resource Annual Capacity Factor Assumptions ........................................................................... 94
Table 7-8: IRP Scenario Comparison .............................................................................................................. 96
Table 8-1: Selected Resources for Scenarios ............................................................................................... 100
2024 Integrated Resource Plan |Summary of Tables xvi | Page
Table 8-2: LOLH for Current Portfolio .......................................................................................................... 106
Table 8-3: LOLH with RPP Removed and 200 MW Battery Storage in 2045 ............................................... 107
Table 8-4: CPWC for Scenarios with Resource Cost .................................................................................... 109
Table 8-5: Load and Resource Balance for Preferred Plan with Operating Constraints ............................. 113
Table 8-6: Selected Resource Additions for Diverse Portfolio Scenario - Nameplate Capacity, MW ........ 117
Table 8-7: Diverse Portfolio CPWC Comparison to IRP Scenarios ............................................................... 119
Table 8-8: REU Predicted Energy Cost Rates in 2045 .................................................................................. 120
Table 9-1: Summary of Reactive Margin ..................................................................................................... 139
Table 9-2: Summary of Cost-Effectiveness Components for Each Measure Test ....................................... 145
Table 9-3: Program Performance of FY 2019 EE Programs (Historic) vs. Future BE and TE Programs ...... 146
2024 Integrated Resource Plan |Executive Summary 1 | Page
1. Executive Summary
This report (Report) presents the Integrated
Resource Plan (IRP) for the City of Redding’s
Electric Department (REU), owner of a non-profit,
vertically integrated utility providing electric
service to approximately 45,000 customers in
and near Redding, California within a service area
that covers approximately 61 square miles. REU’s
vision is to make Redding better by connecting
with customers and being their trusted and
reliable, community-owned utility. This
overarching objective is achieved by providing
reliable, cost-effective service, while complying
with state and federal mandates and regulations.
This Report offers a current and comprehensive
examination, analysis, assessment, and selection
of the Utility's preferred resource plan, aimed at
facilitating REU's vision and enhancing its
established goals and objectives.
An IRP is a long-term, comprehensive plan
developed to help ensure that REU 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
meeting future resource requirements while
complying with clean energy mandates and
objectives. Acquisitions will be thoroughly
evaluated in the normal course and the standard
procurement process will be followed.
2024 Integrated Resource Plan |Executive Summary 2 | Page
The 2024 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 2045. Incorporated into the IRP are anticipated changes to the utility industry and
California over the planning period.
Although significant changes within the electric utility industry are anticipated to occur over the 20-year
planning horizon for the IRP, REU must plan for sufficient supplies of electricity while also maintaining
affordable rates 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 and narrowed down to those that met objectives of the IRP’s guiding
framework. The IRP process has also taken into consideration the need to establish a plan that will allow
flexibility to respond to uncertainty regarding future technology and regulatory change.
1.1 Legislative Requirements and Updates
The initial IRP filed in 2019 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. SB 350 established requirements for any publicly owned utility
(POU) with an average load greater than 700 GWh (in the 2013-16 period) to develop and adopt an IRP by
January 1, 2019, and update it with the California Energy Commission (CEC) at least every five years.
Redding is the smallest utility in California required to complete an IRP, with an average annual load of
approximately 745 GWh.
SB 350 was superseded by Senate Bill 100 (herein SB 100), which updated the State’s Renewables Portfolio
Standard (RPS) requirements, established carbon-reduction goals, and required the CEC, the California
Public Utilities Commission (CPUC), and the California Air Resource Board (CARB) to file a joint policy report
on SB 100 by 2021.
California’s clean energy mandates have expanded to include, but are not limited to, the following:
SB 100: renewable energy and zero-carbon resources must supply 100 percent of electric retail
sales to end-use customers by 2045
Renewables Portfolio Standards (RPS): requires that by 2030, at least 60 percent of California’s
electricity is generated from renewable resources; sets long-term contract requirements
Energy Efficiency Standards: aims to reduce energy consumption and promote energy-saving
practices among utility customers
Carbon reduction targets established by Senate Bill 1020 starting in 2035
POUs must develop an IRP that sets forth the plan to achieve the above goals and other
objectives such as those related to reliability and cost-effectiveness
Transportation electrification plans must be included in the IRP
2024 Integrated Resource Plan |Executive Summary 3 | Page
The CEC requires an updated IRP to be filed by 2024; therefore, REU embarked on a comprehensive and
inclusive process to update its IRP initially filed in 2019. The IRP process involved a series of studies,
assessments, modeling, and stakeholder engagement activities aimed at ensuring that the plan aligns with
the organization's goals and effectively addresses the evolving energy landscape and customer needs.
Greenhouse Gas Cap-and-Trade Program (GHG Program)
Program Administration and Oversight
The CARB oversees health and air quality standards for the state. CARB sets the State’s air quality standards
at levels that protect those greatest at risk, and is the agency tasked with developing policies for combating
climate-change through measures that promote a more energy-efficient, carbon-free, and resilient
economy. CARB policies typically exceed federal emissions standards. Key activities include:
Administer Cap-and-Trade and Greenhouse Gas programs (AB 32)
Developing Scoping Plans (AB 1279) for carbon-neutrality pathways to meet California goals
Administer the State’s Low Carbon Fuel Standards (LCFS) Program
Program Overview
California's cap-and-trade greenhouse gas program is a key component of the State's comprehensive
strategy to combat climate change. Under this program, a cap, or limit, is set on the total amount of
greenhouse gas emissions allowed from certain sectors of the economy, primarily industries and power
plants. These entities are required to hold allowances equal to their emissions, and a portion of these
allowances are auctioned by the State.
The program encourages emission reductions by creating a market for emissions allowances, where entities
can buy and sell allowances as needed to comply with the cap. Over time, the cap is gradually reduced,
leading to a decrease in allowable emissions and incentivizing emissions reduction efforts. Revenue
generated from the sale of allowances is reinvested in various programs aimed at further reducing
greenhouse gas emissions, promoting renewable energy, and supporting disadvantaged communities
disproportionately affected by pollution.
Renewables Portfolio Standards (RPS Program)
Program Administration and Oversight
The California Energy Commission (CEC) began implementing policies in the late 1990s and early 2000s to
address environmental concerns, promote clean energy, and reduce greenhouse gas emissions. California
passed Senate Bill 1078 in 2002, which established the Renewables Portfolio Standards (RPS) program.
The RPS program is a regulatory policy that mandates utilities and energy providers to procure a specified
percentage of their electricity from renewable resources, such as wind, solar, hydro, and biomass. The
program’s objective is to promote the use of renewable energy resources within the State’s electric grid.
Program Overview
When renewable energy is produced, one Renewable Energy Credit (REC) is created for each megawatt-
hour (MWh) of electricity generated from eligible renewable resources. REC represent environmental
2024 Integrated Resource Plan |Executive Summary 4 | Page
attributes of clean energy production. Utilities can use purchased or generated RECs to demonstrate
compliance with renewable energy targets, which are either retired or banked for future compliance. RECs
are categorized based on criteria within the regulations, which specify the percentage of each type of REC
that can be used to satisfy compliance requirements. Some of the key requirements of the RPS program
are:
Procurement Requirement: At least 60 percent of REU’s electric retail sales must be served by
eligible renewable resources by 2030
Long-Term Portfolio Requirement: For the compliance period beginning January 1, 2021, and
each compliance period thereafter, at least 65 percent of the electricity products applied
toward the RPS procurement target shall be from contracts of 10 years or more in duration or
ownership or ownership agreements for eligible renewable energy resources
Portfolio Balance Requirements: Beginning January 1, 2021, at least 75 percent of RPS
procurement shall be from bundled, in-state energy contracts, with a maximum of 10 percent
of RPS procurement from out-of-state RECs.
The CEC adopted revised RPS Enforcement Regulations on December 22, 2020. The updated RPS
Enforcement Regulations included the revised renewables and emissions targets from SB 100. In March
2023, Redding City Council (Council) approved modifications made to REU's RPS Enforcement Program and
Procurement Plan to reflect recent updates to the regulations (Exhibit 9.4). In addition to the updated
procurement targets for each compliance period shown in Table 1-1 below, the newest regulations require
utilities to meet specific Long-Term Procurement Requirements (LTP) and Portfolio Balance Requirements
(PBR).
Table 1-1: SB 100 RPS Procurement Targets
Compliance
Period 4 5 6 7
Year 2023 2024 2025 2026 2027 2028 2029 2030 2031…
RPS Target 41.25% 44.00% 46.00% 50.00% 52.00% 54.67% 57.33% 60.00% 60.00%
Senate Bill 1020
Governor Newsom signed the SB 1020 bill, also known as the 100% Clean Electric Grid bill, on September
16, 2022. This legislation aims to significantly decrease California's reliance on fossil fuels in three stages.
According to the policy, the State's goal is to have 90% of all retail sales of electricity supplied by eligible
renewable energy resources and zero-carbon resources by 2035. This target will be followed by a 5%
increase by 2040, leading to the ultimate objective of achieving 100% clean energy by 2045.
Impacts of Updated Regulations
Recognizing the importance of being flexible and adaptable, REU remains committed to staying informed
of evolving clean energy regulations, targets, and objectives in California, and is well-positioned to adapt
its portfolio modeling accordingly. The preferred scenario selected in the 2019 IRP no longer aligns with
2024 Integrated Resource Plan |Executive Summary 5 | Page
the State's updated regulatory requirements, necessitating the identification of new resources and
timelines to ensure regulatory compliance.
REU aims to ensure the IRP remains robust and responsive to changing regulations throughout the planning
period. To achieve this, modeling and scenario development methodologies have shifted to one that is
centered around compliance requirements rather than renewable resource identification. The scenarios
developed for this IRP account for the varying degrees of compliance needed to meet clean energy
mandates, with an anticipation of increasingly stringent renewable energy and carbon reduction
requirements imposed by regulatory bodies.
Regulatory requirements for clean energy and carbon reduction will likely become more stringent over
time. Through continuous monitoring of regulatory developments, engagement with regulatory
authorities, and iterative modeling processes, REU remains committed to maintaining compliance with
updated clean energy regulations. By incorporating these expectations into the modeling process, the
organization can assess the implications on resource selection, investment strategies, and operational
plans. This forward-thinking approach positions REU to proactively respond to regulatory changes and
achieve long-term sustainability goals while providing reliable and affordable electricity services to its
constituents.
1.2 Existing Resources and Energy Forecast
Existing Resources
The electric resources used to meet the power requirements of customers include generation supply
resources, renewable resources, contractual power purchases, transmission assets, and natural gas supply
facilities. These resources and assets are described in Section 5. REU’s generation resources include:
Redding Power Plant – a 183.1 MW natural gas power plant consisting of combined cycle and
simple cycle generators owned by REU
Whiskeytown Small Hydro – a 3.5 MW eligible renewable hydro generator owned by REU
Big Horn Wind – a Power Purchase Agreement (PPA) for approximately 70 MW of eligible
renewable wind generation from Big Horn Wind Project in Klickitat County, Washington.
Western Base Resource – a PPA contract for approximately 8% of the Central Valley Project
(CVP) hydro generation resources marketed by the Western Area Power Administration (WAPA)
Renewable Energy Purchases – long-term and short-term PPA’s with an Index+ contract
structure for eligible renewable energy from various generators in various quantities
In light of the revised clean energy mandates and targets established through the enactment of SB 100 and
SB 1020, the preferred resource portfolio identified in the 2019 IRP no longer aligns with the State's
requirements concerning renewable energy and carbon mitigation. Table 1-2 below depicts REU’s existing
energy resources and their contribution to customer load, renewable compliance, and carbon-free targets.
2024 Integrated Resource Plan |Executive Summary 6 | Page
Table 1-2: REU Calendar Year 2022 Energy Resources
Capacity Available (MW) Annual Energy (GWh) Percent of Total
Energy
Generated Power
Redding Power Plant1 (U1-U6) 183.1 426,918 60%
Whiskeytown (U9) 3.5 25,916 4%
Total Generated Power 186.6 452,834 64%
Carbon-Free Power Purchase Agreements
WAPA Base Resource2 128.5 63,163 9%
Big Horn I Wind Project 23.0 163,586 23%
Total Purchased Power 151.5 226,749 32%
Market Power
Market Power Purchases - 149,939 21%
Market Power Sales - -117,111 -16%
Net Market Power - 32,828 5%
Total 338.1 712,411 100%
1. Capacity listed is nameplate capacity (EIA860 defined) for Redding Power Plant.
2. The hydro-based contract with WAPA is for 128.5 MW, but the average summer planning capability is 74 MW.
Figure 1-1 below illustrates the current portfolio’s inability to meet the updated renewable energy
requirements beyond 2030.
Figure 1-1: REU Current Portfolio RPS Outlook
-
500,000
1,000,000
1,500,000
2,000,000
2,500,000
3,000,000
0%
20%
40%
60%
80%
100%
120%
WAPA Big Horn Whiskeytown
Index+Optimized Banked Retirement RPS Requirement
Rolling Banked RECs
2024 Integrated Resource Plan |Executive Summary 7 | Page
Based on the current resource portfolio, Figure 1-2 demonstrates the inability to meet newly introduced
carbon emissions targets set forth in Senate Bill 1020 starting in 2035.
Figure 1-2: REU Current Portfolio Carbon-Free Energy
Energy Forecast
The load forecast developed by Itron, Inc. (Itron), the consultant contracted to provide load forecasting
services for REU, and Dunsky Climate + Energy Advisors (Dunsky), the consultant contracted to forecast
load impacts from electrification (further described in Section 6.2) is the foundation upon which the IRP
was built. REU also contracted with Ascend Analytics (Ascend) to conduct portfolio modeling services.
1.3 Modeling and Resource Selection
As highlighted in Section 8.2 of this report, REU's current portfolio does not align with the State’s clean
energy mandates. Consequently, scenarios have been formulated within the outlined strategic framework
to incorporate future resources aimed at achieving renewable energy compliance and carbon reduction
targets. REU collaborated with Ascend, who furnished forecast models to evaluate the diverse attributes
associated with each identified technology (Table 1-3). This approach allowed the model to operate without
technology constraints, permitting the selection of technologies based on their economic performance
within energy markets.
Recognizing the importance of involving diverse perspectives and gathering input from key stakeholders,
REU formed a dedicated stakeholder group to review the results and provide insights on the Utility's
direction. The stakeholder group consisted of representatives from customer advocacy organizations,
environmental groups, regulatory agencies, community organizations, and other relevant entities. This
collaborative approach ensured that the IRP development process benefited from the collective expertise
and input of a broad range of stakeholders.
0%
20%
40%
60%
80%
100%
120%
WAPA Big Horn Whiskeytown SB 1020
2024 Integrated Resource Plan |Executive Summary 8 | Page
This IRP was developed based on the following strategic framework: The preferred 2024 IRP scenario should
meet or exceed the State’s clean energy mandates while balancing reliability and affordability.
Using this framework, REU developed the following scenarios for modeling and evaluation:
Low Scenario: “Current Portfolio” - does not meet mandates
Mid Scenario: “Net-Zero Carbon 2045” - meets mandates
High Scenario: “100% Zero Carbon 2045” - exceeds mandates
REU owns and operates a natural gas fired combined cycle generation plant, Redding Power Plant (the
Plant). The specifics of the Plant are described in Section 5.1. The “Net-Zero Carbon 2045” scenario assumes
that net-zero carbon can be achieved while continuing to operate REU’s natural gas power plant for system
reliability. In contrast, the “100% Zero Carbon 2045” scenario assumes that REU will not generate any
carbon and could no longer rely on the Plant for reliability.
REU worked with partners and consultants to develop and optimize models and forecasts around these
scenarios to determine a preferred approach to resource planning and procurement over the 20-year
planning horizon.
Table 1-3: Potential Resources for Selection
Resource Assumptions Dispatchable RPS Eligible Carbon-free
Solar Southern California,
Northern California No Yes Yes
Wind
Southern California,
Northern California,
Offshore, New Mexico
No Yes Yes
Renewable Gas REU Prepay Gas Agmt. Yes Yes Yes*
Carbon Capture REU Prepay Gas Agmt. Yes No* Yes
Hydrogen Assume NG Retrofit Yes Yes* Yes
Storage 4 Hour Battery, 8 Hour
Battery Yes N/A N/A
Geothermal California Yes Yes Yes
Biomass California, Assume PPA Yes Yes Depends
* Renewable or Carbon-free eligibility depends on the fuel source
2024 Integrated Resource Plan |Executive Summary 9 | Page
1.4 Preferred Plan Evaluation
REU worked with a key stakeholder group that unanimously selected the Net-Zero Carbon 2045 Scenario
as the preferred plan for the 2024 IRP, recognizing the vital role of the Plant in ensuring reliable and
affordable energy throughout the planning horizon.
Net-Zero Carbon 2045 Plan Defining Characteristics:
Allows the continued dispatch of Redding Power Plant with the use of carbon allowances
To meet SB 1020 targets, the Redding Power Plant is primarily running for peaking load
To meet planning criteria, the following resources are added:
● 2031: 150 MW of solar and 25 MW of 8-hr battery storage
● 2034: 50 MW of solar
● 2037: 50 MW of solar and 15 MW of 8-hr battery storage
● 2041: 50 MW of solar and 15 MW of 8-hr battery storage
● 2045: 40 MW of solar
In total, this results in the addition of 340 MW of solar generation and 55 MW of 8-hour battery storage to
the portfolio through the 2045 planning horizon.
The stakeholders strongly encouraged staff to reduce fossil-fuel generation before the 2045 timeframe and
seek opportunities to reduce carbon where feasible without compromising reliability. Additional resources
and capacities needed to meet demand and clean energy mandates are outlined below in Table 1-4.
Table 1-4: Selected Resources for Scenarios
Net-Zero Carbon 2045 100% Zero Carbon 2045
Year Solar (NorCal
+ SoCal) MW
Storage (8-hour
Battery) MW
Solar (NorCal +
SoCal) MW
Storage (8-hour
Battery) MW
Natural Gas
CCS MW
Hydrogen
MW
2031 150 25 200 25 - -
2034 50 - - - - -
2037 50 15 25 15 - -
2041 50 15 35 160 25 95
2045 40 - - - - -
As seen in Figure 1-3 below, with the additional resources specified in the model’s preferred scenario, REU’s
resource portfolio would meet the State’s clean energy mandates, including the SB 1020 carbon targets
that begin in 2035 and increase to meet to the 2045 timeline.
2024 Integrated Resource Plan |Executive Summary 10 | Page
Figure 1-3: Carbon Profile Net-Zero Carbon 2045
Various energy resource technology types identified in the preferred scenario that allow REU to serve
customer demand while meeting clean energy mandates are illustrated below in Figure 1-4. While solar is
recognized as a cost-effective resource option, given its intermittent attributes, the model employs an
approach of overbuilding solar resources to guarantee an ample energy supply for peak load demands. In
the figure below, “Out-of-State Imports/Exports” primarily refers to energy sales and purchases from
power producers in the Pacific Northwest to serve customer demands.
Figure 1-4: Energy Supply Stack – Net-Zero Carbon 2045
0%
20%
40%
60%
80%
100%
120%
140%
WAPA Big Horn Whiskeytown Solar SB 1020
-750,000
-250,000
250,000
750,000
1,250,000
1,750,000
MW
h
RPP WAPA Big Horn Whiskeytown
Solar Battery Out-of-State Imports In-State Imports
In-State Exports Out-of-State Exports Total
2024 Integrated Resource Plan |Executive Summary 11 | Page
Power Supply Cost
A comparison of the cumulative present worth cost (CPWC) across the assessed scenarios, using both total
cost and cost per megawatt hour metrics is presented below (Table 1-5). The Net-Zero Carbon 2045
scenario exhibits a slightly reduced portfolio cost when compared to the existing portfolio. Conversely, the
100% Zero-Carbon 2045 scenario demonstrates a notably higher cost in comparison to both the Current
Portfolio and the Net-Zero Carbon 2045 Scenario.
Table 1-5: CPWC for Scenarios with Resource Cost
Current Portfolio Net-Zero Carbon
2045
100% Zero
Carbon 2045
RPP $14 $13 $15
WAPA $140 $140 $140
Bighorn $102 $102 $102
Whiskeytown $0 $0 $0
Solar $0 $227 $227
8 Hour Battery $0 $200 $477
NG with CCS $0 $0 $83
Hydrogen $0 $0 $96
Market Imports $624 $370 $307
Market Exports -$26 -$205 -$209
Index+ RECs $23 $23 $23
Total, $M $878 $870 $1,263
Levelized CPWC, $/MWh $54.70 $54.25 $79.12
Table 1-6 below provides an estimate of the change in energy costs in 2045 across the modeled scenarios.
These are estimates of the levelized energy costs for that year. The CWPC shows an average levelized
energy cost over the entire planning horizon. Despite the higher energy cost per kilowatt-hour (kWh) in
2045 compared to the Current Portfolio, the CPWC shows the Net-Zero Carbon 2045 plan is more cost-
effective over the entire planning period.
Table 1-6: REU Predicted Energy Cost Rates in 2045
Current Portfolio Net-Zero Carbon
2045
100% Zero Carbon
2045
Energy Cost in 2023 ($/kWh) $0.0574 $0.0574 $0.0574
Energy Cost in 2045 ($/kWh) $0.0765 $0.0866 $0.2079
Energy Cost Change ($/kWh) $0.0191 $0.0292 $0.1505
2024 Integrated Resource Plan |Executive Summary 12 | Page
1.5 Conclusion
In summary, the IRP process has been a complex comprehensive journey, resulting in the identification of
a Preferred Plan that will ultimately shape Redding’s energy future. The Net-Zero Carbon 2045 plan calls
for additional renewable energy resources to satisfy clean energy mandates. Overall, through strategic
implementation of those resources, the total portfolio cost to serve retail customers will decrease by
$8,000,000 over the 20-year planning horizon. Due to increasing carbon and gas prices, integrating
renewable resources in the portfolio reduces power supply costs, as the cost-effectiveness of intermittent
resources is move favorable than the thermal generation resources in today’s portfolio.
The preferred Net-Zero Carbon 2045 scenario, as explained in the Report, aligns with the overarching goals
and objectives of the IRP and integrates renewable energy resources and sustainable practices into REU's
energy portfolio. It represents a flexible and adaptable strategy, preserving the reliability and affordability
of energy services while achieving the State's clean energy targets and objectives. The Preferred Plan
protects the financial interests of REU's valued customers and signifies a pivotal step forward in the Utility's
ongoing journey towards a resilient, responsible, and forward-thinking energy landscape.
2024 Integrated Resource Plan |Purpose and Background 13 | Page
2. Purpose and Background
The City of Redding (COR) recognizes the critical
role that electricity plays in supporting the
growth and vitality of its community. As an
essential utility service provider, REU is
committed to making informed decisions that
address the evolving energy landscape while
considering the unique needs of its customers,
environmental sustainability, technological
advancements, and regulatory requirements.
As a publicly owned utilities (POU), REU is
accountable to its ratepayers and stakeholders.
In today's rapidly evolving energy landscape,
POUs face the responsibility of making informed,
forward-looking decisions that balance
competing interests: providing reliable and
affordable electricity to their communities while
simultaneously addressing the complex
challenges posed by changing energy markets,
technological advancements, and clean energy
mandates.
An IRP offers a structured and systematic
approach to navigate the complex choices
inherent in the provision of electric service
providers. The IRP’s significance is highlighted by
the Utility’s ability to meet short-term objectives
while paving the way toward ensuring a
sustainable, equitable, and resilient energy
future. In essence, an IRP demonstrates REU’s
commitment to serving the community's energy
needs while embracing the broader responsibility
being conscientious stewards and helping the
community thrive.
2024 Integrated Resource Plan |Purpose and Background 14 | Page
As demonstrated in this document, the IRP provides an assessment of the future energy needs of customers
over the next 20+ years (from 2023 through 2045) and summarizes the preferred plan for meeting those
needs in a safe, reliable, cost-effective, and environmentally responsible manner.
2.1 Background
The initial IRP filed in 2019 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. SB 350 established requirements for any POU with an average load
greater than 700 GWh (in the 2013-16 period) to develop and adopt an IRP by January 1, 2019, and update
it with the California Energy Commission (CEC) at least every five years. SB 350 was superseded by Senate
Bill 100 (SB 100), which updated the state’s Renewables Portfolio Standard (RPS) requirements, established
carbon-reduction goals, and required the CEC, the California Public Utilities Commission (CPUC), and the
California Air Resource Board (CARB) to file a joint policy report on SB 100 by 2021.
California’s clean energy mandates include, but are not limited to, the following:
SB 100: renewable energy and zero-carbon resources must supply 100 percent of electric retail
sales to end-use customers by 2045
Renewables Portfolio Standards (RPS): requires that by 2030, at least 60 percent of California’s
electricity is generated from renewable resources; sets long-term contract requirements
Energy Efficiency Standards: aims to reduce energy consumption and promote energy-saving
practices among utility customers
Carbon reduction targets established by Senate Bill 1020 starting in 2035
POUs must develop an IRP that sets forth the plan to achieve the above goals and other
objectives such as those related to reliability and cost-effectiveness
Transportation electrification plans must be included in the IRP
Goals and Objectives
The overarching objective of the IRP is to foster awareness, preparedness, and strategic planning in an
intricate and ever-evolving energy landscape. By doing so, REU ensures its adaptability and responsiveness
to developing trends in the energy sector and hedges against risk, resulting in continued cost-effective
services. The IRP plays a crucial role in establishing well-defined goals and objectives that will steer the
future course of REU's electric utility operations. These goals and objectives encompass multiple
dimensions, including but not limited to:
Affordability
Striving to maintain reasonable and cost-effective electricity rates for customers, taking into account the
cost of generation, transmission, and distribution, while also considering the long-term financial
sustainability of the utility.
2024 Integrated Resource Plan |Purpose and Background 15 | Page
Environmental Sustainability
Meeting clean energy mandates by reducing greenhouse gas emissions, minimizing the environmental
impact of electricity generation and delivery, and promoting renewable energy sources and energy
efficiency initiatives to support a cleaner and greener future.
Reliability
Ensuring a robust and resilient electric grid capable of meeting the community's demand for electricity
under normal and emergency conditions with expected load growth from electrification while managing
increased saturation of intermittent resources.
Benefits of the Integrated Resource Plan
The development and implementation of the IRP offers numerous benefits to REU, the COR, and its
constituents. These benefits include:
Enhanced Decision-Making: The IRP provides a systematic approach for evaluating various
resource options, enabling informed decision-making that aligns with the community's needs,
values, and long-term vision.
Financial Stability: By strategically planning for future electricity supply and demand, the IRP
helps mitigate financial risks and uncertainties, supporting the long-term financial stability of
REU and ensuring cost-effective electricity services for customers.
Environmental Responsibility: The IRP promotes the adoption of cleaner and more sustainable
energy resources, helping to reduce carbon emissions, improve air quality, and contribute to
the state’s efforts in combating climate change.
2.2 Overview of IRP Process
REU embarked on a comprehensive and inclusive process to update its IRP filed in 2019. The IRP process
involved a series of studies, assessments, modeling, and stakeholder engagement activities aimed at
ensuring that the plan aligns with the organization's goals and effectively addresses the evolving energy
landscape and customer needs. This section provides an overview of the key steps undertaken during the
IRP development process.
Initial Studies and Assessments
To lay the foundation for the IRP, REU conducted a range of studies to gather data and insights into various
aspects of electric utility operations. These studies included a customer survey, aimed at understanding
customer preferences, expectations, and evolving energy demands. Additionally, a comprehensive
transmission system assessment was conducted to evaluate the existing infrastructure's capabilities and
identify potential upgrades or expansions needed to support future electricity supply. Furthermore, an
electrification forecast study was carried out to anticipate the growth of electric vehicles, electrified heating
systems, and other emerging electrification trends within the community.
2024 Integrated Resource Plan |Purpose and Background 16 | Page
Integration of Study & Survey Results
The results from the studies were crucial inputs that informed REU's models and load forecast. The load
forecast provided by Itron, Inc., coupled with the electrification forecast developed by Dunsky Climate +
Energy Advisors, helped project the future demand for electricity within the Utility's service territory. By
incorporating the customer survey data, transmission system assessment findings, and electrification
forecast into the load forecast, the models developed by Ascend Analytics provided REU with a
comprehensive understanding of the factors that would influence its future resource needs. (See IRP Project
Partners for more information about the consultants identified in this section).
Portfolio Modeling
Ascend Analytics employed a robust forecast modeling process that integrated the study results and load
forecast to determine resources needed to meet future demand. This modeling exercise allowed REU’s
Long-Term Resource Planning team (the Resources Team) to evaluate several resource scenarios based on
a variety of clean energy requirements and implementation timelines. Doing so determines the optimal mix
of resources needed to meet projected electricity demand while accounting for the State's regulatory
requirements around clean energy and renewable resources.
Stakeholder Engagement
Recognizing the importance of involving diverse perspectives and gathering input from key stakeholders,
REU formed a dedicated stakeholder group to review the results and provide insights on the Utility's
direction. The stakeholder group consisted of representatives from customer advocacy organizations,
environmental groups, regulatory agencies, community organizations, and other relevant entities. Staff
provided a series of educational workshops to ensure the group was able to make an educated and
informed decision when determining the preferred scenario. This collaborative approach ensured that the
IRP development process benefited from the collective expertise and input of a broad range of
stakeholders.
Review of Model and Resource Selections
Once the stakeholder group reviewed the results and provided their insights, the Resources Team
incorporated their feedback into the model and resource selection process. REU carefully considered the
stakeholder group's recommendations to ensure that the IRP reflects the collective vision and goals of the
community. Various resource options were evaluated, such as renewable energy generation, carbon-free
energy, energy storage, and demand response programs, among others, to determine the optimal mix of
resources needed to meet the anticipated utility demand over the long term.
Plan Finalization and Implementation
REU finalized the IRP’s preferred resource scenario and affirmed the stakeholder group’s assessment that
Net-Zero Carbon 2045 is the scenario that most closely aligns with the IRP’s strategic framework identified
by REU leadership.
2024 Integrated Resource Plan |Purpose and Background 17 | Page
The Plan outlines the strategic direction, resource allocation, and implementation timelines to meet the
community's electricity needs while considering reliability, affordability, clean energy mandates, and
customer preferences.
Although the IRP is not a procurement document, the finalized plan serves as a roadmap for REU's future
investments, policy decisions, and operational strategies, with the aim of ensuring a reliable, affordable,
and sustainable electricity supply for the COR.
2.3 Strategic Framework
Establishing a strategic framework prior to developing the modeling scenarios for the IRP was crucial to
ensure a cohesive and effective planning process. The strategic framework serves as a guiding roadmap,
outlining the core principles, goals, and priorities that will shape the IRP's direction. By having REU’s
Leadership Team agree upon this framework, consensus was reached on the fundamental values and
objectives that underpin the energy future.
This approach promoted alignment of the IRP with the REU’s overarching mission and vision, fostering a
coherent and unified approach to energy planning. The agreed-upon strategic framework provided a clear
vision which the Resources Team used to assess various modeling scenarios, ensuring that each option
considered was in alignment with its long-term objectives.
Moreover, having a well-defined strategic framework facilitated informed decision-making during the
modeling process. It helped to focus on exploring viable solutions that not only met REU’s energy needs
but also aligned with its sustainability targets, reliability commitments, and customer demands.
REU’s Leadership Team agreed upon the following strategic framework for the IRP development:
The preferred 2024 IRP scenario should meet or exceed the State’s clean energy mandates while balancing
reliability and affordability.
Subsequently, REU’s Resources Team presented its leadership with a range of proposed modeling scenarios
that aligned with the identified framework. The selected scenarios and assumptions were provided to
Ascend along with the comprehensive load forecast prepared by Itron and Dunsky for portfolio modeling.
The Resources team furnished inputs and constraints for three specific scenarios:
Low Scenario: Herein “Current Portfolio” - does not meet mandates
Mid Scenario: Herein “Net-Zero Carbon 2045” - meets mandates
High Scenario: Herein “100% Zero Carbon 2045” - exceeds mandates
2.4 Scenario Development
With the strategic framework in place, REU’s Resources Team rigorously assessed and scrutinized each
modeling scenario to ensure it resonated with the established long-term objectives, sustainability
commitments, and customer requirements. This process enabled REU to make informed decisions and
prioritize options that not only fulfilled customer energy needs but also aligned with the broader vision for
2024 Integrated Resource Plan |Purpose and Background 18 | Page
a resilient energy future. By anchoring the evaluation process in the strategic framework, the foundation
was laid for a well-considered and cohesive IRP that reflects the collective goals and remains committed to
addressing the dynamic challenges of the energy landscape.
Does the Scenario Meet or Exceed Clean Energy Mandates?
Different scenarios were modeled with varying levels of constraints to assess their feasibility. The model
subsequently determined the optimal combination of energy resources to fulfill the portfolio requirements
while adhering to specified criteria.
Does the Scenario Maintain Reliability?
To assess the reliability of the chosen scenario, a study is conducted analyzing each hour of every day
throughout the 20-year planning period to calculate the Loss of Load Probability (LOLP) based on the
selected resources. This analysis helps ensure that the chosen scenario accounts for the necessary capacity
to maintain a reliable power supply.
Does the Scenario Maintain Affordable Rates?
After completing the capacity expansion model, each scenario undergoes analysis using a production cost
model. This model calculates the cost of the power supply for each scenario, enabling REU’s Resources
Team to evaluate and compare the costs associated with each option.
Affordability Reliability Meets Mandates
Current Portfolio
Net-Zero Carbon 2045
100% Zero Carbon 2045
Table 2-1: Scenario Development
Scenario Results
Outcomes are illustrated in Table 2-1. The Current Portfolio falls short of meeting carbon targets and
requirements; the Net Zero 2045 scenario successfully meets the objectives of the strategic framework;
and the 100% Zero Carbon 2045 scenario fails to meet affordability goals by protecting power supply costs.
2.5 Stakeholder Process
REU recognizes the importance of engaging stakeholders in the decision-making process to ensure that the
IRP reflects the values, needs, and aspirations of the community. In developing the IRP, REU's Resources
team initiated a stakeholder group process, which involved selecting community members representing
various groups and organizations and involving them in a series of workshops and discussions.
2024 Integrated Resource Plan |Purpose and Background 19 | Page
Identifying the Stakeholder Group
The Resources Team carefully identified and invited representatives from diverse community groups to
participate in the stakeholder group. These groups included environmental groups, community
organizations, and other relevant entities who represented economic development, small commercial,
residential, and minority customers. The selection process aimed to ensure a broad representation of
perspectives and expertise, fostering inclusivity and comprehensive input into the planning process.
Customers: Residential, small and large commercial, and institutional customers who rely on
REU's electricity services.
Environmental Organizations: Nonprofit organizations and advocacy groups focused on
environmental sustainability and renewable energy.
Economic Development: Organizations focused on the economic growth, sustainability, and
viability of the community.
Community and Interest Groups: Organizations representing minority customers with diverse
community interests, such as business associations, social justice groups, and more.
Organization Representative
Mercy Medical Center, Redding Facility Director
Caliber Office Furniture Owner, Operator
Shasta Builders' Exchange Executive Director
Redding Rancheria Special Projects
North State Climate Action Advocate
Shasta Environmental Alliance President
Shasta Environmental
Development Corporation
President
The Resources Team contacted several low-income advocacy groups and aimed to invite a representative
to join the stakeholder group. Many of the organizations that were contacted did not have the resources
to spare for this project; therefore, each of the stakeholders involved were asked to consider the vulnerable
low-income and disadvantaged communities when evaluating the scenarios presented.
Stakeholder Workshops and Discussions
The stakeholder group was engaged through a series of workshops and discussions facilitated by REU’s
Resources Team. During these sessions, participants were provided with relevant information about the
energy landscape, the study results, load forecasts, regulatory requirements, and various resource
scenarios. The workshops offered a platform for stakeholders to ask questions, share insights, and provide
feedback on different aspects of the IRP.
2024 Integrated Resource Plan |Purpose and Background 20 | Page
Presentation of Scenarios: Net- Zero Carbon 2045 and 100% Zero Carbon 2045
As part of the stakeholder group process, REU's Resources Team presented two distinct scenarios for
consideration: Net-Zero Carbon 2045 and 100% Zero Carbon 2045 plans. These scenarios outlined different
pathways for achieving carbon reduction goals and transitioning towards cleaner energy sources. The
presentations included detailed information on the potential benefits, challenges, costs, and implications
associated with each scenario.
Voting and Feedback
Following the series of workshops and presentations, stakeholders were given the opportunity to vote and
provide feedback on the two scenarios. Their votes and feedback were sought to gauge their preferences
and perspectives on the proposed plans. The stakeholders' input was vital in guiding the decision-making
process and shaping the final direction of the IRP.
Selection of the 2045 Net-Zero Carbon Plan
After carefully considering the votes and feedback received from the stakeholder group, it was determined
that the preferred plan moving forward was the Net-Zero Carbon 2045 scenario. The stakeholders' choice
was influenced, in part, by the affordability and reliability considerations associated with operating the
Plant. The selected plan reflected the stakeholders' assessment of the balance between environmental
2024 Integrated Resource Plan |Purpose and Background 21 | Page
sustainability, energy affordability, and the organization's operational capabilities necessary for maintaining
its exceptional level of reliability.
Public Survey and Community Agreement
To ensure broad community support and alignment with the stakeholder group's recommendations, REU
conducted a public survey to gather feedback on the proposed 2045 Net-Zero Carbon plan. The survey
aimed to gauge the community's level of agreement with the plan, including its environmental, economic,
and social implications. The results of the survey indicated that the community, as a whole, agreed with
the 2045 Net-Zero Carbon plan, validating the stakeholder group's decision and providing further
confirmation of community-wide support.
By involving the stakeholder group in a transparent and collaborative process, REU ensured that the IRP
incorporated diverse perspectives and reflected the community's preferences. The stakeholder workshops,
voting process, feedback collection, and public survey were instrumental in fostering community
engagement, building consensus, and ultimately shaping a plan that represents the collective vision for a
sustainable energy future in the COR.
2024 Integrated Resource Plan |Legislation & Regulation 22 | Page
3. Legislation & Regulation
In recent years, the legislative and regulatory
landscape surrounding energy has evolved
significantly, driven, in part, by various state and
federal actions. These changes have had a
substantial impact on how utilities like REU
operate and plan for the future. In the context of
these developments, it is crucial to understand
the key agencies involved in overseeing and
implementing legislative changes, as well as how
these changes can affect load forecasting.
REU is subject to oversight from a variety of state
and federal agencies. State regulatory oversight
bodies include the California Energy Commission
(CEC), the California Air Resource Board (CARB),
and the California Public Utilities Commission
(CPUC). Additionally, the Utility reports to the
Western Electric Coordinating Council (WECC),
the North American Electric Reliability
Corporation (NERC), and the Federal Energy
Regulatory Commission. Each of the regulatory
oversight bodies monitors various clean energy
mandates, safety, security, and reliability
standards that REU must abide by. The following
section details the oversight and obligations to
which REU is accountable.
2024 Integrated Resource Plan |Legislation & Regulation 23 | Page
3.1 State Regulatory Agencies
State-level agencies are given regulatory authority to develop, design, and/or implement various legislative
actions from state assembly and senate members, as well as the Governor through executive orders. The
following section describes the three primary State regulatory bodies that oversee REU, and their roles in
supporting decarbonization efforts. Figure 3-1 shows a diagram of these regulatory and oversight agencies.
Figure 3-1: Regulatory Oversight of REU
California Energy Commission
The California Energy Commission (CEC) is the state agency that oversees POU activities. The CEC plays a
key role in implementing and crafting policies and programs to create a low-carbon economy. Key activities
include:
Developing reporting guidelines and reviewing various reports submitted by POUs, including
Integrated Resource Plan, Integrated Energy Policy Report (IEPR), and Annual Energy Efficiency
Report (SB 1037)
Developing and enforcing the State’s Renewables Portfolio Standards (RPS) program
Evaluating and establishing statewide energy efficiency and fuel substitution goals based on
POU’s Technical and Market Potential Studies results
Developing Title 24, Part 6 Building Energy Efficiency Standards required for new construction
and retrofit projects for residential and commercial buildings
Evaluate the Power Source Disclosure and Power Content Label programs
2024 Integrated Resource Plan |Legislation & Regulation 24 | Page
REU is subject to the CEC’s policies and must consider all current and future policies during the resource
planning process. For example, RPS standards were updated to include the accelerated targets, and
incorporated long-term contract minimum standards, and portfolio balancing requirements to ensure in-
state resources (PCC1) continue to be valued more than out-of-state (PCC2) or unbundled (PCC3) RECs.
Additionally, the CEC monitors grid reliability as more renewable energy resources are required through
the IEPR process. REU expects the CEC will continue to update existing programs to support SB 100.
California Air Resources Board
The California Air Resources Board (CARB) oversees health and air quality standards for the state. CARB sets
the State’s air quality standards at levels that protect those greatest at risk, and is the agency tasked with
developing policies for combating climate-change through measures that promote a more energy-efficient,
carbon-free, and resilient economy. CARB policies typically exceed federal emissions standards. Key
activities include:
Administer Cap-and-Trade and Greenhouse Gas programs (AB 32)
Developing Scoping Plans (AB 1279) showing carbon-neutrality pathways to meet California
goals
Administer the State’s Low Carbon Fuel Standards (LCFS) Program
California's cap-and-trade greenhouse gas program is a key component of the State's comprehensive
strategy to combat climate change. Under this program, a cap, or limit, is set on the total amount of
greenhouse gas emissions allowed from certain sectors of the economy, primarily industries and power
plants. These entities are required to hold allowances equal to their emissions, and a portion of these
allowances are auctioned by the State.
The program encourages emission reductions by creating a market for emissions allowances, where entities
can buy and sell allowances as needed to comply with the cap. Over time, the cap is gradually reduced,
leading to a decrease in allowable emissions and incentivizing emissions reduction efforts.
Revenue generated from the sale of allowances is reinvested in various programs aimed at further reducing
greenhouse gas emissions, promoting renewable energy, and supporting disadvantaged communities
disproportionately affected by pollution. California's cap-and-trade greenhouse gas program is a market-
based approach to limit and reduce carbon emissions from major sectors of the economy, contributing to
the State's ambitious climate goals and fostering a transition toward a more sustainable and low-carbon
future.
In 2022, CARB’s 2022 Scoping Plan for Achieving Carbon Neutrality (2022 Scoping Plan) was issued to lay
out additional pathways to achieve carbon neutrality and reduce GHG emissions by 85% below 1990 levels
no later than 2045. The results of the report indicated that carbon neutrality is technically feasible by
leveraging existing programs (Cap-and-Trade, RPS, etc.), focusing on the balance between carbon sinks
(carbon capture, utilization, and sequestration) and sources (fossil fuel production, transportation, etc.),
and investing in existing technologies. Continued leadership and climate policy development are also
necessary to ensure SB 100 goals are met.
2024 Integrated Resource Plan |Legislation & Regulation 25 | Page
California Public Utilities Commission
While it does not have direct oversight for POUs, the California Public Utilities Commission (CPUC) develops
and enforces policies for IOUs that may be passed on to POUs through legislative activities or CEC policy
development. The Wildfire Safety Advisory Board, for example, reviews Wildfire Mitigation Plans for both
POUs and IOUs, and was originally created as an advisor to the CPUC’s Wildfire Safety Division (this has
since moved to the Office of Energy Infrastructure Safety under the California Natural Resources Agency).
REU and other POUs closely monitor new CPUC policies as they are developed and implemented to ensure
POUs are excluded or are provided increased flexibility.
Oversight Agency Coordination
In 2021, the CEC, CARB, and CPUC issued their first SB 100 Joint Agency Report to assess the challenges and
opportunities in meeting the zero-carbon target by 2045. The assessment included various scenarios
including a zero-combustion, zero-carbon firm resources, and an accelerated timeline to meet the goal by
2035. The results of the report indicated that while the SB 100 target is technically feasible, it does not
account for grid reliability. The report acknowledges that retaining some natural gas power capacity to
minimize the impacts from intermittent renewable resources may be required. Future reports will analyze
grid reliability, assess emerging resources (off-shore wind, long-duration storage, etc.), and the
environmental, social, and economic costs and benefits from implementing SB 100.
3.2 Federal Oversight Agencies
Federal-level regulators are authorized through various legislative and administrative actions to provide
oversight to transmission and energy markets to support the overall grid. The following section provides a
brief overview of three primary federal regulatory bodies that oversee REU grid-related activities.
Federal Energy Regulatory Commission
The Federal Energy Regulatory Commission (FERC) is the federal agency responsible for regulating the
interstate transmission of electricity, natural gas, and oil resources, and licensing hydroelectric projects.
Key activities include:
Regulating interstate transmission and wholesale energy markets including electricity and
natural gas
Issuing licenses and conducting inspections for hydroelectric projects
Establishing mandatory reliability standards and approving interstate transmission rates for
electricity and natural gas
Monitors and investigates energy markets
2024 Integrated Resource Plan |Legislation & Regulation 26 | Page
North American Electric Reliability Corporation
The North American Electric Reliability Corporation (NERC) is non-profit regulatory authority responsible
for assuring the effective and efficient reduction of risks to the reliability and security of the electric grid.
Overseen by the Federal Energy Regulatory Commission (FERC), NERC monitors the bulk power system,
develops and enforces Reliability Standards, and assesses seasonal and long-term reliability.
Western Electric Coordinating Council
The Western Electricity Coordinating Council (WECC) is a non-profit, regional entity that supports reliability
of the Bulk Electric System in the Western Interconnection. Comprised of 14 Western states, 2 Canadian
Provinces, and Northern Baja Mexico, WECC is responsible for compliance monitoring and enforcement, as
well as overseeing reliability planning and assessments. WECC is subject to NERC oversight.
WECC is the system administrator for the Western Renewable Energy Generation Information System
(WREGIS) which is used for REC accounting for RPS obligations.
3.3 Changes from 2019 IRP
Senate Bill 100
While REU was developing its 2019 IRP, Senate Bill 100 (SB 100) passed legislation and amended the Public
Utilities Code (PUC), establishing the newly increased RPS requirements. The PUC's previous renewable
energy procurement target required renewable energy to make up 50 percent of retail sales by December
31, 2030. SB 100 accelerated the 50 percent target to 2026 and increased the renewable requirement to
60 percent in 2030.
Additionally, SB 100 reduced the percentage of large hydroelectric generation required to preclude utilities
from procuring over a specified amount of renewable generation. Where SB 350 allowed utilities with at
least 50 percent of their generation from large hydroelectric resources to reduce the required procurement
of renewables by a specified amount, SB 100 reduced the threshold for qualifying utilities to 40 percent.
Finally, SB 100 introduced a new zero-carbon policy not previously required under SB 350. SB 100 requires
eligible renewable energy resources and zero-carbon resources to supply 100 percent of retail sales of
electricity to California customers and 100 percent of electricity procured to serve all state agencies by
December 31, 2045. The bill requires that the achievement of this policy not increase carbon emissions to
another place in the western grid. REU is required to incorporate new policy introduced into its long-term
planning efforts.
Senate Bill 1020
Governor Newsom signed the SB 1020 bill, also known as the 100% Clean Electric Grid bill, on September
16, 2022. This legislation aims to significantly decrease California's reliance on fossil fuels in three stages.
According to the policy, the State's goal is to have 90% of all retail sales of electricity supplied by eligible
renewable energy resources and zero-carbon resources by 2035. This target will be followed by a 5%
increase by 2040, leading to the ultimate objective of achieving 100% clean energy by 2045.
2024 Integrated Resource Plan |Legislation & Regulation 27 | Page
Renewables Portfolio Standards
The CEC adopted revised RPS Enforcement Regulations on December 22, 2020. The updated RPS
Enforcement Regulations included the revised renewables and emissions targets from SB 100. In March
2023, Redding City Council (Council) approved modifications made to REU's RPS Enforcement Program and
Procurement Plan to reflect recent updates to the regulations (Exhibit 9.4). In addition to the updated
procurement targets for each compliance period shown in Table 3-1 below, the newest regulations require
utilities to meet specific Long-Term Procurement Requirements (LTP) and Portfolio Balance Requirements
(PBR).
Table 3-1: SB 100 RPS Procurement Targets
Compliance
Period 4 5 6 7
Year 2023 2024 2025 2026 2027 2028 2029 2030 2031…
RPS Target 41.25% 44.00% 46.00% 50.00% 52.00% 54.67% 57.33% 60.00% 60.00%
The RPS established Portfolio Content Categories (PCC) that define renewable energy credits (RECs) and
the eligible renewable energy resource products needed to comply with the minimum and maximum
values.
PCC 0: Any contract or ownership agreement executed before June 1, 2010; counts in full
toward procurement requirement
PCC 1: bundled REC + energy at the time of procurement and generated by an eligible
renewable resource interconnected to WECC service territory, located within the metered
boundaries of a California balancing authority area
PCC 2: bundled REC + energy at the time of procurement and generated by an eligible
renewable resource interconnected to WECC service territory, located outside the metered
boundaries of a California balancing authority area
PCC 3: Unbundled REC procured from eligible renewable energy resources within WECC that do
not meet the criteria of PCC 1 or PCC 2
To meet the PBR outlined in Table 3-2, for the compliance period beginning January 1, 2021, and each
compliance period thereafter, PCC 1 RECs must account for at least 75 percent of the electricity products
applied toward the RPS procurement target. Additionally, no more than 10 percent of the RECs used to
satisfy compliance in any given compliance period may be derived from PCC 3 RECs. There is no limit on
the number of PCC 0 RECs that can be used in a compliance period, as those RECs are not subject to the
PBR.
2024 Integrated Resource Plan |Legislation & Regulation 28 | Page
Table 3-2: SB 100 Portfolio Balancing Requirements
Compliance Period
CP 1
2011-2013
CP 2
2014-2016
CP 3
2017-2020
CP 4
2021-2024
CP 5
2025-2027
CP 6
2027-2030
PCC1 (min) 50% 65% 75% 75% 75% 75%
PCC2 (no restriction) n/a n/a n/a n/a n/a n/a
PCC3 (max) 25% 15% 10% 10% 10% 10%
PCC0 Not subject to portfolio balancing requirements
Beginning January 1, 2021, with Compliance Period 4, at least sixty-five percent (65%) of REU's RPS
procurement for each compliance period must be generated from contracts of 10 years or more in duration
or ownership or ownership agreements for eligible renewable energy resources (PUC Sections 399.13(b)
and 399.30(d)).
Key modifications to REU's RPS Enforcement Program and Procurement Plan included the following:
Defined updated procurement targets through 2030
Addition of Long-Term Procurement requirement starting January 1, 2021
Included Portfolio Balance Requirement and new Optional Compliance Measure
Updated notice requirements to the public and CEC as outlined in the new RPS regulations
Updates to the RPS requirements have significantly affected REU's procurement requirements. As a result,
the 2019 IRP Scenario H is no longer compliant with current regulations.
Building Energy Code, Title 24 Pt. 6
The Building Energy Efficiency Standards, commonly referred to as Title 24, provides energy and water
efficiency requirements for new construction buildings, additions to existing buildings, and alterations to
existing buildings. Title 24 is updated every three years and was most recently adopted in 2022. These
standards became effective on January 1, 2023.
In addition to general increases in energy efficiency for equipment and buildings, the most significant
impact resulting from the 2022 updated standards is the requirement for new construction residential
dwellings (Sections 140.10 and 150.1) and nonresidential buildings (Section 170.2) to install onsite or
rooftop PV systems Highlights of the PV requirement are as follows:
Must be sized to offset annual electric usage, providing zero net energy (ZNE)
Size of the system may be reduced by 25 percent if installed with battery storage system
Community shared solar, other renewable energy systems, or shared battery systems are
options to meet the ZNE requirements under Section 150.1 of Title 24 (note: this option must
be approved by the CEC)
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Advanced Clean Cars II
California's Governor issued an Executive Order in September 2020, stating that 100 percent of in-state
sales on new passenger cars and trucks will be zero-emission by 2035. Additionally, the Executive Order set
aggressive goals for zero-emission medium- and heavy-duty vehicles in the state for all operations where
feasible by 2045.
Since that time, several major auto manufacturers have pledged to transition to 100 percent electric
vehicles or zero-emission vehicle production as early as 2030. While the Executive Order was primarily
aimed at auto manufacturers, the Governor required state and local government agencies to work together
to develop strategies to provide adequate infrastructure to support the Executive Order's goals. Therefore,
utilities across the state are feeling increased pressure to provide infrastructure to support the additional
electric vehicles that will be on the road in the foreseeable future.
In 2022, the Executive Order was codified in the Advanced Clean Cars II regulation. By 2035 all new
passenger cars, trucks and SUVs sold in California will be zero emissions. The Advanced Clean Cars II
regulations take the state’s already growing zero-emission vehicle market and robust motor vehicle
emission control rules and augments them to meet more aggressive tailpipe emissions standards and ramp
up to 100% zero-emission vehicles.
Low Carbon Fuel Standards and Clean Fuel Reward Programs
In 2020, REU opted into the State's Low Carbon Fuel Standards (LCFS) program, which included a provision
requiring the Utility to execute a joinder agreement to participate in the State's Clean Fuel Reward (CFR)
program. As a program participant, CARB allocates credits to REU based on the saturation of EV charging
in its service territory. The credits are issued quarterly and monetized through a competitive bidding
process, and revenue is reinvested in the Utility's transportation electrification programs.
LCFS participants are required to contribute a portion of LCFS revenue to the State’s CFR program, which
was developed to provide rebates to California residents who purchased a qualifying electric vehicle. The
CFR program funding has been expended and the program is on hold; however, LCFS program participants
are required to continue allocating 25 percent of the revenue from the LCFS proceeds to the CFR program
annually.
Each of these programs has a set of corresponding regulatory requirements that participants are mandated
to follow, including spending and equity requirements, which impact REU’s customer program offerings for
transportation electrification.
Advanced Clean Fleet Rule
The Advance Clean Fleet Rule (ACF) rule is a policy aimed at reducing greenhouse gas (GHG) emissions from
vehicles and promoting the adoption of cleaner, more sustainable fleet transportation options. The rule
sets specific requirements for public fleets to adopt zero-emission vehicles (ZEVs). This requirement is
aimed at accelerating the transition to cleaner transportation options in the public sector.
Under the ACF rule, public fleets, including government agencies and departments, are mandated to
incorporate a certain percentage of ZEVs into their vehicle fleets. This means that a portion of their vehicle
2024 Integrated Resource Plan |Legislation & Regulation 30 | Page
acquisitions or replacements must be zero-emission vehicles, such as battery electric vehicles (BEVs) or fuel
cell electric vehicles (FCEVs). Due to more than 90 percent of its fleet residing in a low-population county,
the COR is not required to make ZEV purchases until 2027. However, 100 percent of the vehicle purchases
must be zero-emission vehicles beginning January 1, 2027.
The inclusion of the public fleet zero-emission vehicle requirement acknowledges the important role of
government entities in leading by example and driving the adoption of cleaner technologies. The COR
contracted with Frontier Energy, Inc. in April of 2023 to develop a comprehensive City-wide ZEV Fleet
Replacement and Infrastructure Plan to fully assess the implications of the regulation on the City’s fleet.
Assembly Bill 3232
In addition to the requirement to achieve a reduction in the emissions of greenhouse gases by 40 percent
below 1990 levels by 2030, the Clean Energy and Pollution Reduction Act of 2015 (SB 350) established a
goal for achieving a cumulative doubling of statewide energy efficiency savings in electricity and natural gas
end uses of retail customers by January 1, 2030. AB 3232 directed the CEC, by January 1, 2021, to assess
the potential for the state to reduce GHG emissions from residential and commercial building stock by at
least 40 percent below 1990 levels by 2030.
The bill requires the CEC to include in their assessment evaluations of the cost to reduce carbon emissions
from residential and commercial building stock; cost-effectiveness strategies; challenges with reducing
emission from low-income and multi-family housing; load management strategies; potential impacts to
ratepayers; and load impacts on infrastructure due to transportation electrification. The CEC was required
to submit the findings of the assessment to the Legislature by June 1, 2021. Beginning with the IEPR due
on November 1, 2021, and in all subsequent IEPRs, the CEC is required to report on the emissions of GHG
related to the energy supply to residential and commercial buildings by fuel type.
Impacts of Updated Regulations
Recognizing the importance of being flexible and adaptable, REU remains committed to staying informed
of evolving clean energy regulations, targets, and objectives in California, and is well-positioned to adapt
its portfolio modeling accordingly.
The preferred scenario selected in the 2019 IRP no longer aligns with the State's updated regulatory
requirements, necessitating the identification of new resources and timelines to ensure regulatory
compliance. To achieve this, modeling and scenario development methodologies have shifted to one that
is centered around compliance requirements rather than renewable resource identification. The scenarios
developed for this IRP account for the varying degrees of compliance needed to meet clean energy
mandates, with an anticipation of increasingly stringent renewable energy and carbon reduction
requirements imposed by regulatory bodies.
Regulatory requirements for clean energy and carbon reduction will likely become more stringent over
time. By incorporating these expectations into the modeling process, the implications of resource selection,
investment strategies, and operational plans can be assessed. This forward-thinking approach positions
REU to proactively respond to regulatory changes and achieve long-term sustainability goals while
providing reliable and affordable electricity services to its constituents.
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4. Energy Efficiency, Electrification, & Demand Response
As the state pursues a zero-carbon future,
impacts from Customer Program offerings that
include energy efficiency, electrification, and
demand response activities are increasingly
considered critical to decarbonization efforts.
The transportation and building sectors are key
areas for improvement to meet SB 100 targets.
Building code changes support decarbonization
by requiring “electric-ready” new construction
homes and businesses for future EV and space
and water heating equipment, elimination of
natural gas subsidies for new construction
buildings, and future bans on fossil-fueled
appliances. This shift from energy efficiency to
decarbonization will contribute to increased
energy consumption. Current and future policies
on technologies focused on increasing adoption
in the transportation and building sectors will
also significantly impact the grid’s ability to
support a zero-carbon future.
REU categorizes program measures as either
Committed Savings or Additional Achievable
Energy Efficiency (AAEE) or Additional Achievable
Fuel-Switching (AAFS). Program measures that
were considered in the 2021 Potential Study
results are listed as “committed savings” and
support REU’s approved targets.
The following sections detail the studies and
program development for decarbonization
programs.
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4.1 Demand-Side Management Integrated Resource Plan
Historically, REU has offered energy efficiency programs supporting state goals and regulations, resulting
in a lower load forecast over time. With the passing of SB 100, the State began to focus on grid
decarbonization rather than relying on energy efficiency to meet clean energy goals. REU developed two
reports to address this change:
2021 Energy Efficiency Potential Forecast Study (2021 Potential Study)
Demand-Side Management Integrated Resource Plan (DSM-IRP)
Results from the 2021 Potential Study and the DSM-IRP indicate that electrification programs are expected
to increase load over the next ten years. The current load forecast includes results from the Potential Study,
whereas results from the DSM-IRP will be incorporated into future load forecasts once programs are fully
implemented. Each report's findings are detailed in the following two sections.
2021 Energy Efficiency Potential Study Forecast
Beginning in 2013, and every four years thereafter, REU is required to develop an Energy Efficiency (EE)
Potential Study Forecast (Potential Study) that provides a 10-year projection of achievable EE savings.
Customer program impacts in the 2019 IRP load forecast were primarily driven by the results of the 2017
EE Potential Forecast (2017 Potential Study) developed for REU by Navigant. Initial findings for that
Potential Study indicated approximately 34 GWh of potential EE savings from 2018-2027. These results
were incorporated into the load forecast for the 2019 IRP, supporting SB 350 and the state's efforts to
double EE savings by 2030.
Results from the 2021 Potential Study forecast (2022-2031), developed for REU by GDS Associates, Inc.,
identified only approximately 8 GWh of total potential EE from 2022-2031, which is significantly less than
the 2017 Potential Study's findings. The differences are attributed to the following factors:
Updated utility avoided cost rates based on the most recent cost of service study reduced the
cost-effectiveness of EE programs
Increasingly stringent building standards under Title 24 reduced the amount of potential EE
savings
Heavy saturation in the Commercial Lighting Program reduced potential EE savings in future
forecasts due to high participation in the early years of the program
On March 2, 2021, Council approved REU staff’s recommendation to update REU's EE goals due to the
reduced EE potential identified. The updated goals are listed in Table 4-1, while Figure 4-1 compares the
goals from the 2017 and 2021 Potential Studies compared to the CEC’s targets from 2022-2031.
Table 4-1: 2021 REU Council-approved EE Goals
Year 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
2021 Goals, MWh 1,358 1,305 1,233 1,115 992 755 581 525 439 388
2024 Integrated Resource Plan |Energy Efficiency, Electrification, & Demand Response 33 | Page
Figure 4-1: CEC Targets, AAEE/FS, and Approved Goals
2021 DSM-IRP Report and Recommendation
The DSM-IRP was developed in response to the 2021 Potential Study results. The planning document sets
a framework to identify which programs meet utility goals and establishes a preferred DSM portfolio. REU
staff followed a five-step process to structure the DSM-IRP (Figure 4-2). Council approved the report on
September 21, 2021.
2024 Integrated Resource Plan |Energy Efficiency, Electrification, & Demand Response 34 | Page
Figure 4-2: DSM-IRP Five-Step Process
Using a five-step approach, staff analyzed hundreds of measures, including energy efficiency, building
electrification, and transportation electrification, to determine which measures and programs are most
cost-effective. A set of principles were developed to guide the plan, which included the following:
Offer measures where program participants save money
Ensure that funds are not transferred from non-participants to participants
Focus on programs that cost-effectively reduce carbon emissions
From there, three key cost-effectiveness tests were identified that support the guiding principles:
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 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.
Step 1
•Develop Guiding Principles
•Review of all funding requirements, relavant statutes and regulations, community feedback, and City Council
determinations
Step 2
•Establish Key Assumptions and Cost-Effectiveness Tests
•Review industry cost-effectiveness tests
•Select tests that best support the guiding principles
Step 3
•Identify and Characterize Measure Options
•Define detailed chracteristics of each measure
Step 4
•Perform Analyis and Identify Preferred Plan
•Analyze different measures, including energy efficiency, building electrification, and transportation
electrification
•Identify cost-effective DSM programs that most align with guiding principles and meet utility goals
Step 5
•Develop an Implementation Plan
•Combine recommendations of the DSM-IRP analysis with existing budgets and internal staffing available to
meet utility goals with existing resources
2024 Integrated Resource Plan |Energy Efficiency, Electrification, & Demand Response 35 | Page
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 cost-effectively
reduce carbon emissions. Note that measures with a positive CIT save carbon while providing
downward rate pressure.
The components that are included in each cost-effectiveness measure are shown in Table 4-2, where the
three metrics that align with the guiding principles are highlighted in blue.
Table 4-2: Cost-Effectiveness Tests Used for Program Evaluation
Test Component RIM, $ CIT, $/MT GHG PCT, $
GHG Emissions Reduction X
Electric Energy and Capacity Avoided Costs X X
Incremental Costs for Measure and Installation X
Program Administrator Overhead Costs X X
Incentive Payments Paid by Utility X X X
Customer Bill Impact X
Utility Revenue Impact X X
The results of the report concluded that building electrification programs and transportation electrification
programs best support the guiding principles identified in the DSM-IRP because 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.
Two decarbonization measure types, building electrification (BE) and transportation electrification (TE),
were identified as the preferred measures for the DSM portfolio. As a result, REU recommended gradually
eliminating EE programs to launch decarbonization programs focused on cost-effective BE and TE measures
identified in the analysis. The implementation plan incorporates existing budgets and internal staffing to
meet utility goals. Furthermore, it includes education and outreach for customers and contractors to
facilitate the transition to decarbonization programs and address all barriers prior to implementation.
REU developed a BE and TE forecast to determine load growth from decarbonization programs based on
the DSM-IRP implementation plan. Results from the BE/TE forecast are incorporated into the load forecast
for the 2024 IRP.
Shift to Electrification Programs
Since 2017, REU’s Customer Program Portfolio (Program Portfolio) has primarily focused on energy
efficiency measures that support the State’s ongoing climate goals. Programs include energy efficiency
equipment rebates for Residential, Commercial, and Low-Income customers. The current Program Portfolio
supports the State’s energy efficiency doubling goals under SB 350.
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Building on the findings of the DSM-IRP, REU transitioned from the current suite of energy efficiency
programs to building electrification and transportation electrification programs with a phased approach
that will allow time for all stakeholders to adapt to these new types of programs. The energy efficiency
programs were terminated effective May 1, 2022, and the first suite of electrification programs was
launched on July 1, 2022. Marketing materials, including television and social media campaigns were issued
to promote the programs and educate customers on the benefits of electrification.
Methods for reporting electrification program savings relative to the energy efficiency goals are currently
under development by California POUs. Existing electrification measures are calculated using energy
savings by converting natural gas savings to an electricity-equivalent and subtracting the electricity
consumption. This methodology is utilized in the SB 1037 Annual Energy Efficiency report that is submitted
by California Municipal Utilities Association.
Redding is required to commit to cost-effective energy efficiency savings. The recommended goals do not
achieve the annual SB 350 Targets that were assigned to REU by the CEC from 2023-2026 (Figure 4-3).
However, the recommended goals more accurately quantify the cost-effective potential than do the SB 350
Targets. Furthermore, REU expects to meet cumulative goals through 2029 (Figure 4-4), and building
electrification will be a significant contributor to energy efficiency in the later years of the forecast. REU
will continue to review and identify cost-effective measures that support SB 350 and the State’s focus on
decarbonization. The results from the 2021 Potential Study are incorporated into the load forecast.
Figure 4-3: City Council Approved Goals vs. Estimated Energy Savings
2024 Integrated Resource Plan |Energy Efficiency, Electrification, & Demand Response 37 | Page
Figure 4-4: Cumulative Savings: Forecast, Savings Achieved, & Goals
4.2 Transportation Electrification
Overview
Various initiatives have been implemented to encourage the adoption of electric vehicles (EVs) and create
a supportive infrastructure for EV charging. The COR has been actively engaged in promoting and advancing
transportation electrification within its community. To better educate customers, a dedicated online EV
hub has been created with customer-facing information including cost calculators, shopping assistance,
rebate and incentives programs, charging locators, and contact information for support staff. Additionally,
educational materials are provided to customers at various events throughout the year, and promotional
advertisements are used to educate the customers about REU’s available transportation programs.
The COR has collaborated with local businesses and other stakeholders to install charging stations at key
locations, including public parking areas, commercial centers, and recreation facilities. Furthermore, REU
has actively participated in regional and state-level programs aimed at expanding the EV charging network
and securing funding for EV incentives and infrastructure development.
Alongside its collaboration with EV charging providers, the COR has established an EV Readiness Committee
with the purpose of revising and enhancing its design, permitting, and development policies and
procedures. The Committee's primary objective is to proactively address barriers to EV adoption and
facilitate the necessary investment in EV charging infrastructure throughout the COR. Through this
initiative, more customer-friendly policies have been adopted that meet the State’s regulatory
2024 Integrated Resource Plan |Energy Efficiency, Electrification, & Demand Response 38 | Page
requirements, encourage the development of EV charging infrastructure, and further support the transition
to electric vehicles.
Transportation Electrification Plan
In 2017, Council approved the COR’s first transportation electrification programs, which were funded with
revenues from California’s Greenhouse Gas Cap & Trade program. Funding was approved for the following
transportation electrification initiatives:
Residential EV Rebate
Residential EV Charger Rebate
Commercial EV Rebate
COR Fleet EV Charging Stations
COR Fleet Replacement with EVs
Public Charging Infrastructure
Subsequently, the COR installed fleet EV charging stations at five of its City facilities, electrified 26 fleet
vehicles, invested in electric motorcycles for the Police Department, deployed over a dozen off-road electric
vehicles.
After joining the State’s LCFS Program, REU shifted from using Cap-and-Trade funds to using LCFS revenues
to support EV programs. As a result of the equity spending obligations mandated by LCFS, a thorough
evaluation of the existing programs was conducted, leading to necessary modifications to ensure
compliance with the funding requirements outlined by LCFS. By aligning funding priorities with LCFS, REU
aims to actively contribute to the reduction of carbon emissions and promote equity within the
transportation sector.
REU remains committed to supporting the community's transition to electric transportation and plans to
continue its collaboration with other COR departments, leverage existing programs, and to consistently
evaluate its programs and procedures to identify and address potential obstacles and barriers to adoption,
identify gaps, and seek opportunities for improvement.
2024 Integrated Resource Plan |Energy Efficiency, Electrification, & Demand Response 39 | Page
Residential Programs
Income-Qualified EV Voucher
The purpose of the program is to reduce or remove barriers to adoption by lowering the down payment
amount, the monthly payment amount, and ultimately lowering customers’ ongoing fuel and maintenance
costs by providing affordable energy that can be used to fuel their vehicles. Funded through LCFS, the
Income-Qualified EV Voucher program applies to REU customers who are at or below the Shasta County
median income level.
Income-Qualified EV Voucher Program: applicants can receive a point-of-sale discount off the
purchase or lease of a new or used qualifying electric vehicle from a participating retailer.
Income-Qualified e-Bike Voucher
The purpose of this program is to provide clean mobility options and solutions to Redding’s most vulnerable
community members. Recognizing that the low-income community may not have the ability to invest in an
electric vehicle, the Utility is offering an income-qualified electric bike voucher. Customers who are earning
an income that is at or below 80% of the Shasta median income can qualify for the voucher.
Income-Qualified E-Bike Voucher Program: applicants can receive a point-of-sale discount off
the purchase of a qualifying e-bike from a participating retailer; additional incentives toward
helmet and lock are also available.
Commercial Programs
The Utility has worked in partnership with other COR departments to evaluate the policies and procedures
around commercial EV charging infrastructure investments. Policies were updated to comply with the
State’s charging infrastructure requirements set forth in AB 2127 and AB 970. Additionally, the Utility has
implemented a complimentary site assessment service to provide service planning information to
customers in an effort to educate customers and encourage investments in public charging infrastructure.
A dedicated website has been established allowing customers to find relevant commercial EV charging
permitting and building information in one central location.
Commercial DC Fast Charger Rebate
The purpose of this program is to promote the investment and installation of EV fast-charging infrastructure
in Redding to support and meet demand for alternative fueling. Many small businesses are interested in
installing EV infrastructure, but the initial capital costs can be prohibitive.
DCFS Rebate Program: applicants can receive a rebate per charging port on qualifying EV
charging installations.
Commercial Demand Credit
With the installation of fast charging stations, many small businesses are required to install a second
electrical service, which carries an added expense and exposes them to a potentially significant demand
fee. Until the charging stations are used regularly and the load factor become favorable, the demand fees
2024 Integrated Resource Plan |Energy Efficiency, Electrification, & Demand Response 40 | Page
can be cost-prohibitive. A demand fee credit can be applied for customers with installations that meet the
following criteria:
Between 50-200kW capacity
Separately metered stations
Assign LCFS credits to REU
The demand fee credit can be applied for five years and ramps down by 20% each year before sunsetting.
Transportation Electrification Infrastructure Projects
Public Charging
In 2022, the COR installed four DC Fast Charging stations as a pilot project to encourage third-party
investments in charging infrastructure. The COR owns and operates the stations, which are located at the
entrance to the Sundial Bridge. Charging rates were established through a public hearing process and are
set at $0.20/kWh, REU’s cost to provide power, which is significantly lower than typical public charging fees.
Adopting affordable charging rates ensures customers have equitable access to public charging.
Since the Sundial Bridge Charging Project was energized, an
additional eight super-charging stations have been installed
in the same area, and several additional infrastructure
projects are currently in the planning, permitting, and
construction phases throughout Redding.
To incentivize investments in EV fueling infrastructure, REU
has fostered close collaborations with EV charging
providers, alongside its partnership with the COR. Together,
suitable locations for EV charging stations have been
pinpointed and diligently assessed. Through site
assessments and circuit impact studies conducted by REU,
available capacities have been provided and any essential
infrastructure upgrades needed at these locations have
been identified. Whenever viable, the COR has taken the
initiative to lease properties to third-party charging
providers, encouraging the installation of EV charging
infrastructure.
City of Redding ZEV Fleet Replacement and Infrastructure Plan
The COR has contracted with Frontier Energy to create a comprehensive City-wide Zero-Emission Fleet
Replacement and Infrastructure Plan. The primary objective of this Plan is to carefully assess the electric
fuel supply requirements for the future transition of the COR’s light-, medium-, and heavy-duty fleets to
zero-emission vehicles. However, there are several ancillary benefits that the plan will provide.
The comprehensive plan will help proactively prepare for the anticipated impacts resulting from
the increased adoption of electric vehicles.
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The plan will support applications grant funding opportunities to help with the added cost of
infrastructure required to meet the Fleet’s electric fuel supply demands.
Sharing the plan with other agencies impacted by the State’s ACF Rule will encourage
collaboration and joint infrastructure planning across the region.
Furthermore, this Plan aims to ensure that the COR not only meets but also maintains compliance with
regulations while aligning with the State's ambitious goals of significantly reducing transportation
emissions.
Electric Vehicle Charging Rates and Managed Charging
REU is in the process updating its 2021 Cost of Service Analysis (COSA), and in the upcoming Cost of Service
and Rate Design Study, it is evaluating the potential for creating a new customer class, EV charging rates
for Fiscal Year (FY) 2024 and FY 2025. Rates will be designed to follow the Strategic Rate Design document,
support the Council’s rate philosophy, and closely follow the COSA results by categorizing the customer-,
demand-, and energy-related costs for each customer class.
The current rate structure supports the adoption of transportation electrification and EV charging by
providing low-cost power to our customers. Low electricity costs can help offset initial investment by
reducing the operating costs of EVs, making the cost of charging an EV more affordable than refueling a
gasoline or diesel vehicle. Overall, low electricity costs create a favorable environment for transportation
electrification by reducing the financial barriers and increasing the economic viability of electric vehicles
and charging infrastructure.
The electrification forecast provided by Dunsky evaluated various adoption scenarios including low
adoption, high adoption, and managed charging scenarios. This exercise provided REU with valuable
insights to use when planning for the increased system demand from electric vehicles. Forecast results
indicate implementing managed charging could reduce Redding’s peak demand by up to 12MW.
The potential benefits of managed charging have been reviewed. While there are no plans to offer managed
charging at this time, REU continues to explore ways to incorporate managed charging strategies into its
current customer program portfolio to determine whether that is a technology that would benefit REU and
its customers. Additionally, REU is evaluating time-of-use rates and will continue to assess the necessity
for managed charging in the event that time-of-use rates are imposed.
4.3 Building Electrification
The Building Electrification program portfolio for both residential and commercial customers aim to
simultaneously contribute to the state’s goal of doubling statewide energy efficiency savings as codified in
SB 350 through traditional EE programs and fuel-substitution (electrification) options, and support
decarbonization efforts. To align with decarbonization efforts, REU developed Building Electrification
programs to support the conversion of fossil-fueled appliances (natural gas, propane) with electric heat
pump technologies.
The following section describes the program offerings.
2024 Integrated Resource Plan |Energy Efficiency, Electrification, & Demand Response 42 | Page
Residential Programs
Residential Building Electrification Heat Pump Rebates – AAFS
The Residential Building Electrification Heat Pump Rebate program offers prescriptive rebates for
residential ratepayers to replace natural gas or propane-fueled appliances with heat pump technology.
Selected measures support the DSM-IRP by saving participants money without burdening non-participating
ratepayers and has the potential to reduce the overall energy costs. Measure offerings include:
Heat Pump Clothes Dryers replacing gas appliances
Heat Pump Water Heaters replacing gas appliances
New Construction Building Electrification – AAFS
The New Construction Building Electrification Rebate Program offers prescriptive rebates for developers to
install heat pump equipment instead of natural gas appliances for space and water heating. Measure
offerings include:
Heat pump water & space heating combination
Commercial Programs
Building Electrification Heat Pumps – AAFS
The Commercial Building Electrification Heat Pump Rebate program offers prescriptive rebates for
residential ratepayers to replace natural gas or propane-fueled appliances with heat pump technology.
Heat Pump Water Heaters replacing gas appliances
4.4 Energy Efficiency and Greenhouse Gas Reduction
Investing in energy efficiency has long been recognized as a means of reducing losses on the power
distribution system. Such investments have positive impacts on customer rates, the environment, and the
lifespan of transmission, distribution, and generating assets. Energy efficiency programs represent
significant strides in reducing losses on REU’s distribution system. For instance, since the implementation
of the street lighting program in September 2015, REU has reduced annual system losses by an average of
1,860,000 kWh by converting high-pressure sodium lighting to LED lighting.
Energy Efficiency Programs
City Energy Efficiency Economic Response Program – Committed Savings
The City’s Energy Efficiency Economic Response Program (EEERP) was established in 2020 in response to
the Covid-19 Pandemic. The EEERP provides energy efficiency and greenhouse gas reducing measures to
COR facilities to help offset utility costs to respective departments. Measures replaced include:
Replace electric resistance water heaters to heat pumps
Upgrade to more efficient pool pumps for community aquatic center
Lighting upgrades for stadiums and city facilities
2024 Integrated Resource Plan |Energy Efficiency, Electrification, & Demand Response 43 | Page
City LED Streetlight Upgrades – Committed Savings
LED technology consumes nearly two-thirds less energy. The LED Streetlight Replacement Project reduces
operational costs, energy consumption, and GHG emissions throughout the city by replacing high-intensity
discharge (HID) lights with LED technology. Seventy-seven percent or over 6800 HID streetlights have been
replaced with LED fixtures through 2022. REU expects the remaining streetlights to be replaced by 2024.
Greenhouse Gas Programs
Non-Motorized Transportation – GHG Reduction
The Non-Motorized Transportation program provides funding for installation of sidewalks and bike lanes
that reduce GHG emissions by improving access throughout City streets to encourage alternatives to
traditional transportation methods. Funding also provides the development of additional trail system
enhancements throughout the city.
Retired Programs
As discussed, REU has retired several programs as it shifts focus from EE to decarbonization efforts. In
addition to energy efficiency programs, GHG programs are also winding down as there is no longer a surplus
of GHG allowances available to sell at auction for program proceeds. While this is considered a
decarbonization effort, there are fewer funding opportunities to support. REU continues to evaluate
programs that can be funded by other means (LCFS, Public Benefits, and ratepayer) to support
decarbonization programs. Programs that have been terminated include:
Residential Energy Efficiency Deemed Rebates
● Building Envelope (Windows, Ceiling, Floor, & Wall Insulation)
● Energy Star Appliances (Refrigerators, Room A/Cs, Variable-Speed Pool Pumps)
● HVAC Systems (Air Conditioning & Space Heating)
● Water Heater Replacements
Commercial Energy Efficiency Deemed Rebates
● Food Service Equipment
● HVAC Systems (Air Conditioning & Space Heating)
● Refrigeration Equipment
● Water Heater Replacements
Commercial Custom Rebates
Commercial Lighting Rebates
Low Income Energy Efficiency & Electrification Programs
Shade Trees
2024 Integrated Resource Plan |Energy Efficiency, Electrification, & Demand Response 44 | Page
4.5 Future Programs
REU does not expect to meet the current savings targets due to the shift to electrification. However, REU
continues to find opportunities to meet savings targets through electrification programs. Areas of
opportunity that may be considered to support electrification, decarbonization, or demand reduction
programs included but are not limited to the following:
Residential and commercial induction cooktop programs
Residential and commercial heat pump space heating programs
Residential and commercial behavioral programs
Panel upgrades
Low-Income direct-install programs
4.6 Demand Response Programs
Demand Response (DR) programs incentivize customers to reduce the impact of peak demand by load
shifting activities, including sending signals to reduce consumption through energy efficiency, appliance
adjustments, utilize backup generation, or time-of-use rates. Currently, REU’s DR efforts are limited to the
CEC’s Demand Side Grid Support (DSGS) program, which uses backup generation at certain COR facilities.
In Summer 2022, during a period of high demand, the Utility collaborated with other COR departments,
specifically the Wastewater and Water Departments, to effectively utilize backup generation. This
collaborative effort aimed to alleviate the strain on the grid during peak demand periods, reducing peak
demand by 2.54 megawatts.
REU regularly evaluates opportunities for customers to adjust their electricity usage during times of
increased demand; however, due to the limited potential for load shifting, there are no current demand
response programs or time-of-use rates offered to customers. Programs to incentivize the purchase of DR-
capable appliances (heat pump space and water heating, for example) have been considered as an interim
step to deploy a full DR program for customers. However, this would need to be supported with time-of-
use rates, which would require additional investment. In addition to the existing DSGS program, REU is also
evaluating utility-side DR to shift load.
4.7 Energy Storage
REU continuously evaluates the procurement for energy storage requirements. 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:
Use mechanical, chemical, or thermal processes to store energy that was generated at one time
for use at a later time.
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.
2024 Integrated Resource Plan |Energy Efficiency, Electrification, & Demand Response 45 | Page
Use mechanical, chemical, or thermal processes to store energy generated from renewable
resources for use at a later time.
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 serves as an efficient means of mitigating system peaks and delivering energy during periods of
maximum demand. It can function as an independent asset or be integrated with renewable sources like
wind or solar to enhance the reliability of intermittent resources. Notably, the costs associated with energy
storage have witnessed substantial reductions in recent years, with the expectation that this trend will
persist in the foreseeable future.
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 regarding the goals adopted by the Council
in 2014. In 2005, REU installed Thermal Energy Storage (TES) systems at various City facilities. 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 for customers. REU evaluated and adopted ES procurement targets in
response to AB 2514. This resulted in expanding TES installation to commercial customers from 2012 to
2020. REU met its 2020 behind-the-meter (BTM) ES target of 3.6 MW of, therefore satisfying AB 2514 and
AB 2227 requirements. The TES systems have reached their useful life and are in process of being
decommissioned. Therefore, no additional BTM from TES systems are included in the Itron load forecast.
While BTM storage is no longer included explicitly in the load forecast, REU continues to evaluate ES
procurement opportunities on the supply-side as a resource or on the utility's distribution-side as front-of-
meter applications. Utility-scale ES can be effective in reducing system peaks and providing energy at the
time of day when it’s most valuable. ES costs should continue to decrease and technologies should improve
to support utility-scaled needs. Battery storage is an available resource selected in the modeling for the IRP
evaluation.
4.8 Localized Air Pollutants and Disadvantaged Communities
The California Environmental Protection Agency (CalEPA) currently identifies disadvantaged communities
using the California Communities Environmental Health Screening Tool (CalEnviroScreen). The COR is not
an officially designated disadvantaged community (DAC); however, several census tracts within the COR
are designated low-income according to California Climate Investments Priority Populations map.
REU recently retired its low-income weatherization program, LIEEP (as mentioned in Section 4.4), which
provided energy efficiency and limited electrification upgrades at no cost to low-income customers. REU
continues to design and develop programs to support electrification efforts for the low-income community
in alignment with the DSM-IRP’s objectives. Current offerings include promoting alternative mobility
options for purchasing electric vehicles and electric bikes. Both programs provide point-of-sale discounts
to lower the upfront cost barriers that prevent customers from investing in cleaner transportation.
2024 Integrated Resource Plan |Energy Efficiency, Electrification, & Demand Response 46 | Page
Plans for new or future program developments that aim to educate and assist low-income customers will
focus on coordinating with local agencies and leveraging existing programs in other COR departments to
ensure the needs to the low-income community are met.
2024 Integrated Resource Plan |Existing System and Resource Description 47 | Page
5. Existing System and Resource Description
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 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, REU 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 REU, 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 Utility’s electric system (Electric System)
includes generation, transmission, and
distribution assets. REU also purchases power
and transmission services from other entities,
referred to as market purchases and sales. For
the Fiscal Year ended June 30, 2023,
approximately 45,000 customer accounts were
served, with a total sale of 738,500 MWh, and
realized a peak demand of 234 MW.
2024 Integrated Resource Plan |Existing System and Resource Description 48 | Page
The electric resources used to meet the power requirements of customers include generation supply
resources, renewable energy 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 2022, are presented in Table 5-1. These resources are further
described in this section.
Table 5-1: Calendar Year 2022 Energy Resources
Capacity Available
(MW)
Annual Energy
(GWh)
Percent of Total
Energy
Generated Power
Redding Power Plant1 (U1-U6) 183.1 426,918 60%
Whiskeytown (U9) 3.5 25,916 4%
Total Generated Power 186.6 452,834 64%
Carbon-Free Power Purchase Agreements
WAPA Base Resource2 128.5 63,163 9%
Big Horn I Wind Project 23.0 163,586 23%
Total Purchased Power 151.5 226,749 32%
Market Power
Market Power Purchases - 149,939 21%
Market Power Sales - -117,111 -16%
Net Market Power - 32,828 5%
Total 338.1 712,411 100%
1. Capacity listed is nameplate capacity (EIA860 defined) for Redding Power Plant.
2. The hydro-based contract with WAPA is for 128.5 MW, but the average summer capability is 74 MW.
5.1 Generating Facilities
Redding Power Plant
The Plant is the primary local generation resource, with a total station nameplate capacity of 183.1 MW.
The Plant is comprised of: one (1) two-on-one combined cycle power generating station with two Siemens
SGT-800 gas turbines (nameplate capacities of 42.5 MW and 40 MW) coupled with a 26.8 MW nameplate
capacity GE steam turbine, and three GE Frame 5 simple cycle combustion turbines (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.
2024 Integrated Resource Plan |Existing System and Resource Description 49 | Page
The initial steam unit (Unit 4) was acquired and converted from biomass fuel to gas in 1991. Both generator
Units 5 and 6 can operate in combined-cycle mode to provide steam to Unit 4. A steam turbine bypass
allows either Unit 5 or Unit 6 to operate by sending the generated steam to a secondary steam condenser.
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 COR
water to meet its cooling needs.
Whiskeytown Project
The COR owns and operates a 3.5 MW hydroelectric generating plant located at the U. S. Bureau of
Reclamation Whiskeytown Dam near Redding. This project was completed in 1986 and has produced an
average of approximately 26 GWh annually since that time. In some years, temporarily high flow releases
have been captured by the flexibility of the dual runners installed in the unit and additional energy has been
generated. Under minimum flow release restrictions, it is estimated the facility could produce
approximately 10 GWh per year.
In 2021, the controls system for the Whiskeytown station were upgraded to a new programmable logic
controller (PLC) system to replace obsolete equipment. The upgrade also allowed remote viewing of the
turbine performance from the Redding Power Plant.
The COR has received full CEC certification for the Whiskeytown facility as a California RPS Eligible
renewable resource. The facility has been registered with WREGIS, and the associated RECs will either be
retained for RPS compliance purposes or utilized for wholesale sales.
The operating license will need to be renewed in 2033. It is expected that the license will be renewed, and
Whiskeytown will continue to generate as an eligible renewable resource providing carbon-free power and
RECs.
2019 IRP Local Solar Project (Cancelled)
As directed by the preferred portfolio outlined in the 2019 IRP, REU collaborated with NCPA to seek
proposals for a 10 MW solar project in REU’s service territory in 2019. Despite receiving competitive bids
for the project, costs exceeded initial expectations and were higher than those of larger-scale projects.
Consequently, the decision was made to prioritize larger-scale projects to fulfill RPS compliance
requirements.
2024 Integrated Resource Plan |Existing System and Resource Description 50 | Page
5.2 Power Purchase Agreements
In addition to owning and operating generating facilities, REU supplements its energy needs through
contractual purchases of energy, transmission, and gas.
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. As
a member of the M-S-R Public Power Agency (M-S-R PPA), a Joint Powers Agency (JPA) with Modesto
Irrigation District and the City of Santa Clara, REU receives a 35 percent share of the output from the Big
Horn through a power purchase agreement (PPA). REU’s share of Big Horn wind energy equates to
approximately 70 MW (22 MW firm capacity through a firming and shaping agreement) of the project’s
output. Power deliveries commenced on October 1, 2006, and will continue through September 30, 2026.
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, Avangrid (owner and operator of Big Horn) receives energy generated from Big Horn, and
delivers a firmed and shaped 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 the COR.
Big Horn is considered an eligible renewable resource by the CEC for California RPS certification. 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.
REU retires the RECs towards RPS compliance accounts on an annual basis.
Big Horn Contract Extension
Big Horn's current contract (Initial Term) expires on September 26, 2026; however, there is an option to
extend the contract through September 30, 2031, or negotiate a new PPA if the units are repowered. REU
staff developed a forecast based on the assumption that Avangrid will exercise the contract extension
option (Extension Term) to determine the pricing assumptions and financial impacts.
Currently, the Initial Term variable costs are comprised of the price of energy, plant operations and
maintenance (O&M), and the firming and shaping agreement. The Extension Term updates the variable
cost components to incorporate the following:
Monthly Market Index Price (MMIP) + REC pricing as a portion of the cost of energy if it is greater
than the contracted price
O&M costs based on real pricing instead of 2005 nominal value
Escalation rates to a portion of fixed costs
Current fixed costs are expected to remain constant
2024 Integrated Resource Plan |Existing System and Resource Description 51 | Page
The Extension Term forecast indicates variable costs are higher than what was paid historically due to the
O&M costs driving an immediate increase at the start of the new contract term. Furthermore, the addition
of the MMIP and REC pricing potentially exposes REU to market volatility. Figure 5-1 highlights the expected
increase in variable and fixed costs for Big Horn through the extension contract term.
Figure 5-1: Initial Term Costs vs. Extension Term Cost Components
WAPA Base Resource (Hydroelectric Power)
The 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 WAPA began on January 1, 2005, and
continues through 2024. On January 19, 2021, the Council authorized REU to extend the Base Resources
contract with WAPA effective January 1, 2025, through December 31, 2054. REU's current allocation is
8.159% of base resource hydroelectric energy generated by WAPA. With the contract extension, REU's
allocation of the total CVP generation will be reduced by 2% (from 8.159% to 7.996%) beginning 2025, with
an additional 1% reduction (to 7.916%) commencing January 1, 2040.
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 the COR—and at the Airport
Substation, located in the southeastern part of the service territory. Power is transmitted to distribution
substations over the 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. Deliveries are
highly dependent on the hydrologic conditions (rainfall, snowpack, reservoir level, etc.) of Northern
California and can vary significantly from year to year. For example, REU received 153 GWh of energy in
$-
$50,000
$100,000
$150,000
$200,000
$56
$58
$60
$62
$64
$66
$68
$70
$72
$74
Fi
x
e
d
C
o
s
t
s
(
$
/
y
r
)
Va
r
i
a
b
l
e
C
o
s
t
s
(
$
/
M
W
h
)
Big Horn Fixed and Variable Cost Components
BH - Variable Cost Forecast, $/MWh BH - Fixed Cost Forecast, $/yr
2024 Integrated Resource Plan |Existing System and Resource Description 52 | Page
calendar year 2021 after below-average rainfall in Northern California. In calendar year 2022, REU received
69 GWh of energy – a 45 percent decrease from 2021 – after critically-dry drought conditions remained in
Northern California. Deliveries are expected to increase in 2023 due to exceptional rainfall during the year.
While not truly dispatchable, REU is able to shape the daily deliveries of WAPA Base Resource energy within
minimum hourly, maximum hourly, and daily total energy. This valuable capability enables REU to align
energy scheduling with anticipated load profiles. Looking ahead, this synergy could be particularly
advantageous when integrating non-dispatchable renewable resources with predictable generation
patterns, such as solar.
REU’s contract with WAPA includes power from numerous hydroelectric plants around the Sierra Nevada
Region, some of which qualify as a California RPS eligible renewable resource. REU participates in WAPA’s
Sierra Nevada Region (SNR) REC program to receive the RECs from qualifying hydroelectric projects. RECs
from these qualifying hydro facilities (under 30 MW) account for approximately 1.7% of the total allocated
Base Resource, supporting RPS targets and the SB 100 requirement to achieve a 100 percent carbon-free
resource mix by 2045.
Impact of Drought
In an average water year, approximately one-third of REU’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 5-2 indicates, for example, that during four
consecutive years of drought, generation received from the WAPA CVP was significantly reduced.
Table 5-2: Historic Deliveries from WAPA CVP
Calendar Year Energy (GWh)
2018 342
2019 341
2020 253
2021 153
2022 69
Est. 2023 172
In the event of reduced hydroelectric generation, generating additional energy or purchasing additional
energy on the wholesale market may be necessary to meet retail sales load obligations, and such actions
can significantly increase power supply costs. This is a consideration when planning for future resources
and when assessing the risk of renewable energy 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 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 the COR’s share of Big Horn Wind. During such periods, there may be a
2024 Integrated Resource Plan |Existing System and Resource Description 53 | Page
need to purchase replacement energy from the wholesale market or generate replacement energy at an
additional cost.
WAPA Contract Renewal
During the development of the 2019 IRP, Base Resource customers and WAPA were actively negotiating a
30-year contract renewal (Renewal) to continue base resource hydroelectric power after December 31,
2024. REU staff developed the Renewal Forecast to analyze the impacts prior to signing the Renewal, which
included:
Extending the forecast period from January 1, 2025, through December 31, 2054
Reducing Base Resource allocation by 2% beginning January 1, 2025
Further reducing Base Resource allocation by 1% beginning January 1, 2040
The Renewal Forecast findings indicate that Base Resource remains a cost-effective resource throughout
the forecast period. On January 19, 2021, City Council approved REU staff recommendation to sign the
WAPA Renewal based on the assessment. The model incorporated the results from the Renewal Forecast
upon approval.
The reduced Base Resource allocation also decreases the cost of the contract for Redding (Figure 5-2).
Furthermore, WAPA updated the FY21-FY30 Power Revenue Requirement (PRR) forecast due to
adjustments made by the Bureau of Reclamation on operations and maintenance (O&M) costs and project
repayments.
Figure 5-2: WAPA Costs - Historical and Forecast
$0.00
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
$70.00
$80.00
$/
M
W
h
Western BR Cost-Historical Western BR Cost-Forecast
2024 Integrated Resource Plan |Existing System and Resource Description 54 | Page
5.3 Renewable Energy Resources
Since 2003, REU has aggressively pursued cost-effective and self-owned or purchased renewable resources
through adopted RPS targets. Currently, REU has a diversified renewable portfolio comprised of the
following resources:
Hydroelectric resources (owned)
Hydroelectric resources (long-term contracts)
Wind power (long-term contracts)
Renewable Energy Contracts (long-term and short-term contracts)
The current resources, which include zero carbon and renewable resources, are summarized in Table 5-3.
It is important to note that while WAPA large hydro is considered a zero-carbon resource, it does not qualify
as an eligible renewable energy resource. Similarly, behind-the-meter solar does not qualify for utility
renewable energy or zero-carbon categorization.
Table 5-3: Current (Calendar Year 2022) Clean Energy Resources
Resource Type Capacity Available
(MW)
Annual Energy
(GWh)
Percent of Retail
Sales
Renewable Resources
M-S-R PPA/Big Horn I Wind Project Wind 23.0 163 23%
WAPA Base Resource – Small
Hydro Small Hydro 1.3 5 1%
Whiskeytown (U9) Small Hydro 3.5 26 4%
Total Renewable 26.5 194 27%
Carbon-Free Resources
WAPA Base Resource – Large
Hydro Large Hydro 128.5 63 8%
Total Clean Energy 155.0 252 35%
Hydroelectric generation has a significant impact on REU’s power mix. In 2021, approximately 81 percent
of retail sales were supplied by zero carbon resources. However, in 2022, the proportion of zero carbon
resources declined to approximately 53 percent due to severe drought conditions affecting hydroelectric
generation. This reduction led to an increased reliance on fossil fuel resources to satisfy energy demand.
In 2022, REU received notification from the CEC staff that 121,352 of its RECs, which had been intended for
use in Compliance Period (CP) 3 to satisfy Excess Procurement requirements, were rendered ineligible. This
ineligibility arose from an administrative error within the reporting tool when the RECs were retired.
Consequently, RECs planned for CP 4 compliance were moved into the CP 3 subaccount to satisfy CP 3 RPS
requirements for that period, causing a short position for CP 4. Subsequently, REU staff have sought bids
to replace those compliance instruments; however, due to elevated market prices, the cost to replace those
2024 Integrated Resource Plan |Existing System and Resource Description 55 | Page
ineligible RECs would disproportionately impact customers. Figure 5-3 shows the potential impact to RPS
obligations due to the ineligible RECs. Note that REU would not Compliance Period 4 (2021-2024)
requirements and would potentially have to seek alternative compliance.
As a result, REU is evaluating the potential need to exercise an Optional Compliance Measure to satisfy the
RPS requirements for CP 4. To ensure ongoing compliance with SB 100, and meet the RPS targets, REU
actively monitors RPS-eligible resources and considers the need for Optional Compliance Measures
outlined in its RPS Procurement and Enforcement Plan (Exhibit 9.4).
Figure 5-3: 2019 IRP Scenario H v. SB 100 Renewable Requirements with Ineligible RECs Removed
The 2019 IRP's preferred portfolio was devised to align with the renewable energy objectives mandated by
SB 350. Initially, REU was tasked with procuring 50 percent of energy supplied to end-use customers from
eligible renewable sources by 2030. However, SB 100 subsequently raised the compliance threshold to 60
percent eligible renewables by 2030, introduced long-term contract requirements, and introduced a zero-
carbon target for 2045. Concurrently, SB 1020 set interim carbon-free energy targets of 90% in 2035 and
95% in 2040.
The preferred scenario outlined in the 2019 IRP no longer satisfies these updated compliance requirements
and targets, as depicted in Figure 5-4. Therefore, it becomes imperative to reassess and adapt this portfolio
accordingly.
-
500,000
1,000,000
1,500,000
2,000,000
2,500,000
3,000,000
0%
20%
40%
60%
80%
100%
120%
WAPA Big Horn Whiskeytown
Index+Optimized Banked Retirement RPS Requirement
Rolling Banked RECs
2024 Integrated Resource Plan |Existing System and Resource Description 56 | Page
Figure 5-4: 2019 IRP Scenario H vs. SB 1020 Carbon-Free Targets
REU contracted with Ascend to incorporate the adjusted regulatory obligations into its current portfolio
scenario to evaluate the long-term effects of the updated requirements. In addition to the stricter energy
procurement requirements, there are new Long-Term Procurement and Portfolio Balancing Requirements
within the updated RPS regulations that must be adhered to. As such, adjustments to the portfolio included
larger eligible renewable project PPAs and earlier procurement target dates.
Renewable Energy Purchases
The preferred plan identified in the 2019 IRP included the addition of 10 MW of local solar generation,
originally scheduled to begin operation in 2026, with another Wind Project coming online in 2034.
However, updated clean energy mandates rendered the plan non-compliant with new regulatory
requirements. To bridge the gap until future renewable projects could be developed, REU executed a short-
term, one-year contract for 100,000 MWh of renewable energy, which provided PCC1 RECs to address the
shortfall. The long- and short-term contracts will deliver energy with PCC1 RECs according to the schedule
in Table 5-4.
0%
20%
40%
60%
80%
100%
120%
WAPA Big Horn Whiskeytown
NorCal Wind Local Solar + CV PV SB 1020 Targets
2024 Integrated Resource Plan |Existing System and Resource Description 57 | Page
Table 5-4: Contracted PCC1 REC Deliveries
RPS Compliance
Period Calendar Year Long-Term Contract
Energy, MWh
Short-Term
Contract Energy,
MWh
Total, MWh
5 2025 125,000 50,000 175,000
5 2026 125,000 50,000 175,000
5 2027 125,000 50,000 175,000
6 2028 175,000 0 175,000
6 2029 175,000 0 175,000
6 2030 175,000 0 175,000
7 2031 175,000 0 175,000
7 2032 175,000 0 175,000
7 2033 175,000 0 175,000
7 2034 175,000 0 175,000
Total 1,600,000 150,000 1,750,000
In addition to the renewable resources listed above, the 2019 IRP preferred plan identified the need for a
60 MW solar project beginning in 2026. As a result, multiple requests for proposals were solicited across
various joint powers agencies, and many competitive bids were received. REU worked with Ascend
Analytics to evaluate the potential projects and choose the one that satisfied the requirements for
renewable compliance and provided the most benefit to REU and its customers.
Based on the analysis of the various proposal received, given the current portfolio needs and compliance
requirements, REU selected two Index+ projects to deliver long-term and short-term PCC1 RECs for the
years 2025 through 2034. With the Index+ structure, renewable energy is bundled with the RECs. The seller
schedules the energy to deliver to the CAISO market, REU receives the renewable attribute, and the seller
is compensated by the CAISO for energy delivered.
5.4 Transmission Assets
The transmission facilities owned or contracted for are described in this section. Owned transmission
facilities are shown in Figure 5-5.
2024 Integrated Resource Plan |Existing System and Resource Description 58 | Page
Figure 5-5: REU Existing Transmission
2024 Integrated Resource Plan |Existing System and Resource Description 59 | Page
WAPA Transmission Service and BANC
REU is a customer of WAPA, who provides access to their high voltage transmission via an interconnection
with its distribution system. Through a transmission service contract, any power needed to meet system
loads that are not met by generation assets within the service area can be imported using WAPA’s
transmission. 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 5-5. The WAPA transmission system is part of the Balancing Authority of Northern California (BANC)
balancing authority area (BAA) and interconnects with the California Independent System Operators
(CAISO) BAA.
Table 5-5: WAPA Transmission Service Summary Information
Capacity
Contract End Date Capacity,
MW* Voltage, kV Delivery Point(s)
Long-Term Firm Transmission
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
REU is also a member of BANC, a joint powers authority and balancing area with members that also include
the Sacramento Municipal Utility District (SMUD), Modesto Irrigation District (MID), Roseville Electric,
Trinity Public Utility District (TPUD), 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. A
map of BANC members and associated transmission, generation, and interties are in Figure 5-6.
2024 Integrated Resource Plan |Existing System and Resource Description 60 | Page
Figure 5-6: Balancing Area of Northern California (BANC) Members
As a member of BANC, REU 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.
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.
2024 Integrated Resource Plan |Existing System and Resource Description 61 | Page
BANC operates under the principle of maximizing consumer value and compliance with NERC reliability
standards. The structure provides flexibility to expand and allows members to benefit from potential future
savings through the sharing of facility costs.
TANC and California-Oregon Transmission Project
REU, along with fourteen other northern California cities, utility districts, and one rural electric cooperative,
are members, or associate members, of a California JPA known as the Transmission Agency of Northern
California (TANC). TANC, in partnership with 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.
REU 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, REU purchased from COSL, its 1.5856 percent
ownership interest (approximately 25 MW) in the COTP. As a result, REU 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 (PACI). The
PACI is a two-line system that, like the COTP, connects California utilities with other utilities in the Pacific
Northwest. The PACI is owned by PG&E, PacifiCorp, and WAPA; it is operated by the CAISO. The three-line
system comprised of the COTP and the Intertie is collectively referred to as the California-Oregon Intertie
(COI).
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, bidirectional
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 long-term agreement known as
the South of Tesla Principles (SOTP). The 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.
2024 Integrated Resource Plan |Existing System and Resource Description 62 | Page
Other Transmission Assets
Power from sources outside the service territory is delivered to 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. WAPA retains ownership of the Airport Substation facilities exclusive of the
substation property owned by REU. At the Airport Substation, WAPA owns and maintains the 230 kV related
facilities; REU owns the 115 kV facilities, which are maintained and operated by WAPA at REU’s expense.
At the Keswick Substation, WAPA owns, and is responsible for, all facilities other than the remote terminal
unit equipment specific to REU’s use at the Keswick Substation.
Transmission Losses
REU contracts with WAPA to settle transmission losses financially. This contract settles losses on all REU
transmission, including CVP, COTP, PACI, and SOTP. Through this contract, REU purchases replacement
energy in the amount of the assumed losses at the line terminus. This energy is delivered in sync with the
scheduled energy so that effective energy at the origin and terminus are the same. The replacement energy
for losses is purchased at real-time market rates.
NERC Registration
NERC, the Electric Reliability Organization for North America, has the vital responsibility of safeguarding the
reliability and security of the bulk power system (BPS). Its operations fall under the oversight of the Federal
Energy Regulatory Commission (FERC). Among the Regional Entities authorized by NERC and FERC, the
Western Electricity Coordinating Council (WECC) assumes the role of monitoring and enforcing compliance
within the Western Interconnection.
NERC and the Regional Entities have the mandate to identify and register entities that meet the criteria for
inclusion in NERC's Compliance Registry. Owners, operators, and users of the BPS must register and adhere
to approved Reliability Standards. Entities are categorized into different functional types based on their
typical operations and are obligated to comply with the relevant Reliability Standards applicable to their
registered functions.
Prior to 2020, REU was registered as a Generator Owner (GO), Generator Operator (GOP), Distribution
Provider (DP), and Resource Planner (RP). REU owns 115 kV Facilities that meet the threshold of Bulk
Electric System (BES), therefore, in 2019 WECC notified REU that it should either register as a Transmission
Owner (TO) or apply for a registration exemption with NERC.
REU pursued a registration exemption by submitting an application to the NERC-led Review Panel. NERC
determined that REU has a material impact to the BES and required REU to register as a Transmission Owner
(TO), Transmission Planner (TP), and Transmission Operator (TOP). REU completed the implementation of
all three registered functions and was officially added to the NERC's Compliance Registry as a Transmission
Owner, Transmission Planner, and Transmission Operator in 2020. As a result of the additional functional
registrations, REU's compliance obligations increased from approximately 100 Reliability Standard
requirements to around 240 requirements. This change also affected the audit cycle, which will require
REU to transition from a 6-year audit cycle to a 3-year audit cycle.
2024 Integrated Resource Plan |Existing System and Resource Description 63 | Page
5.5 Distribution Assets and Adequacy
Distribution Assets
The 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 was 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 12kV distribution system using underground cabling. Figure
5-7 shows the interface of the 115kV transmission system with the distribution system through 115 kV/12
kV substations.
Figure 5-7: Electric Distribution System
The current transmission and distribution systems consist of the following:
Service area of approximately 61 square miles
Approximately 72 miles of 115 kV transmission
Eleven transmission/distribution substations, one generation step-up substation
Approximately 740 miles of 12 kV distribution, (OH=300 mi, UG=440 miles)
Approximately 17,000 poles
2024 Integrated Resource Plan |Existing System and Resource Description 64 | Page
Distribution System Adequacy
In 2022, the service availability index achieved an outstanding rating of 99.997 percent, representing an all-
time high. This outstanding accomplishment translates to an average customer experiencing only 16.89
minutes without power throughout the entire year (Figure 5-8). The staff’s dedication to providing reliable
service has resulted in significantly better power availability and minimized disruptions for customers
compared to the broader population.
This is a significant improvement from the 2020 average outage time of 52.51 minutes. This impressive
performance is notably better than the national average for all Americans where the average power outage
duration in 2020 was 116 minutes. The 68 percent improvement in reliability from 2020 can be attributed
to the hard work and dedication of staff.
Figure 5-8: Reliability Comparison
For a more localized comparison, in the year 2020, customers of PG&E in the north valley experienced an
average of 125 minutes without power while REU customers experienced 52.5 minutes.
The combined strength of its community-owned power plant and diverse grid connections contribute to
the continued commitment to high reliability rates. By harnessing these resources and the expertise of
dedicated personnel, REU successfully mitigated the impacts of the Carr Fire, a raging wildfire that tore
2024 Integrated Resource Plan |Existing System and Resource Description 65 | Page
through Shasta County and blazed into Redding’s city limits, safeguarding the well-being and comfort of
the community during an exceptionally challenging time.
The distribution system conditions are continually evaluated and appropriate adjustments are made as
needed to improve and optimize the distribution network. Projects aimed at these improvements are
approved and funded through the Electric Distribution Capital Expenditure Plan. Currently, REU is
considering the following modifications:
Replacing aging underground cables in our infrastructure. Our estimates indicate that
approximately 790,000 feet (149 miles) of underground cable currently require replacement
due to age-related issues, including regular cable failures.
● Estimated completion by end of 2027
Upgrading aging circuit breakers and circuit switchers at substations.
● Estimated completion by end of 2025
Implementing substation improvements to enhance safety and security. This project will focus
on strengthening the physical security of substations throughout our service territory, including
upgrades to fences, security cameras, lighting, and other detection methods.
● Estimated completion by end of 2025
Conducting line capacity upgrades and Volt-Var Optimization (VVO) for voltage support. These
projects involve model validation, analysis, and distribution system improvements through line
capacity upgrades and capacitor placement, ensuring sufficient capacity to serve new electric
loads with minimal losses.
● Estimated completion by end of 2027
Design and construction of a new 115/12kV substation in Stillwater Business Park. This new
substation will be in the southeast side of Redding and will increase system capacity and service
reliability.
● Estimated completion date in 2028
Installing reclosers at Tier 2 or Tier 3 boundaries as part of the fire mitigation plan. This
deployment of fast interrupting reclosers at the fire zone boundaries will enhance reliability on
circuits outside of Tier 2 and 3 fire zones, eliminating the need to set feeder breaker relays to
non-reclosing during periods of increased fire hazard, as required by the state of California.
● Estimated completion by end of 2027
Furthermore, REU is exploring alternative initiatives aimed at enhancing the communication systems
essential for integrating further investments in demand-side energy management. One potential initiative
involves the phased installation of optional Outage Management System (OMS) and Distribution
Management System (DMS) software. This software would complement the existing system management
software, OSI-SCADA, used by Electric Utility Distribution System Operators. By implementing these
2024 Integrated Resource Plan |Existing System and Resource Description 66 | Page
upgrades, response times are expected to improving, reduced risks of switching errors, and decreased
likelihood of unknown equipment overloads.
Phase one of the OMS project has been successfully completed, although additional refinements are still
necessary. However, after a comprehensive evaluation and comparison of these projects with the priorities
outlined in the 2022 Strategic Plan, it has been decided not to pursue the DMS and network projects during
this revision of the IRP.
5.6 Natural Gas Commodity, Transportation and Storage
Natural gas is the primary fuel and the primary variable operating cost of the Plant. The Plant 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.
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 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, REU 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).
Fixed Price Forward Purchases
In addition to natural gas procured through the M-S-R EA Gas Prepay Project, REU also enters fixed price
forward gas contracts.
Table 5-6 provides the volume of current fixed price natural gas purchases to which REU has committed.
Table 5-6: Natural Gas Fixed Price Hedges
Year 2023 2024 2025 2026 2027
Decatherm per day (Dth/day)* 9,722 6,538 4,875 2,625 875
*Delivery Point is PG&E City Gate
2024 Integrated Resource Plan |Existing System and Resource Description 67 | Page
Natural Gas Transportation
In order to provide for the transportation and delivery of purchased natural gas, REU 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. In 2022, REU permanently signed over all shipping rights to a third
party. When the current contract expires in October 2023, REU will no longer hold any firm gas shipping
rights.
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, REU 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.
5.7 Wholesale Energy Trading
REU 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.
Like any utility, generation and transmission resource additions may not perfectly align with yearly load
projections. To manage this discrepancy, in addition to strategic market purchases when cost-effective,
REU leverages its excess capacity and energy by engaging in wholesale energy market trading. This
approach aims to maximize the value of its generation assets while minimizing the expenses associated
with purchased power.
Furthermore, REU coordinates its gas purchases and sales within the year, taking into account wholesale
energy costs. In terms of financial forecasting and planning, only revenues from wholesale trading activities
under contract at the time of the forecast are considered. REU remains committed to optimizing its
generation and transmission assets within the wholesale market, ultimately benefiting its retail customers.
It is anticipated that wholesale sales will continue to play a role in power operations in the future.
5.8 Western Energy Imbalance Market (EIM)
The CAISO Western Energy Imbalance Market (WEIM) is a 5-minute, real-time, bulk power trading market
administered by the CAISO. The market utilizes a sophisticated energy model that optimizes the lowest-
cost energy to serve real-time customer demand across a wide geographical area.
2024 Integrated Resource Plan |Existing System and Resource Description 68 | Page
REU embarked on a trading modernization project to meet the challenges of changing markets and officially
joined the WEIM through BANC on April 1, 2021. All future generators installed in the BANC footprint must
be bid in the WEIM. The Redding Power Plant is currently bid into the WEIM and responds to signals from
CAISO in order to best-utilize the resource.
5.9 Extended Day-Ahead Market (EDAM)
In October 2019, the CAISO initiated the development of a new approach aimed at integrating the CAISO
day-ahead market with entities in the WEIM. The WEIM enabled entities to participate in the CAISO day-
ahead market without necessitating full integration into the CAISO itself. This approach, known as the
Extended Day-Ahead Market (EDAM), represents a significant step forward in regional energy market
collaboration and efficiency.
BANC is closely monitoring the ongoing development of the EDAM. They are actively engaged with
members to evaluate the feasibility and benefits of potentially becoming part of the integration. This
strategic involvement demonstrates BANC's commitment to exploring new opportunities for enhancing
energy market operations and achieving more efficient resource planning.
REU anticipates participating in the Extended Day-Ahead Market (EDAM). By doing so, the new market
approach can be leveraged to enhance resource planning, optimize energy operations, and ultimately
deliver more reliable and cost-effective power to customers.
2024 Integrated Resource Plan |Energy Forecast and System Impacts 69 | Page
6. Energy Forecast and System Impacts
A fundamental element of the IRP analysis
involves the careful development of long-term
projections, spanning the horizon from 2023 to
2045, for both system peak demand and energy
consumption. These forecasts serve as the
foundation upon which the Utility's strategic
planning is constructed. They summarize a
comprehensive projection of the capacity and
energy needs that the Utility must be prepared to
address, either through the development of self-
owned generation assets or via strategic power
purchase arrangements with external suppliers
and joint powers agencies.
These projections are not simply deterministic
exercises; rather, they are dynamic statistical
representations of the future energy landscape,
accounting for a variety of factors, including
anticipated population growth, commercial
expansion, technological advancements, clean
energy mandates and climate initiatives, and
evolving energy efficiency and electrification
measures. These forecasts evolve in parallel with
the ever-changing economic, social, and
technological trends, forming a critical
component in the REU's ability to proactively and
effectively navigate the complex terrain of the
energy sector to ensure both reliability and
sustainability for the Redding community.
2024 Integrated Resource Plan |Energy Forecast and System Impacts 70 | Page
6.1 Historical Energy Use and Peak Demand
Electricity demand exhibits strong seasonal trends, with peak energy requirements driven by air-
conditioning 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 6-1, which displays the monthly average energy sales for the
period of 2018 through 2022. Additionally, Figure 6-2 shows the daily variation in load by month. The
summer peak load is roughly three times the magnitude of the base load.
Figure 6-1: 5-Year Average Monthly Energy Sales and Peak Demand (2018-2022)
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2024 Integrated Resource Plan |Energy Forecast and System Impacts 71 | Page
Figure 6-2: Average Daily Load Profile by Month (2018-2022)
Table 6-1 provides a comprehensive overview of historical data spanning the last five Fiscal Years. The data
reveals that the combined peak customer demand observed from 2018 to 2022 reached its highest point
at 241 MW in 2018, in contrast to 234 MW in 2022. It is important to note that this peak demand is
significantly lower than the historical distribution system peak demand of 253 MW, which was recorded on
July 24, 2006.
While it is typical for peak demand to occur only once annually, it is crucial to emphasize that resources
must be continuously maintained at levels capable of meeting this peak demand throughout the entire
year. This ensures the reliability and resilience of the system, even during periods of maximum stress on
the infrastructure.
Energy sales exhibited a declining trend from 2018 to 2020. However, there was a significant and notable
upturn in energy sales for the years 2021 and 2022. This shift in sales patterns suggests dynamic changes
in energy consumption and demand during this period. The sales reduction was expected and aligned with
forecast trends. Analysis suggests the sudden increase in energy sales were driven by work-from-home
measures implemented during the COVID outbreak. Overall, 2022 sales are 99 percent of 2018 sales.
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2024 Integrated Resource Plan |Energy Forecast and System Impacts 72 | Page
However, 2020 sales dipped down to only 95 percent of 2018 sales. At the same time, the number of
customers has increased by 1.5 percent over the period and reached 44,981 customers in 2022.
Table 6-1: Historic Customer, Sales, and Demand Data
Year 2018 2019 2020 2021 2022
Number of Customers
Residential 38,088 38,058 38,320 38,587 38,572
Commercial 4,955 4,942 4,972 4,975 5,088
Industrial 326 334 338 353 351
Other 935 930 936 966 970
Total Customers 44,304 44,264 44,566 44,881 44,981
Megawatt-Hour Sales
Residential 368,829 356,741 358,510 393,404 375,818
Commercial 323,799 312,484 298,242 302,067 300,597
Industrial 12,626 12,372 12,349 11,552 12,155
Other 41,471 39,765 41,640 50,105 49,924
Total MWh 746,725 721,363 710,740 757,129 738,494
Peak Demand (MW) 241 228 224 225 234
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.
6.2 Forecast Methodology and Assumptions
The load forecast for the IRP planning period was developed by Itron, Inc. an energy forecasting consultant.
Future projections of energy sales and peak demand are developed based on the historical relationship
with various socioeconomic factors and temperature data as described further below.
The 2023 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
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.
2024 Integrated Resource Plan |Energy Forecast and System Impacts 73 | Page
In contrast, the strength of the end-use modeling approach is the ability to identify the end-use factors that
are driving energy use. By incorporating end-use structure into an econometric model, the SAE modeling
framework captures the strengths of both approaches. For instance, by explicitly introducing trends in
equipment saturation and equipment efficiency levels, it is easier to explain changes in usage levels and
changes in weather-sensitivity over time, and identify end use factors driving those changes.
SAE models leverage the U.S. Energy Information Administration’s (EIA) Sector-level End Use Saturation
and Efficiency Forecast for the Pacific Region as well as information specific to the 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 sector-level 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 6-2. For
the variables listed, those of special importance include assumptions about the future growth of EVs, solar
installations, energy efficiency, as well as population growth and the consideration of temperature data.
Table 6-2: Load Forecast Assumptions and Input Considerations
Category Description
Weather • Normal Weather for Energy and Peak: (Calculation Range 2013 – 2022)
Economics • Net Migration Forecast obtained from Woods & Poole Economics, Inc.
• High and Low Cases +/- 10% of forecast provided by Woods & Poole Economics,
Inc.
• Employment Forecast obtained from Woods & Poole Economics, Inc.
End Use Equipment
Saturation & Efficiency/
New Technology
• SAE Inputs – Pacific Region Efficiencies from the EIA’s 2022 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
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
2022 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 1980-2022 period formed the
basis for the “1-in-2 year” case, and the 90th percentile temperature occurring during this period formed
2024 Integrated Resource Plan |Energy Forecast and System Impacts 74 | Page
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.
Service Area Population
An Average Annual Growth Rate (AAGR) for population of less than one percent (0.37 percent) is projected
by Woods & Poole Economics, Inc. (the vendor used for the economic driver forecasts) for the forecast
period compared to an AAGR of 1.13 percent experienced between 1990 and 2017.
Rooftop solar installations
Recent updates to the Title 24 building code require solar installations on all new residential and
commercial buildings that generate 100 percent of the dwelling's annual consumption. This is likely to cause
an increase in behind-the-meter solar generation. Concurrently, REU implemented a net-metering rate
(commonly referred to as NEM 2.0) for customers with solar. Under this rate, excess generation is credited
at the electric utility's avoided cost instead of the retail rate. The new rate is projected to reduce natural
adoption of solar resulting from economical choice. As a result, the rooftop solar forecast is largely driven
by the expected number of new homes and commercial buildings each year. Due to the rate grandfathering
provisions approved by Council, REU received numerous applications before the net metering rate was
implemented. a percentage of these are included in the anticipated installations for 2023. As of calendar
year 2022, there is 18,076 kW of behind-the-meter solar on REU’s system Figure 6-3).
Figure 6-3: Projected Solar Installations
Transportation and Building Electrification Forecast
In preparation for the 2024 IRP update, the Resources Team proactively engaged the expertise of Dunsky.
Recognizing the importance of capturing impacts of electrification in forecasting customer demand, Dunsky
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2024 Integrated Resource Plan |Energy Forecast and System Impacts 75 | Page
was contracted to carry out a comprehensive and detailed forecast specifically focusing on building and
transportation electrification. This strategic collaboration allowed the Resources Team to gather valuable
insights and projections about the future trajectory of electrification in these two critical sectors. By
leveraging Dunsky's specialized knowledge and extensive experience, a deeper understanding of the
potential impact of electrification on the overall energy landscape was gained.
Dunsky's comprehensive analysis involved assessing various factors such as technological advancements,
regulatory frameworks, market trends, and consumer behavior. Through this evaluation, a holistic picture
was provided showing potential outcomes and implications of building and transportation electrification.
The findings of this forecast provided the Resources Team with vital information to inform their decision-
making process and align their strategies with the emerging electrification trends. With a clearer
understanding of the opportunities and challenges associated with building and transportation
electrification, staff was better equipped to develop an effective and sustainable roadmap for the 2024 IRP
update.
The research objectives for the electrification forecast were to:
1. Forecast service territory-wide adoption of electrified technologies to support REU’s long-term
planning efforts
2. Consider service territory-wide load impacts of Electric Vehicle (EV) adoption, including annual
energy and demand and hourly impacts for a select number of peak and off-peak days
3. Provide results that will integrate with other REU forecasts for the purpose of resource and
distribution planning
Based on findings from the electrification forecast, by 2045, up to 24,700 additional units of space heating
heat pumps, 11,400 additional units of electrified water heating equipment, and 37,000 additional units of
electrified cooking equipment could be seen in Redding. Although variations in near-term market
conditions and incentive programs will impact uptake to some degree, regulations will have the greatest
influence over adoption levels. Should they be enacted, all-electric new construction codes have the ability
to electrify new building stocks while gas appliance bans have the ability to electrify all building types – new
and existing.
By 2045, up to 61,000 additional electrified light-duty vehicles and up to 6,400 additional electrified
medium-duty vehicles (MDV), heavy-duty vehicles (HDV), and buses may be adopted. As with the building
sector, uptake of EVs will be most influenced by regulation. California’s light-duty ZEV sales target will
require 100% of light-duty vehicles sold in the state to be zero-emission vehicles from 2035 onwards, while
other regulations will require zero-emission vehicle adoption by public MDV and HDV fleets and transit
buses. By 2045, EV charging could consume up to 490 additional GWh annually and increase demand at
the time of current peaks by up to 87 MW.
2024 Integrated Resource Plan |Energy Forecast and System Impacts 76 | Page
Figure 6-4: Projected Light-Duty Electric Vehicles – REU Service Territory
Figure 6-5: Projected Medium Duty Electric Vehicles –REU Service Territory
Energy Efficiency and Demand Response
Previously, Itron’s load forecast considered past and current efforts to reduce energy consumption through
energy efficiency and GHG-reducing programs. However, with a continued focus on electrification, Itron
must now account for increased energy consumption from programs. Itron does not currently disaggregate
energy efficiency and building electrification load impacts in the load forecast. Transportation
electrification results from the Dunsky forecast study were directly incorporated into the Itron load
forecast. The energy requirements and peak demand projections reflect the impact of efforts to reduce
energy consumption, system peak, and GHG emissions through the multiple programs described in this
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2024 Integrated Resource Plan |Energy Forecast and System Impacts 77 | Page
section. The load forecast considered a number of energy efficiency and demand reduction measures.
These are further described in Section 4.
6.3 Forecast Results
The peak and energy forecast results are presented in this section. The capacity and energy requirement
forecasts are also carried forward to the required CEC tables in Exhibit 1.1.
Peak and Energy Forecast
Table 6-3 illustrates the energy and peak demand forecast. In previous studies, the forecast showed a
modest decrease in both energy and peak over time due to energy efficiency and conservation efforts.
However, with the inclusion of the electrification forecast, which includes both building and transportation
electrification, the forecast now shows a steady and significant increase though 2045.
During the forecast period (2023 through 2045), energy requirements for all customer classes are projected
to increase from 730,857 MWh in 2023 to 1,101,932 MWh in 2045. For the system, the increase equates
to an overall growth of approximately 50.8 percent over the planning horizon and an AAGR of 1.63 percent.
During the forecast period, peak demand is projected to increase, from a value of 224.3 MW in 2023 to
261.4 MW in 2045, equating to an AAGR of 0.75 percent.
System Load Factor
A load factor is a fundamental metric used to assess the variability of utility load patterns over a specific
period of time. It provides insights into the overall energy utilization efficiency of a utility system.
Specifically, the load factor quantifies the total energy consumed by a utility system relative to the
maximum potential energy requirements that would occur if the energy demand at the peak period
persisted throughout the entire year.
By expressing the energy requirements as a percentage of the theoretical maximum, the load factor offers
a valuable indicator of how consistently and effectively a utility system is utilized. A higher load factor
signifies a more balanced energy usage pattern, where the system operates closer to its maximum capacity
for longer durations, indicating a higher level of efficiency. Conversely, a lower load factor suggests greater
variability in energy demand, with periods of lower consumption relative to peak demand.
Understanding the load factor helps determine the appropriate sizing and capacity requirements for
generation, transmission, and distribution infrastructure, ensuring a reliable and cost-effective supply of
electricity to customers. Due to the increased electrification in the forecast, the load factor increases from
37.2% in 2023 to 48.1% in 2045. The increase is related to increased winter month usage and off-peak
electric vehicle charging. Increased demand from EV charging and building electrification measures results
in higher energy consumption and more effective utilization of the grid’s capacity. While the increased load
factor does mean the electric system will be used more efficiently, it also means that more energy will need
to be delivered.
2024 Integrated Resource Plan |Energy Forecast and System Impacts 78 | Page
Table 6-3: Projected Net Energy Requirements, Peak Demand Forecast, and Load Factor
Net Energy Requirements Peak Demand
Year MWh Percent Change MW Percent Change Load Factor
2022 (Actual) 763,376 - 239.1 - 36.45%
2023 730,857 -4.26% 224.3 -6.19% 37.19%
2024 730,911 0.01% 223.9 -0.17% 37.16%
2025 728,713 -0.30% 223.7 -0.10% 37.18%
2026 729,990 0.18% 223.8 0.03% 37.24%
2027 733,590 0.49% 224.2 0.18% 37.36%
2028 740,293 0.91% 224.8 0.27% 37.49%
2029 744,785 0.61% 225.6 0.34% 37.69%
2030 752,641 1.05% 226.6 0.48% 37.91%
2031 761,774 1.21% 227.9 0.55% 38.16%
2032 772,635 1.43% 229.0 0.49% 38.41%
2033 782,305 1.25% 230.4 0.59% 38.77%
2034 799,534 2.20% 232.3 0.83% 39.29%
2035 825,847 3.29% 235.0 1.19% 40.11%
2036 857,983 3.89% 238.0 1.26% 41.04%
2037 887,123 3.40% 241.1 1.29% 42.01%
2038 921,442 3.87% 244.2 1.31% 43.07%
2039 971,617 5.45% 247.5 1.33% 44.82%
2040 1,007,767 3.72% 250.5 1.22% 45.80%
2041 1,053,926 4.58% 254.1 1.43% 47.35%
2042 1,087,307 3.17% 257.5 1.36% 48.20%
2043 1,090,995 0.34% 258.8 0.50% 48.12%
2044 1,096,450 0.50% 260.1 0.50% 47.99%
2045 1,101,932 0.50% 261.4 0.50% 48.12%
AAGR 2023-2045 1.63% 0.40%
2024 Integrated Resource Plan |Energy Forecast and System Impacts 79 | Page
Changes to Load Forecast
Figure 6-6 illustrates the forecast trends since 2019, with actual load data through from 2015 through 2022.
Compared to the 2018 forecast used for the 2019 IRP, the current 2023 load forecast is four percent lower
though 2030; however, it starts dramatically increasing to 11 percent higher by 2038. The current forecast
also shows continual growth through 2045. Three prominent drivers are leading to the reduction in the
forecast though 2030:
1. Increased behind-the-meter solar adoption
2. Lower overall net migration and economic outlook
3. Assumed efficiency gains of typical household appliances
Figure 6-6: Load Forecast Comparison
The historical data shows a consistent year-over-year decrease in actual load, which aligns with the initial
forecast. However, a pivotal shift occurs post-2030, driven by the widespread adoption of electric building
and transportation technologies. This adoption surpasses any previous efficiency gains or reductions,
leading to an unprecedented surge in load. The peak load forecast mirrors this same trajectory as the
annual energy consumption pattern (Figure 6-7).
The actual load saw a sharp increase in 2020 partly due to above-average temperatures, coupled with the
stay-at-home orders due to COVID-19. It is not conclusive that this is the start of an increasing load trend;
however, REU staff continue to evaluate energy trends and future forecasts.
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2024 Integrated Resource Plan |Energy Forecast and System Impacts 80 | Page
Figure 6-7: Peak Load Forecast Comparison
6.4 Transmission System Assessment
Overview
To accurately capture a zero-carbon scenario within the IRP, the decommissioning of the Plant had to be
considered in the portfolio models. This decision prompted REU to carefully assess the resilience and
capabilities of its transmission and distribution system to solely rely on imported energy for meeting its
load requirements. Additionally, REU needed to evaluate whether the distribution system could effectively
operate without on-system generation support to maintain optimal voltage levels.
To address these critical considerations, REU engaged in consultation with the Sacramento Municipal Utility
District (SMUD). SMUD embarked on modeling two distinct scenarios to thoroughly assess the potential
impacts on REU's transmission and distribution system. These scenarios aimed to uncover potential
contingencies, identify necessary mitigations to maintain reliability, and estimate the associated costs
required to operate REU’s system in the absence of the Plant.
By collaborating with SMUD, REU gained valuable insights into the resilience and reliability of its system
under the proposed zero-carbon scenario. The modeling exercises enabled a comprehensive evaluation of
various factors, including system stability, load balancing, voltage management, and overall operational
feasibility without on-system generation.
Furthermore, the estimated cost of operating without the Plant was also a crucial aspect analyzed in these
scenarios. This evaluation allowed REU to gain a comprehensive understanding of the financial implications
associated with transitioning to a zero-carbon future and to make informed decisions regarding future
investments and resource allocation.
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2024 Integrated Resource Plan |Energy Forecast and System Impacts 81 | Page
System Study results
Study 1
The initial transmission system study aimed to determine whether REU could meet its projected peak
demand without relying on generation from the Plant. REU has a Long-term Parts (LTP) maintenance
contract with minimum run-hour constraints. The current LTP agreement is set to expire in 2032, after
which there will be no obligation for the Plant to continue operating. Therefore, for SMUD's study, they
assumed that the Plant would be taken out of service starting in 2032, and all demand would be met with
imported energy. They utilized the 1-in-10-year load forecast from that year to conduct their assessment,
with the task of identifying and evaluating any resulting system limitations.
In summary, to serve REU’s 2032 forecasted load of 253.73 MW with the Plant out of service, study results
concluded REU’s transmission system experienced low voltage contingencies at multiple substations. The
low voltages fell below current emergency low voltage limits; therefore, REU is not able to serve its year
2032 forecast load reliably and stay above REU’s current emergency low voltage limit.
Study 2
The purpose of this study is to ensure REU would be able to serve its load without on-system generation in
the event the demand exceeds the forecasted future demand. The second transmission system assessment
identified REU transmission system limitations when serving the Utility’s load at the maximum reported
import level of 350 MVA without the Plant. REU relied on imports to meet its maximum reported import
capability without any on-system generation.
In summary, to serve load at REU’s maximum import capability, the following system reinforcements must
be implemented:
Convert the Redding Power Plant generator into synchronous condenser for voltage support.
Loop-in the WAPA’s Keswick-Olinda 230 kV Line into the Redding Power Plant (Redding
Substation) 115 kV substation as new tie lines for voltage support and eliminating identified
thermal overloads.
Re-rate or replace the Airport 230/115 kV Banks with 140 MVA rating or higher to mitigate
identified thermal overloads.
Re-rate or replace the Keswick 230/115 kV Bank #1 with 110 MVA rating or higher to mitigate
identified thermal overload.
Add a 2nd Moore-Redding 115 kV Line for voltage support.
Add a 2nd Texas Spring-Redding 115 kV Line for voltage support.
Loop-in the East Reading-Airport 115 kV Line #1 into the Future South Business Park substation
for voltage support.
Add 35 MVAr of shunt capacitors at Canby 115 kV substation for voltage support.
The facilities with highest thermal violations are for various P6 contingencies are:
2024 Integrated Resource Plan |Energy Forecast and System Impacts 82 | Page
Oregon-Waldon 115 kV Line at 101.8%
Airport 230/115 kV Bank #1 at 108.46%
Airport 230/115 kV Bank #2 at 108.46%
REU was able to use the results from the studies to obtain high-level cost estimates of approximately $46
million for the mitigations listed in study one, and input those into the forecast models for the 2045 zero-
carbon scenario to capture the capital improvement costs that would be associated with that analysis.
6.5 Comparison to CEC Forecast
As part of the IRP analysis, the energy and peak demand forecasts used in this IRP and prepared by Itron
and are compared to the forecasts published by the CEC in its 2022 IEPR Update. While the energy
requirements differ between the two forecasts, they are relatively similar in that growth is relatively flat
through 2035. Furthermore, the CEC and Itron peak demand forecasts are substantially similar, steadily
increasing through 2035. Overall, the forecasts are comparable when looking at the growth rate for energy
demand and peak requirements.
Comparing the CEC’s forecast of energy requirements to the forecast developed by Itron for the IRP
through 2035, the CEC forecast ending (900 GWh) is approximately 9 percent higher than the Itron
forecast in 2035 (825 GWh), as seen in Figure 6-8. On average, the CEC forecast of energy requirements is
about 15 percent higher throughout the forecast period, while the IRP forecast developed with Itron
increases slightly through 2030. However, the average growth rates are virtually the same between the
CEC (0.6 percent) and Itron (0.9 percent) forecasts.
Figure 6-8: Energy Requirements Comparison: REU Forecast vs. CEC Forecast for REU
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2024 Integrated Resource Plan |Energy Forecast and System Impacts 83 | Page
As seen in Figure 6-9, the anticipated peak demand is comparable between the two forecasts. The CEC
reports a higher peak demand for REU, relative to the Itron forecast. In 2035, CEC’s peak demand forecast
for REU is 239.1 MW, while the corresponding figure in Itron’s forecast is 235.0 MW. Similar to the energy
demand, the growth rates are also virtually same between the CEC (0.7 percent) and the Itron (0.4 percent)
forecasts.
Figure 6-9: Peak Demand Comparison: REU Forecast vs. CEC Forecast for REU
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2024 Integrated Resource Plan |Modeling Assumptions, Tools, Methodology 84 | Page
7. Modeling Assumptions, Tools, Methodology
REU engages in a partnership with Ascend
Analytics, a provider of resource portfolio
modeling services. This collaboration allows REU
to make well-informed and strategic decisions
regarding the resources necessary to meet future
customer demands effectively.
Various modeling tools, including load
forecasting models, stochastic simulation
models, reliability models, and economic
dispatch models were employed to analyze and
project energy-related data. Ascend integrates
data inputs provided and leverages them with
nuanced assumptions concerning future energy
markets, constructing a sophisticated, long-term
stochastic modeling framework. This model
serves as a valuable tool enabling the Resource
Team to navigate the intricate landscape of
regulatory compliance seamlessly.
Assumptions played a pivotal role, encompassing
factors such as energy demand growth rates,
natural gas prices, energy policy changes,
technological advancements, and clean energy
mandates, all of which are described in greater
detail below.
This holistic approach ensured that the IRP was
well-informed, enabling the Resources Team to
make informed and forward-looking decisions
regarding its energy portfolio while delivering
reliable, cost-effective, and sustainable energy to
its customers in the future.
2024 Integrated Resource Plan |Modeling Assumptions, Tools, Methodology 85 | Page
7.1 Modeling Tools
Ascend Analytics' PowerSIMM software was used exclusively for all scenario resource modeling and
evaluation.
PowerSIMM Overview
PowerSIMM is a software program used for simulating the performance of an electric power system with
high spatial and temporal granularity. This section provides an overview of the key features and capabilities
of this simulation software. In the IRP analysis, PowerSIMM was used for the following applications:
1. Production cost modeling – simulates power system operations, inclusive of transmission
constraints, on an hourly or sub-hourly timestep for use in decision making for portfolio
management or resource planning
2. Capacity expansion optimization – provides a roadmap of future resource procurements to meet
policy or reliability needs at the lowest cost
3. Resource adequacy analysis – determines how well a portfolio of resources can serve customer load
over a defined period of time on an hourly basis
All applications listed above start with simulations of weather, load, renewables, forced outages, and
market prices. The only exception is in resource adequacy models where prices are not used.
Simulations in PowerSIMM
PowerSIMM simulations start with weather as the fundamental driver of load, renewable generation, and
market prices. Weather simulations consist of daily maximum and minimum temperatures. PowerSIMM
uses historical temperatures to construct future simulations of weather with a time-series model that
includes seasonal inputs.
Renewable items require hourly historical generation data coupled with weather data from a nearby station
to determine the structural relationship between daily min and max temperatures and renewable
generation. PowerSIMM constructs a model for each renewable item using inputs that include daily min
and max temperatures, month, and hour. Future simulations are generated with the model using weather
simulations as an input. Generation output is scaled to meet future expectations for monthly energy
generation and capacity limits.
For load, PowerSIMM creates a structural model using hourly load data, daily min and max temperatures,
hour, day of the week, and month. Load simulations are based on weather simulations and scaled to match
load forecasts for monthly energy and peak demand.
The simulation of market prices follows a similar construct; however, there are more structural variables
observed in both historic and forecast values. There are also more parameters used as inputs. For market
price simulations, PowerSIMM adheres to market expectations (i.e. forward prices and option quotes for
volatility in prices) by scaling simulations such that the average price exactly meets the forward curves for
monthly average prices for natural gas, on peak power, off peak power and carbon. The stochastic price
2024 Integrated Resource Plan |Modeling Assumptions, Tools, Methodology 86 | Page
ranges hold to future expectations of price volatility, correlations across time and commodities, and daily
price shapes.
Additional details on the model simulations can be found in Exhibit 9.1.
Dispatch in PowerSIMM
Simulations of weather, load, renewables, and spot prices roll into the dispatch module. PowerSIMM
models dispatch by optimizing supply resource options in a “dispatch to load” or “dispatch to price” model.
In a dispatch to load model, PowerSIMM calculates dispatch decisions to serve load at the least cost, while
accounting for transmission system congestion. Market purchases are generally, but not always, included
as an option for serving load. The dispatch to price model calculates dispatch decisions to maximize market
revenue from generation.
Dispatch calculations rely on inputs to define the physical and economic characteristics of supply resources,
including thermal resources, energy storage, hydro resources, or demand-side options. Users can also
define transmission lines to represent constraints, such as import or export limits, or line losses. Ancillary
services can be included in dispatch models where PowerSIMM will co-optimize supply resources to serve
load and fulfill ancillary requirements. PowerSIMM ancillary product dispatch can include regulation up,
regulation down, spinning reserves, and non-spinning reserves. PowerSIMM can also perform multiphase
dispatch.
PowerSIMM uses a mix-integer linear programming algorithm in the dispatch calculations. The objective
function in the algorithm is the minimization of cost to supply energy and ancillary requirements. Included
in the total cost are startup costs, variable operations and maintenance (O&M) costs, fixed O&M costs, fuel
costs and fuel delivery costs, electric power purchases and power sales. Power sales are treated as negative
costs.
The decision variables for the dispatch algorithm include the online state of dispatchable generators, the
generation setting for all dispatchable generators, the assignment of ancillary services for units capable of
providing ancillary services, the charge or discharge state of energy storage resources, and the amount of
market purchases. PowerSIMM iterates over a range of possible values to settle on the decision variables
that provide the lowest possible cost within the model constraints.
Dispatch constraints are set for all units in the model such as economic max generation, economic min
generation, ramp rates, must run requirements, minimum generation, etc. There are also constraints
attributable to transmission limits and the requirement to meet load.
Variable generation from wind, solar and geothermal items are not considered dispatchable, but
PowerSIMM may elect to curtail variable resources if system conditions require it. For example, wind
generation may be curtailed due to transmission limits.
2024 Integrated Resource Plan |Modeling Assumptions, Tools, Methodology 87 | Page
7.2 Modeling Assumptions
Load Forecast
The load forecast used in the model is described in Section 6.3. A comprehensive description of the
technical aspects and implementation of the load forecast in the model is described in Exhibit 9.1.
Forward Curves and Market Pricing
Ascend developed the forward curves for this study. The statistical P5, mean, and P95 values are presented
when available to show the general volatility of each curve. Carbon forward curves are represented in
Figure 7-1.
Figure 7-1: Carbon Forward Price
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2024 Integrated Resource Plan |Modeling Assumptions, Tools, Methodology 88 | Page
The import and export energy terms are in reference to REU: imports flow to REU and exports flow to
energy markets. These curves are adjusted for High-Voltage Wheeling Charges (for imports), grid
management charges, transmission losses, and Locational Marginal Pricing based on the CAISO nodes
where BANC transacts with CAISO. The import (Figure 7-2) and export (Figure 7-3) energy prices are based
on the CAISO NP-15 day-ahead price.
Figure 7-2: In-State Energy Imports Forward Price
Figure 7-3: In-State Energy Exports Forward Price
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2024 Integrated Resource Plan |Modeling Assumptions, Tools, Methodology 89 | Page
Out of state energy refers to the Pacific Northwest markets where REU has access to energy though the
COI. These prices are bi-directional and include transmission losses and carbon allowances as required by
CARB (Figure 7-4).
Figure 7-4: Out-of-State Energy Forward Price
Natural gas prices illustrated in Figure 7-5 below are modeled at the PG&E City Gate hub.
Figure 7-5: Natural Gas Forward Price
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2024 Integrated Resource Plan |Modeling Assumptions, Tools, Methodology 90 | Page
The values in Error! Reference source not found. and Error! Reference source not found. represent
annualized averages of the forward prices for power, gas, carbon allowances, and renewable attributes
used in the model. More information about use of forward curve in PowerSimm can be found in Exhibit 9.1.
Table 7-1: Forward Energy Price Assumptions
Year Import Energy Price, $/MWh Export Energy Price, $/MWh Out of State Energy Price, $/MWh
P5 MEAN P95 P5 MEAN P95 P5 MEAN P95
2023 84.00 101.92 123.87 65.74 82.97 104.24 42.86 48.80 55.35
2024 62.90 85.99 112.56 44.51 66.55 92.01 37.71 47.77 58.44
2025 62.13 80.73 102.53 42.85 60.47 81.24 37.14 47.86 59.04
2026 59.22 75.43 96.33 39.09 54.38 74.23 36.23 46.52 59.72
2027 57.06 74.17 94.00 36.10 52.17 70.88 34.78 44.56 55.39
2028 57.77 74.00 97.82 35.75 51.02 73.45 34.96 44.04 56.37
2029 58.90 74.28 92.09 35.72 50.29 67.23 35.64 43.22 53.03
2030 63.76 79.37 97.42 39.41 54.21 71.26 36.31 43.52 52.37
2031 68.58 86.25 107.01 43.30 59.87 79.54 37.52 44.89 53.56
2032 71.09 90.53 114.94 44.69 63.02 86.24 40.06 47.32 56.57
2033 76.44 95.91 119.11 48.76 67.23 89.51 41.78 48.48 57.22
2034 79.89 101.21 126.73 50.97 71.35 95.76 43.47 50.26 59.06
2035 84.24 107.06 132.82 54.28 76.02 100.64 45.63 52.29 60.18
2036 90.60 114.60 141.67 59.36 82.30 108.35 46.90 54.55 63.38
2037 94.95 118.48 146.78 62.60 85.04 112.33 50.05 56.86 65.16
2038 91.95 115.17 143.02 58.71 80.84 107.75 51.88 59.38 68.80
2039 86.61 111.21 139.96 52.62 76.00 103.62 54.48 62.07 71.59
2040 85.21 107.17 132.03 50.23 71.11 94.91 56.79 64.93 74.17
2041 79.10 99.09 119.56 43.09 62.28 82.15 60.85 68.42 77.72
2042 78.11 97.86 118.66 41.14 60.09 80.08 64.17 72.14 82.51
2043 79.46 97.84 116.42 41.29 59.08 77.06 68.19 76.11 86.35
2044 77.82 96.31 116.36 38.86 56.60 76.02 72.13 80.32 90.95
2045 80.30 96.44 114.78 40.10 55.73 73.55 76.73 84.82 95.47
* Average Energy Price data are averages of hourly values
** In-State Purchases assumed from CAISO and include High-Voltage Wheeling Charges for energy imports
+ Out-of-State purchases include the cost of carbon allowances
2024 Integrated Resource Plan |Modeling Assumptions, Tools, Methodology 91 | Page
Table 7-2: Forward Gas, Carbon, and REC Price Assumption
Year Average* Annual Spot Gas Price, $/Dth Average* Annual Carbon Allowance Price,
$/mTCO2e
Average*
PCC1 REC
Price, $/REC
P5 MEAN P95 P5 MEAN P95 MEAN
2023 6.16 7.72 9.84 27.90 29.83 31.74 17.25
2024 4.08 6.17 8.80 27.71 30.61 33.77 17.25
2025 3.90 5.90 8.41 28.05 31.37 35.32 19.55
2026 3.77 5.81 8.29 28.95 32.76 37.17 18.76
2027 3.73 5.79 8.59 30.53 34.87 39.73 16.46
2028 3.71 5.91 8.75 32.78 37.76 43.45 14.96
2029 3.98 6.03 8.87 36.50 41.51 47.66 12.32
2030 4.01 6.15 8.93 40.71 46.22 52.63 11.26
2031 3.93 6.27 9.31 45.85 51.97 58.78 11.46
2032 3.95 6.39 9.67 52.06 58.87 66.79 11.27
2033 4.36 6.52 9.42 54.77 62.99 72.07 11.14
2034 4.43 6.65 9.55 59.13 67.40 77.00 10.65
2035 4.46 6.79 9.67 62.53 72.12 82.99 10.87
2036 4.58 6.92 10.04 67.80 77.17 88.80 11.08
2037 4.52 7.06 10.68 72.66 82.57 94.20 11.30
2038 4.38 7.20 10.82 77.86 88.35 99.31 11.53
2039 4.58 7.35 10.72 82.45 94.54 107.48 11.76
2040 4.65 7.49 10.87 89.94 101.15 113.54 12.00
2041 4.86 7.64 11.08 95.27 108.23 122.84 12.24
2042 5.04 7.79 11.56 101.94 115.81 131.44 12.48
2043 5.46 7.95 11.15 109.08 123.92 140.65 13.16
2044 5.31 8.11 11.45 116.71 132.59 150.49 14.23
2045 5.40 8.27 11.99 124.88 141.87 161.02 15.63
* Average data are averages of monthly values
2024 Integrated Resource Plan |Modeling Assumptions, Tools, Methodology 92 | Page
Potential Resources
Rather than selecting specific projects for evaluation, REU considered potential resources based on their
technology type and generating characteristics. The included resources are found in Table 7-3. Ascend
provided forecasts for the various attributes for each of these technologies. Each technology was allowed
to be selected by the model based on economic performance in energy markets.
Table 7-3: Potential Resources
Resource Assumptions Dispatchable RPS Eligible Carbon-free
Solar Southern California,
Northern California No Yes Yes
Wind
Southern California,
Northern California,
Offshore, New Mexico
No Yes Yes
Renewable Gas Assume Tolling
Agreement Yes Yes Yes*
Carbon
Capture
Assume Tolling
Agreement Yes No* Yes
Hydrogen Assume NG Retrofit Yes Yes* Yes
Storage 4 Hour Battery, 8 Hour
Battery Yes N/A N/A
Geothermal California Yes Yes Yes
Biomass California, Assume PPA Yes Yes Depends
* Renewable or Carbon-free eligibility depends on the fuel source
2024 Integrated Resource Plan |Modeling Assumptions, Tools, Methodology 93 | Page
Table 7-4: Renewable PPA Price Forecast, $/MWh
Technology Solar Wind Geothermal
Location Southern
California
Northern
California
Southern
California
Northern
California
Offshore
Wind New Mexico California
2031 19.56 27.05 46.30 50.51 97.10 39.23 109.38
2032 20.12 27.78 46.65 50.91 97.39 39.50 112.27
2033 20.70 28.53 46.99 51.30 97.78 39.75 115.24
2034 21.29 29.31 47.32 51.69 98.24 40.00 118.29
2035 21.90 30.09 47.65 52.07 98.77 40.25 121.42
2036 22.52 30.90 47.98 52.44 99.36 40.48 124.63
2037 30.20 38.78 53.00 57.51 100.02 45.42 135.35
2038 38.19 46.95 58.20 62.77 110.08 50.54 146.55
2039 46.47 55.44 63.59 68.21 110.91 55.84 158.25
2040 55.08 64.25 69.17 73.84 111.80 61.33 170.47
2041 64.01 73.38 74.94 79.66 112.73 67.02 183.23
2042 73.25 82.85 80.92 85.69 119.03 72.91 196.54
2043 74.90 84.71 81.80 86.63 125.47 73.70 201.74
2044 76.56 86.60 82.69 87.57 132.05 74.50 207.09
2045 78.27 88.52 83.57 88.50 138.79 75.30 212.58
Table 7-5: Renewable Fuel Price Forecast, $/Dth
Year Hydrogen Renewable Natural
Gas
2031 16.70 30.37
2032 16.27 29.59
2033 15.86 28.83
2034 15.45 28.09
2035 15.05 27.36
2036 14.66 26.66
2037 14.28 25.97
2038 13.92 25.30
2039 13.56 24.65
2040 13.21 24.02
2041 12.87 23.40
2042 12.54 22.80
2043 12.21 22.21
2044 11.90 21.64
2045 11.59 21.08
2024 Integrated Resource Plan |Modeling Assumptions, Tools, Methodology 94 | Page
Table 7-6 below shows the ELCC as a percentage of the nameplate capacity based on resource type. The
ELCC assesses the overall capacity and performance of an energy system to ensure that it can reliably
deliver electricity to meet the peak demands of consumers under different conditions and contingencies.
Table 7-6: Resource Effective Load Carrying Capability as % of Nameplate Assumptions
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2031 82% 92% 100% 62% 100% 3% 3% 28% 8% 18%
2032 84% 93% 100% 60% 100% 3% 3% 28% 8% 17%
2033 85% 93% 100% 58% 100% 3% 3% 28% 8% 17%
2034 87% 94% 100% 56% 100% 3% 3% 27% 8% 17%
2035 88% 95% 100% 53% 100% 3% 3% 27% 8% 17%
2036 88% 95% 100% 50% 100% 3% 3% 27% 8% 17%
2037 88% 95% 100% 47% 100% 3% 3% 27% 8% 17%
2038 88% 95% 100% 44% 100% 3% 3% 27% 8% 17%
2039 88% 95% 100% 42% 100% 3% 3% 27% 8% 17%
2040 88% 95% 100% 41% 100% 3% 3% 27% 8% 17%
2041 88% 95% 100% 40% 100% 3% 3% 27% 8% 17%
2042 88% 95% 100% 35% 100% 3% 3% 27% 8% 17%
2043 88% 95% 100% 34% 100% 3% 3% 27% 8% 17%
2044 88% 95% 100% 33% 100% 3% 3% 26% 8% 16%
2045 88% 95% 100% 32% 100% 3% 3% 26% 8% 16%
Table 7-7: Resource Annual Capacity Factor Assumptions
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70% 92% 33% 34% 47% 31% 25% 55% 46% 24%
MW
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6,095 8,016 2,857 2,978 4,142 2,734 2,151 4,818 4,070 2,080
2024 Integrated Resource Plan |Modeling Assumptions, Tools, Methodology 95 | Page
Transmission Assumptions
REU is part of the BANC balancing area therefore, any potential projects in CAISO balancing area would
incur High Voltage Wheeling Charges to import the energy into REU’s system. These charges are significant
and make all CAISO projects prohibitively expensive unless REU chooses to liquidate the energy in CAISO,
unless the power can be scheduled to REU’s system, the power does not have capacity value for REU.
Additionally, projects in CAISO can be prioritized for CAISO load, and REU does not consider projects in
CAISO as having firm capacity. For the purposes of capacity expansion modeling, all potential resources are
assumed to be connected to transmission on which REU has firm rights. For resources that would require
additional transmission, that cost would need to be further evaluated.
Discount Rate
The analysis utilized a 2.0 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.
7.3 Scenario Design
To begin the scenario development process, REU’s Leadership Team was asked to identify the goals and
objectives of its IRP. Subsequently, the team agreed upon the following strategic framework for the IRP
development:
The preferred 2024 IRP scenario should meet or exceed the State’s clean energy mandates while balancing
reliability and affordability.
Contrary to the 2019 IRP, which focused on developing the most cost-effective and reliable resource mix
for meeting the RPS requirements set in SB 350, the 2024 IRP update focuses on meeting reliability and
planning capacity requirements with a sufficiently renewable and carbon-free portfolio. This fundamental
shift in scenario development strategy will allow REU to maintain awareness of impacts resulting from
increasing energy mandates, further enabling its efforts to maintain affordable and reliable rates.
REU's Leadership Team was presented with a range of modeling scenarios proposed by the Resources
Team, and chose the following options:
Low “Base Case” (current portfolio, does not meet mandates)
Mid “Net-Zero Carbon 2045” (meets mandates and targets)
High “100% Zero Carbon 2045” (exceeds mandates and targets)
The major distinction between the Mid and High scenarios is the treatment of carbon. Table 7-8 outlines
these differences.
2024 Integrated Resource Plan |Modeling Assumptions, Tools, Methodology 96 | Page
Table 7-8: IRP Scenario Comparison
Low Scenario Mid Scenario High Scenario
Primary
Objective
Does not Meet
Requirements or Targets
Meets RPS Requirements and
Carbon Targets
Exceeds RPS Requirements and
Carbon Targets
Name Base Case Net-Zero Carbon 2045 100% Zero Carbon
2045
Description
• Reference case,
assumptions from 2019
IRP
• SB 1020 carbon-free targets
(90% by 2035, 95% by 2040,
100% by 2045)
• RPP can still run; use offsets for
carbon emissions
• Carbon-free energy does not
need to be brought to load
• SB 1020 carbon-free targets
(90% by 2035, 95% by 2040,
100% by 2045)
• RPP offline no later than 2045
• Carbon-free energy brought to
load (no offsets)
In addition to the regulatory mandates that must be evaluated, typical resource planning criteria must
also be considered. Sufficient capacity must be secured to cover projected peak annual demand as well as
reserve requirements. PRM is the excess energy above the projected system peak that utilities will plan
to maintain in the event that forecasted demand is higher than anticipated due to extreme weather
conditions, 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 PRM of 15 percent is
used in planning based on the requirement set forth for the region by NERC.
Traditionally, a PRM has been considered sufficient to prevent loss-of-load scenarios. However, with the
significant penetration of intermittent renewable resources in the bulk power grid, loss-of-load events may
occur outside of peak hours. These events are not captured with a planning reserve margin. Using Ascend
modeling tools, REU evaluated the scenarios on hour-by-hour basis to ensure that load can be served
without relying on market imports. The primary metrics for this study is the Loss-of-Load Hours (LOLH),
which gives the average hours in a year that there may be a loss of load. This is described further in Exhibit
9.1.
Each of these scenarios uses the following design constraints and criteria:
Planning Reserve Margin – sufficient peaking capacity must exist in the portfolio to cover 115%
of the annual peak load
Renewable Energy Compliance – the portfolio must generate enough RECs to satisfy the
requirements of SB 100
Carbon-Free Energy – the portfolio must generate enough carbon-free energy to meet the
targets suggested in SB 1020
100% Zero-Carbon – no carbon emitting-resources may be procured for the portfolio to be
100% carbon-free
Reliability – the portfolio must not exceed 2.4 LOLH for any year without using energy imports
2024 Integrated Resource Plan |Modeling Assumptions, Tools, Methodology 97 | Page
Portfolio Cost– each portfolio will be evaluated for portfolio cost based on the evaluation
framework in the Executive Summary.
Low Scenario - Base Case
For the Base Case, there are no constraints and no additional resources added. This scenario represents
REU’s current system.
Mid Scenario – Net-Zero Carbon 2045
The Net-Zero Carbon 2045 scenario is required to meet the PRM, Renewable Energy, Reliability, and
Carbon-Free Energy constraints. The Plant can remain in the portfolio to provide peaking capacity and
generate when economically feasible.
High Scenario – 100% Zero Carbon 2045
The 100% Zero Carbon 2045 scenario is required to meet the PRM, Renewable Energy, Reliability, Carbon-
Free Energy, and 100% Zero-Carbon constraints; in this scenario, the Plant is not permitted to generate
after 2045. The model never naturally selected to retire the Plant economically, so constraints were added,
forcing it to retire. In the model, the Plant is forced offline starting in 2040 rather than 2045 to adequately
capture the impacts of the retirement. Additionally, all carbon-free energy must be brought to load to be
considered carbon-free in the portfolio.
2024 Integrated Resource Plan |Evaluation & Results 98 | Page
8. Evaluation & Results
The evaluation of IRP scenarios and the preferred
plan involved a comprehensive analysis of various
strategic options for the Utility. Multiple
scenarios were considered, each exploring
different resource combinations and strategies to
meet future energy demands and regulatory
requirements. These scenarios were subjected to
rigorous evaluation, considering factors such as
cost-effectiveness, environmental impact,
reliability, and alignment with clean energy goals.
Ultimately, after a thorough assessment, a
preferred plan was identified by the key
stakeholder group. This plan was chosen because
it effectively balanced the need for reliability and
affordability with the imperative of meeting clean
energy targets and regulatory mandates. The
Resources Team agrees with the stakeholder
group’s assessment and finds the Net-Zero
Carbon 2045 plan represents the most viable and
sustainable path forward for the Utility.
2024 Integrated Resource Plan |Evaluation & Results 99 | Page
8.1 Economic Evaluation Framework
The aim of the economic analysis is to meet the goals and objectives of the IRP as describe in the Purpose
and Background, including clean energy mandates, 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 2023-2045
evaluation period. Incremental costs do not include existing fixed costs or common costs such as general
and administrative costs, as these are considered 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.
8.2 Scenario Analysis
Based on the planning criteria, the software planning tools trended toward a standard set of resources to
meet portfolio compliance. REU’s portfolio meets capacity and renewable constraints through 2030 and
there are no carbon constraints enforced in the model until 2035 to coincide with the targets established
in SB 1020. Therefore, no additional resources are selected until 2031 when the Big Horn Wind contract is
due to expire.
For renewable and carbon free energy, solar appears to be the most cost-effective option, although it
provides very little capacity. For capacity, battery storage appears to be the best option despite not
providing energy. These two resources combined provided high value in all scenarios where resources were
needed.
As a result, for incremental renewable, carbon, and capacity requirements, solar and 8-hour battery storage
were chosen for all scenarios starting in 2031. The solar resources selected are a mix of northern California
and southern California projects. The selected resources projects sizes and start year of each are in Table
8-1 below.
In the high scenario, where the goal is 100% Zero Carbon, it becomes imperative to replace the capacity
provided by the existing Plant since it would no longer be permitted to generate. However, the model did
not naturally retire the Plant because doing so would entail significant costs and necessitate extensive
upgrades to REU's distribution system, as elaborated in Section 5.4 of the report.
In response to this challenge, the model pursued a strategy that involved a substantial increase in battery
storage, roughly four times the previous capacity. Nevertheless, even with this augmented storage
capacity, it remained insufficient to ensure the required level of system reliability. Consequently, the model
recommended integrating firm, dispatchable resources to maintain the necessary resource adequacy.
Specifically, the model added 120 MW of thermal capacity to compensate for the retiring Plant. This
capacity was comprised of 25 MW generated from natural gas with carbon capture and sequestration (CCS)
and an additional 95 MW sourced from hydrogen. This approach aimed to address the immediate need for
capacity replacement in a manner consistent with the zero-carbon objectives of the high scenario.
2024 Integrated Resource Plan |Evaluation & Results 100 | Page
Table 8-1: Selected Resources for Scenarios
Mid Scenario High Scenario
Year Solar (NorCal
+ SoCal) MW
Storage (8-hour
Battery) MW
Solar (NorCal +
SoCal) MW
Storage (8-hour
Battery) MW
Natural Gas
CCS MW
Hydrogen
MW
2031 150 25 200 25 - -
2034 50 - - - - -
2037 50 15 25 15 - -
2041 50 15 35 160 25 95
2045 40 - - - - -
Carbon-Free Energy
Senate Bill 1020 (SB 1020) introduces interim carbon-free energy targets beginning in 2035, prior to the
zero-carbon requirement in 2045. These targets are 90 percent carbon-free from 2035-2039 and 95
percent carbon-free from 2040-2044.
The Low Scenario, or Base Case (shown below) does not meet SB 1020 carbon-free targets. After Big Horn
retires in 2031, only WAPA and Whiskeytown will be providing carbon-free energy. As previously
mentioned, solar energy was deemed the best value in the model. The unconstrained model deployed an
extensive amount of solar due to the relatively low cost comparatively. This resulted in an abundance of
renewable and carbon-free energy in both Mid and High scenarios (Figure 8-2 and Figure 8-3).
Figure 8-1: Carbon-Free Energy – Base Case
0%
20%
40%
60%
80%
100%
120%
WAPA Big Horn Whiskeytown SB 1020
2024 Integrated Resource Plan |Evaluation & Results 101 | Page
Figure 8-2: Carbon-Free Energy – Net- Zero Carbon 2045
Figure 8-3: Carbon-Free Energy – 100% Zero Carbon 2045
Renewable Energy Compliance
REU’s current portfolio is positioned to meet RPS compliance through 2030. The figures below indicate the
ability to meet its RPS targets if no additional renewable energy resources are added. In each figure, a year
in which a shortfall in RPS compliance occurs is displayed by the stacked bar chart not meeting the red line
and by the purple line reaching zero.
0%
20%
40%
60%
80%
100%
120%
140%
WAPA Big Horn Whiskeytown Solar SB 1020
0%
20%
40%
60%
80%
100%
120%
140%
WAPA Big Horn Whiskeytown Solar Battery CCS Hydrogen SB 1020
2024 Integrated Resource Plan |Evaluation & Results 102 | Page
As indicated in Figure 8-4 for the Low Scenario, if no additional renewable energy resources are added,
there would be an RPS compliance shortfall starting in 2031. The shortfall would become increasingly
severe; in 2035 and beyond only the small hydro resources would be contributing renewable energy.
Looking at the REC outlook, it is clear that the current portfolio results in a deficiency of RECs.
Figure 8-4: Renewable Energy Compliance – Base Case
Both the Mid Scenario (Figure 8-5) and High Scenario (Figure 8-6) exceed RPS requirements for all years and
will generate more RECs than needed. The addition of solar in the portfolio starting in 2031 to meet RPS
requirements creates a surplus of RECs, and with the focus on carbon-free energy, the renewable energy
requirements are easily met. The excess RECs can be marketed; however, revenues from REC sales are not
included in this analysis. Additionally, the model indicates that solar projects will become increasingly cost-
effective, especially with on-system storage.
-
500,000
1,000,000
1,500,000
2,000,000
2,500,000
3,000,000
0%
20%
40%
60%
80%
100%
120%
WAPA Big Horn Whiskeytown
Index+Optimized Banked Retirement RPS Requirement
Rolling Banked RECs
2024 Integrated Resource Plan |Evaluation & Results 103 | Page
Figure 8-5: Renewable Energy Compliance – Net-Zero Carbon 2045
Figure 8-6: Renewable Energy Compliance – 100% Zero Carbon 2045
-
500,000
1,000,000
1,500,000
2,000,000
2,500,000
3,000,000
0%
20%
40%
60%
80%
100%
120%
WAPA Big Horn Whiskeytown
Solar Index+Optimized Banked Retirement
RPS Requirement Rolling Banked RECs
-
500,000
1,000,000
1,500,000
2,000,000
2,500,000
3,000,000
0%
20%
40%
60%
80%
100%
120%
WAPA Big Horn Whiskeytown
Solar Index+Optimized Banked Retirement
RPS Requirement Rolling Banked RECs
2024 Integrated Resource Plan |Evaluation & Results 104 | Page
Planning Reserve Margin
A Planning Reserve Margin (PRM) represents the excess energy that a utility ensures is on standby in case
the actual demand for electricity goes beyond what was predicted or expected. Traditionally, REU has relied
on a 15 percent PRM to guarantee the reliability of its operations, especially during the hottest summer
days. BANC performs an annual study to ensure that all members meet the required PRM. Each resource
in the model (existing and potential) is given an Effective Load Carrying Capacity (ELCC), which is the
capacity that it is expected to provide during the peak period.
The capacity balance is shown in Figure 8-7 for the Existing System Scenario. This scenario assumes no
additional resources are added through 2045 and reflects the expiration of the Big Horn wind resource in
2031. The figure indicates insufficient capacity to meet the PRM after Big Horn wind is retired. Additionally,
due to increasing load, there will be insufficient capacity to meet future demand staring in 2039.
Figure 8-7: Planning Reserve Margin – Base Case
Both the Mid Scenario (Figure 8-8) and High Scenario (Figure 8-9) meet PRM requirements. The High
Scenario exceeds the planning reserve margin starting in 2041 due to excessive battery capacity required
after the retirement of the RPP in 2040. The excess capacity in the High Scenario is required to maintain
reliability at the hourly level. This is discussed in the following section.
-
50
100
150
200
250
300
350
400
450
500
MW
RPP Whiskeytown WAPA
Big Horn Peak Load Planning Reserve Margin
2024 Integrated Resource Plan |Evaluation & Results 105 | Page
Figure 8-8: Planning Reserve Margin – Net-Zero Carbon 2045
Figure 8-9: Planning Reserve Margin – 100% Zero Carbon 2045
Reliability
With the increase of intermittent renewable resources on the power grid, system reliability has been a
growing concern. Traditionally, a PRM on an annual peak demand was used to determine resource
adequacy. With the tools provided by Ascend, each of the scenarios was modeled to determine the Loss of
Load Hours (LOLH).
-
50
100
150
200
250
300
350
400
450
500
MW
RPP Whiskeytown WAPA
Big Horn Solar Battery
Peak Load Planning Reserve Margin
-
50
100
150
200
250
300
350
400
450
500
MW
RPP Whiskeytown WAPA
Big Horn Solar Battery
CCS Hydrogen Peak Load
Planning Reserve Margin
2024 Integrated Resource Plan |Evaluation & Results 106 | Page
Current Portfolio: REU’s Current Portfolio exceeds LOLH targets until 2038, which is the first
year that the LOLH is greater than 2.4, per the design criterium (Table 8-2).
Table 8-2: LOLH for Current Portfolio
Loss of Load hours
Added
Capacity 0 MW 20 MW 40 MW
2023 0.16 0 0
2025 0.06 0 0
2027 0.01 0 0
2028 0.01 0 0
2029 0.01 0 0
2031 0.04 0 0
2032 0.70 0.03 0
2033 0.16 0 0
2034 0.67 0.05 0
2035 0.96 0.06 0
2036 1.10 0.02 0
2037 2.17 0.15 0
2038 2.99 0.24 0
2039 4.56 0.58 0.02
2040 5.92 0.70 0.01
2041 6.88 1.17 0.02
2042 8.19 1.24 0.05
2043 9.97 1.74 0.06
2044 11.12 2.32 0.19
2045 11.27 2.34 0.23
Mid Scenario (Net-Zero Carbon): Based on the results of these models, there are no concerns
with reliability for the Mid Scenario. The Plant provides reliable capacity support and the battery
storage provides incremental support as load grows. Batteries are added to the system to meet
the PRM constraints, and the LOLH is reduced to zero.
For planning purposes, this study suggests that the 15 percent PRM is sufficient for system reliability and
far exceeds LOLH targets.
High Scenario (100% Zero Carbon): With the absence of the Plant in the 100% Zero Carbon
scenario, the 15 percent reserve margin is not sufficient to meet the LOLH planning targets.
● The capacity expansion model added 200 MW of battery storage to meet planning reserve
margin requirements in 2045. However, with the loss of load analysis, additional firm
capacity was still needed to meet LOLH targets (Table 8-3).
2024 Integrated Resource Plan |Evaluation & Results 107 | Page
Table 8-3: LOLH with RPP Removed and 200 MW Battery Storage in 2045
Added Firm Capacity, MW 0 20 40 60 80 100 120 140
Average LOLH 913.5 913.4 909.2 807.2 509.2 167.1 8.7 0.4
As evidenced above, more than 120 MW of firm capacity is required to meet LOLH targets. Beyond a certain
threshold, in this case, 200 MW, adding more battery storage capacity showed diminishing benefits in
terms of enhancing system reliability. This suggests that while battery storage is a valuable tool for grid
stabilization and energy storage, it should be deployed judiciously and in conjunction with other firm
capacity resources to maximize its effectiveness. This insight underscores the complexity of energy planning
and the importance of balancing various technologies and resources to create a resilient and sustainable
energy portfolio.
Energy Supply Stack and Market Energy
The production cost model takes the selected resource scenarios and subjects them to a rigorous economic
dispatch model. This sophisticated model is instrumental in estimating the energy output expected from
each of the chosen resources within the given scenarios. By doing so, it provides a detailed and quantitative
assessment of the performance and contributions of each resource option.
Figure 8-10: Energy Supply Stack – Base Case
Based on this scenario with no added resources, REU would supply most of energy through market
purchases. Under this scenario, any increases in forward power prices would be a direct increase in power
supply costs.
Both the Net-Zero Carbon 2045 and 100% Zero Carbon 2045 scenarios estimate significant market
purchases, though to a much lesser degree. The model was constrained prevent it from simultaneously
importing energy from out-of-state and make a market sale in-state. Although the majority of purchases
-750,000
-250,000
250,000
750,000
1,250,000
1,750,000
MW
h
RPP WAPA Big Horn
Whiskeytown Out-of-State Imports In-State Imports
In-State Exports Out-of-State Exports Total
2024 Integrated Resource Plan |Evaluation & Results 108 | Page
are from out-of-state and the majority of sales are in-state, these are not coincident. The purchases and
sales are due to solar generation profiles and economic battery optimization.
The WAPA Base Resource, while not fully dispatchable, can be shaped to fit the daily load profile (Section
5.2), which is difficult to capture in the model. In tandem with battery storage and solar generation, the
Base Resource could be used to further reduce market imports. The energy supply stacks for the Net-Zero
Carbon 2045 and 100% Zero Carbon 2045 scenarios are shown in Figure 8-11 and Figure 8-12, respectively.
Figure 8-11: Energy Supply Stack – Net-Zero Carbon 2045
-750,000
-250,000
250,000
750,000
1,250,000
1,750,000
MW
h
RPP WAPA Big Horn Whiskeytown
Solar Battery Out-of-State Imports In-State Imports
In-State Exports Out-of-State Exports Total
2024 Integrated Resource Plan |Evaluation & Results 109 | Page
Figure 8-12: Energy Supply Stack – 100% Zero Carbon 2045
With the dispatchable thermal CCS and hydrogen resources added in the 100% Zero Carbon 2045, the
market imports are reduced even further.
Portfolio Cost
The total portfolio costs are represented as the cumulative present worth cost (CPWC). These values are
broken down by resource and shown in Table 8-4.
Table 8-4: CPWC for Scenarios with Resource Cost
Current Portfolio Net-Zero Carbon 2045 100% Zero Carbon 2045
RPP $14 $13 $15
WAPA $140 $140 $140
Bighorn $102 $102 $102
Whiskeytown $0 $0 $0
Solar $0 $227 $227
8 Hour Battery $0 $200 $477
NG with CCS $0 $0 $83
Hydrogen $0 $0 $96
Market Imports $624 $370 $307
Market Exports -$26 -$205 -$209
Index+ RECs $23 $23 $23
Total, $M $878 $870 $1,263
Levelized CPWC, $/MWh $54.70 $54.25 $79.12
The Net-Zero Carbon 2045 scenario closely aligns with the cost of the Current Portfolio scenario. This cost
parity is achieved due to the solar and storage resources acquired for the Net-Zero Carbon 2045 scenario
-750,000
-250,000
250,000
750,000
1,250,000
1,750,000
MW
h
RPP WAPA Big Horn Whiskeytown
Solar Battery CCS Hydrogen
Out-of-State Imports In-State Imports In-State Exports Out-of-State Exports
Total
2024 Integrated Resource Plan |Evaluation & Results 110 | Page
operating at rates very similar to those prevailing in the market. Essentially, this scenario does not incur
significantly higher expenses compared to participating in the market without these resources.
In stark contrast, the 100% Zero Carbon scenario presents a notably higher cost profile. This is particularly
evident when examining a year-by-year comparison of the levelized CPWC, as illustrated in Figure 8-13. Up
until 2040, the three scenarios exhibit minimal cost differences and appear almost identical. However, after
2040, the 100% Zero Carbon scenario faces the necessity of retiring the Plant and procuring substantial
additional resources.
The need for such significant procurements post-2040 results in a substantial and abrupt cost escalation
for the 100% Zero Carbon scenario. This cost surge is due to the challenge of replacing the Plant's capacity
and securing additional resources to maintain grid reliability while adhering to the stringent zero-carbon
mandate.
Figure 8-13: Levelized Annual CWPC by Scenario, $/MWh
8.3 Preferred Plan Selection
The key stakeholder working group was tasked with identifying the preferred planning scenario to be used
for the development of the 2024 IRP. The primary goal of the scenarios presented was to determine the
preferred method for reaching the State’s carbon reduction requirements and targets. This decision
impacts how REU would account for carbon emissions within its portfolio and ultimately determines
whether there is a need to begin planning to retire the Plant to achieve a 100% zero-carbon portfolio.
After thorough consideration, the key stakeholder group unanimously chose the Mid Scenario, Net-Zero
Carbon 2045, during the conclusive workshop held on March 23, 2023. This scenario was recognized as the
Preferred Plan for the 2024 IRP, with an acknowledgment of the Plant’s crucial role in ensuring reliable and
affordable energy.
$-
$50.00
$100.00
$150.00
$200.00
$250.00
Current Portfolio Net-Zero Carbon Zero Carbon
2024 Integrated Resource Plan |Evaluation & Results 111 | Page
The Preferred Plan recommends procuring large capacities of solar generation to meet renewable and
carbon-free energy targets while using 8-hour battery storage for capacity and reliability. Despite the
intermittent solar resources, the portfolio still achieves high reliability with fewer than 2.4 loss-of-load
hours estimated per year.
In summary, the Preferred Plan has the following characteristics:
Allows the continued dispatch of Redding Power Plant with the use of carbon allowances
To meet SB 1020 target, the Plant is primarily running for peaking load and to provide system
stability when needed
To meet planning criteria, the following resources are added:
● 2031: 180 MW of solar and 25 MW battery storage
● 2037: 55 MW of solar and 15 MW battery storage
● 2041: 80 MW of solar and 15 MW of battery storage
In total, this would add 315 MW of solar generation and 55 MW of 8-hour battery storage to
the portfolio though the planning horizon
While endorsing the Net-Zero Carbon 2045 scenario as a means of maintain affordability and reliability, the
stakeholders strongly encouraged the staff to explore opportunities for reducing fossil-fuel generation and
minimizing carbon emissions without compromising reliability and affordability.
The specific resources selected in each scenario are not the primary focus of this study. The takeaways
from the preferred plan as modeled are that REU should focus on cost-effective intermittent resources to
2024 Integrated Resource Plan |Evaluation & Results 112 | Page
procure renewable and carbon-free energy while leaning on 8-hour battery storage to maintain system
reliability and meet capacity planning requirements.
A diverse portfolio is typically preferred to maintain high reliability by not relying heavily on one type of
generation resource. As REU seeks to fill these resource requirements, staff will continue to evaluate the
portfolio, diversify its resource technology options, and optimize resource selection while adhering to the
carbon-free principles established in the preferred plan.
Preferred Plan Reporting
The preferred plan identifies the desired approach to reach zero-carbon goals by 2045 while meeting
intermediate renewable requirements and carbon-free targets. Using the resources in the preferred plan,
additional models were dispatched to develop a forward outlook that meets the requirements discussed
in this report while considering other operational constraints of the Utility and reporting consistent with
Form CEC 113, “Standardized Reporting Tables for Public Owned Utility IRP Filing.”
The operational constraints relate to obligations under current agreements for minimum operations of REU
generation due to the current LTP and prepay gas agreements. While the requirements will still be met
under the preferred plan with these constraints, REU staff, under direction of the stakeholder group, is
currently evaluating all opportunities to eliminate such operating constraints to further reduce emissions
where possible and optimize the resource portfolio to provide the most cost-effective and reliable service.
The annual energy balance for this study is shown in Table 8-5. The forecasted emissions for this plan are
shown in Figure 8-14.
2024 Integrated Resource Plan |Evaluation & Results 113 | Page
Table 8-5: Load and Resource Balance for Preferred Plan with Operating Constraints
Description Type 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
System Energy Demand, GWh 731 731 729 730 734 740 745 753 762 773 782 800 826 858 887 921 972 1,008 1,054 1,087 1,091 1,096 1,102
Unit 1 NG GT 1 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 - - - - -
Unit 2 NG GT 3 1 2 1 0 0 0 0 0 0 0 0 0 0 0 0 0 0 - - - - -
Unit 3 NG GT 2 1 1 1 0 0 0 0 0 0 0 0 0 0 0 0 0 0 - - - - -
Unit 4 Steam - - - - - - - - - - - - - - - - - - - - - - -
Unit 5 (Simple Cycle) NG SC - - - - - - - - - - - - - - - - - - - - - - -
Unit 6 (Simple Cycle) NG SC - - - - - - - - - - - - - - - - - - - - - - -
1x1 (Combined Cycle 5 or 6 w/ 4) NG CC 147 147 136 146 140 140 138 139 136 146 133 134 136 132 132 137 99 - - - - - -
2x1 (Incremental Combined Cycle) NG CC 140 139 129 142 133 136 132 132 130 141 128 129 133 127 126 131 96 - - - - - -
Unit 9 (Whiskeytown) Hydro 24 24 24 24 24 24 24 24 24 24 24 24 23 23 23 23 23 23 22 22 21 21 20
Total Energy from REU Generation, GWh 317 313 292 313 298 300 295 296 291 311 286 287 293 282 282 292 218 23 22 22 21 21 20
Big Horn Wind 173 173 171 169 168 167 166 164 123 - - - - - - - - - - - - - -
Western Hydro 142 248 243 243 243 243 243 243 243 243 243 243 243 243 243 243 243 243 243 243 243 243 243
Renewable PPAs Solar,
Wind - - 175 175 175 175 175 175 175 175 175 175 - - - - - - - - - - -
Recommended Renewables Solar - - - - - - - - 371 500 500 515 572 615 644 673 716 773 833 878 907 937 982
Total Generation from Energy Contracts , GWh 316 421 589 587 586 585 584 582 912 918 918 933 815 858 887 916 959 1,016 1,076 1,121 1,150 1,180 1,225
Total Contracted & Installed Generation, GWh 632 733 881 900 884 886 879 878 1,203 1,229 1,204 1,220 1,108 1,140 1,168 1,208 1,177 1,039 1,098 1,142 1,172 1,201 1,245
Market Sales, GWh (140) (159) (318) (330) (316) (316) (309) (309) (535) (572) (558) (564) (426) (442) (444) (442) (403) (331) (333) (342) (346) (354) (365)
Market Purchases, GWh 226 200 209 201 208 212 217 226 143 172 194 202 208 229 236 232 279 383 387 397 383 379 366
Net Market Energy, GWh 86 41 (109) (129) (108) (103) (91) (83) (393) (400) (364) (362) (218) (213) (208) (210) (124) 53 53 54 37 25 1
Net System Energy, GWh 718 775 772 772 775 783 788 795 810 829 839 858 890 927 961 998 1,053 1,092 1,151 1,196 1,209 1,226 1,247
2024 Integrated Resource Plan |Evaluation & Results 114 | Page
Figure 8-14: Carbon Emission Outlook for Preferred Plan with Operating Constraints
8.4 Sensitivity Cases
As discussed previously in Section 7.1, 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 Table 8-4 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 in this section are based on the mean results of all runs resulting
from multiple draws on the stochastic input variables and simulated by the model.
In addition to the sensitives inherent in the modeling, REU also performed further sensitivity analyses by
forcing changes in the modeling assumptions. The primary cases studied were as follows:
-
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
180,000
200,000
Carbon Emissions, mTCO2e CARB Allowances Allocated to REU
2024 Integrated Resource Plan |Evaluation & Results 115 | Page
High Load Case – all criteria are the same as the Net-Zero Carbon 2045 scenario, except the
load forecast is increased by 10% starting in 2031
Net-Zero Carbon 2035 – all criteria are the same as the Net-Zero Carbon 2045 scenario, except
the portfolio must reach 100% net-zero carbon 2035 instead of 2045
Net-Zero Carbon Diverse Portfolio – all criteria are the same as the Net-Zero Carbon 2045
scenario, except no new resource technology types can exceed 100 MW
High Load Case
In the High Base Case Scenario, customer demand was assumed increase by 10 percent over the load
forecast used in this IRP (Figure 8-15). Although the load was greater, the model did not identify any unique
resources. Rather, the already selected solar and battery storage resources were simply scaled up to meet
the greater demand, indicating the resource selection is not sensitive to load. The same resources that are
most cost effective at the current load forecast will still apply even with increased load. The energy supply
stack for this scenario is shown in Figure 8-16.
Figure 8-15: High Load Scenario Load Forecast
-
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
1,600,000
1,800,000
An
n
u
a
l
E
n
e
r
g
y
,
M
W
h
IRP Load Forecast High Load Forecast
2024 Integrated Resource Plan |Evaluation & Results 116 | Page
Figure 8-16: Energy Supply Stack – High Load Scenario
Net-Zero Carbon 2035
As shown in Section 7.2, the Net-Zero Carbon 2045 case achieved greater than 100 percent net-zero carbon
starting in 2035. Therefore, this accelerated scenario is identical to the preferred scenario chosen for this
IRP.
Net-Zero Carbon Diverse Portfolio
The portfolios identified in the mid and high scenarios include large solar projects to reach renewable and
carbon-free targets. While resource diversity was a constraint set for the IRP scenario, past experience and
prudent planning suggests there is inherent risk in portfolios that rely on a single type of resource. Despite
solar is being the least cost resource available to meet renewable compliance and carbon-free targets
based on forward cost estimates, a balanced portfolio that includes multiple technologies may reduce risks
associated with over-reliance on a single technology. To consider this, the Net-Zero Carbon Diverse
portfolio sensitivity scenario limits a single technology type to 100 MW of nameplate capacity.
For this scenario, the model selected wind, solar, and geothermal resources. In this scenario, REU would
procure:
• Solar: 100 MW by 2037
• Wind: 100 MW by 2031
• Geothermal: 25 MW by 2043
With the inclusion of geothermal and wind, which both include greater ELCC values than solar, battery
storage was no longer selected. The selected resources are shown in Table 8-6 and Planning Reserve Margin
-500,000
0
500,000
1,000,000
1,500,000
2,000,000
MW
h
RPP WAPA Bighorn Whiskeytown Solar
Battery CCS Hydrogen COB Import NP15 Import
NP15 Export COB Export Index+Total Load Forecast
2024 Integrated Resource Plan |Evaluation & Results 117 | Page
Compliance is shown in Figure 8-17. The Plant and WAPA hydro resources will still serve the majority of
REU’s peaking capacity.
Table 8-6: Selected Resource Additions for Diverse Portfolio Scenario - Nameplate Capacity, MW
Year Solar, MW Wind, MW Geo, MW
2031 50 100 -
2033 25 - -
2037 25 - 5
2039 - - 5
2040 - - 5
2041 - - 5
2043 - - 5
Figure 8-17: Planning Reserve Margin – Net-Zero Carbon Diverse Portfolio
The Diverse Portfolio exceeds RPS compliance requirements and maintains renewable generation greater
than 60 percent of retail sales through 2045 as seen in Figure 8-18. The portfolio meets the carbon targets
for almost every year, illustrated in Figure 8-19. There is one notable shortage in 2045 where only 95
percent carbon-free energy is achieved. The model had selected a small biomass project to fill in this gap.
-
50
100
150
200
250
300
350
400
450
500
MW
RPP Whiskeytown WAPA
Big Horn Solar Wind
Geothermal Peak Load Planning Reserve Margin
2024 Integrated Resource Plan |Evaluation & Results 118 | Page
In practice, however, REU would likely allow one of the other resources, such as solar or wind, to exceed
100 MW and fill in the resource need.
Figure 8-18: Renewable Energy Compliance – Net-Zero Carbon Diverse Portfolio
Figure 8-19: Carbon-Free Energy – Net-Zero Carbon Diverse Portfolio
Limiting the allowable solar to 100 MW of nameplate capacity reduces the excess procurement of
renewable energy apparent in the preferred scenario. The market and resource price forwards indicate
solar is the least cost resource available and provides a positive return. Therefore, limiting this resource
-
500,000
1,000,000
1,500,000
2,000,000
2,500,000
3,000,000
0%
20%
40%
60%
80%
100%
120%
WAPA Big Horn Whiskeytown
Solar Wind Geothermal
Index+Optimized Banked Retirement RPS Requirement
Rolling Banked RECs
0%
20%
40%
60%
80%
100%
120%
WAPA Big Horn Whiskeytown Solar Wind Geothermal SB 1020
2024 Integrated Resource Plan |Evaluation & Results 119 | Page
increases overall portfolio cost compared to the preferred plan by approximately $49 million, or 5.6
percent. A comparison of the CWPC values for IRP scenarios, including this sensitivity case, are shown in
Table 8-7.
Table 8-7: Diverse Portfolio CPWC Comparison to IRP Scenarios
CPWC Levelized CPWC
$ million $/MWh
Current Portfolio $878 $54.70
Net-Zero Carbon $870 $54.25
Zero Carbon $1,263 $79.12
Diverse Portfolio $919 $57.70
When selecting future resources, REU must consider these increased costs while weighing the diversity
risk; however, this sensitivity analysis provides a comprehensive outlook of a more diverse portfolio that
can meet REU’s portfolio requirements.
8.5 Impacts to Redding
The extensive modeling provided by Ascend allows for better insights when making future resource
portfolio decisions. Weighing not just the carbon emissions, but the reliability and affordability of the given
resource options is imperative when meeting customer needs over the planning period.
Future System Modifications
In the scenario favored by the stakeholder group, the modeling predicts a decrease in generation from the
Plant. Despite this reduction, studies indicate that the Plant will still be dispatched to meet peak customer
demands. REU will evaluate the listed mitigations in Phase I of the Transmission System Assessment study
to ensure the Plant can run economically and without voltage support limitations and constraints.
After the adoption of the final 2024 IRP, REU's Transmission & Distribution Assets division aims to create
an Integrated Distribution Plan (IDP). The goal of the IDP is to assess the Preferred Plan outlined in the IRP,
ensuring that the transmission and distribution system can adequately handle the increased load and
identifying any necessary measures for mitigation. Moreover, the IDP will present a comprehensive strategy
and timeline for the implementation of system upgrades identified in the Preferred Plan.
Retail Rate Impacts
Table 8-8 below illustrates a comparison of energy rates ($/MWh) for each scenario in the year 2045 and
the cumulative present worth cost (CPWC) for each scenario. This comparison provides valuable insights
into the relative costs of each scenario over the specified timeframe.
2024 Integrated Resource Plan |Evaluation & Results 120 | Page
Table 8-8: REU Predicted Energy Cost Rates in 2045
Current Portfolio Net-Zero Carbon
2045
100% Zero Carbon
2045
Energy Cost in 2023 ($/kWh) $0.0574 $0.0574 $0.0574
Energy Cost in 2045 ($/kWh) $0.0765 $0.0866 $0.2079
Energy Cost Change ($/kWh) $0.0191 $0.0292 $0.1505
Energy Cost Change Compared to Current Rate* 11% 23% 89%
*REU Current Blended Retail Rate is $0.17/kWh
The energy rate in 2045 provides insights as to how the retail rates would be affected when a scenario is
implemented. However, it is essential to recognize that this does not capture the rate changes that may
occur throughout the planning horizon. In 2045, under the current portfolio, retail rates are expected to
increase by roughly 11 percent. The Net-Zero Carbon 2045 scenario would lead to a more substantial
increase of 23 percent, while the 100% Zero Carbon scenario would result in a significant 89 percent rate
hike.
Power supply costs make up a substantial portion, roughly 34 percent, of REU’s annual budget, shown in
Figure 8-20. Given this significant share, it is imperative to keep power supply costs as low as possible to
maintain affordable rates for REU customers. Striking a balance between achieving environmental goals
and keeping costs in check is a delicate yet critical aspect of ensuring that energy remains accessible and
affordable for the community.
Figure 8-20: REU Fiscal Year 2023 Budget Breakdown
2024 Integrated Resource Plan |Evaluation & Results 121 | Page
8.6 Conclusion of Evaluation and Results
In conclusion, REU’s IRP update strategy resulted in a comprehensive, all-inclusive process to determine
the community's energy future. Through rigorous analysis, stakeholder engagement, and careful
consideration of various scenarios, the Net-Zero Carbon 2045 plan has emerged as the Preferred Plan that
most closely aligns with REU's goals and objectives.
The Preferred Plan, which meets the compliance requirements while balancing reliability and affordability,
is a testament to the Utility's commitment to meeting clean energy targets while ensuring that energy
remains accessible to all residents. It not only outlines a strategic roadmap for resource allocation but also
emphasizes the importance of adaptability and foresight in navigating the dynamic energy landscape.
The impacts of the IRP are far-reaching and affect nearly every area of the Utility. Beyond the technical
aspects of energy planning, they extend to the community, the environment, and long-term sustainability.
The chosen plan supports grid reliability and environmental responsibility while also serving as a tool that
allows REU to preserve the affordability and accessibility of clean energy for Redding's diverse population.
2024 Integrated Resource Plan |Appendix 122 | Page
9. Appendix
APPENDIX
2024 Integrated Resource Plan |Appendix 123 | Page
9.1 Ascend Analytics Resource Planning Modeling
Ascend PowerSIMM was used to run a variety of models for this resource plan. This section describes the
types of models used for the plan.
Production Cost Modeling
The most common application of PowerSIMM in resource planning is as a production cost model, which
shows many detailed aspects of system operations over a future time period. Production cost models can
run with dispatch modeled across a range of simulated future conditions.
Outputs from production cost models include generation costs, fuel consumption, renewable generation,
carbon emissions, and a long list of additional variables used to make investment and operational decisions.
Example uses for PowerSIMM include analyzing options to hedge fuel price risk, evaluating new generation
resource options, or conducting a study to determine renewable additions for RPS (Renewable Portfolio
Standard) mandates.
Production cost model outputs allow users to understand how the system will operate with the assumed
inputs. Figure 9-1 shows hourly dispatch results of a production cost model. Comparing outputs from two
or more production cost models allows a user to understand how changes in resource mix, price forecast,
operational constraints, or other aspects of the system will affect future outcomes.
Figure 9-1: Dispatch outputs over a three-day period plotted against load
Key inputs for production cost models include the simulated system conditions1 and supply resource
operating parameters. The operating parameters of dispatchable generation assets in the portfolio—such
as ramp rates or start-up times for thermal assets, leakage rates and round-trip efficiencies for battery
storage, or spill requirements for hydro—guide dispatch optimization to ensure the model adheres to the
actual physical capabilities and attributes of the resources in the portfolio.
2024 Integrated Resource Plan |Appendix 124 | Page
Capacity Expansion Optimization
A second common application of PowerSIMM in resource planning is for capacity expansion optimization,
which provides the least-cost selection of future resources over time, subject to user-specified constraints.
Such constraints may include resource adequacy requirements, annual energy positions, renewable
portfolio standards, or carbon emission limits. The Automatic Resource Selection (ARS) module contains
the PowerSIMM capacity expansion model. ARS evaluates the performance of a portfolio of existing
resources and candidate resources across a range of future operating conditions to assess their likely
revenues, costs, and other characteristics (e.g., carbon emissions). Based on the user inputs and
constraints, the model determines the optimal resource additions (or retirements) for minimizing total
costs while ensuring the generation portfolio can serve load without violating loss-of-load standards or
emissions constraints. Figure 9-2 illustrates an ARS model that adds candidate resources to a portfolio to
serve load at the lowest cost.
Figure 9-2: ARS Schematic
The portfolio of existing resources and customer load are evaluated with candidate resources across a
range of future conditions to select the optimal portfolio composition under input constraints.
The input data requirements for ARS are generally the same as for production cost modeling except for
additional project cost information (e.g. new candidate resources), accredited capacity (e.g. existing and
new resources), and project specific constraints such as annual build limits for new resources. Users must
also define model constraints to apply in the resource selection process, such as requirements for capacity,
energy, or renewable generation.
Resource Adequacy Analysis
The third main application of PowerSIMM in resource planning is for resource adequacy analysis, which is
used to assess the probability that a system will have adequate generation resources to meet load over a
wide range of conditions. Common metrics for this assessment include loss-of-load probabilities (LOLP),
expected unserved energy (EUE), and capacity deficit (the amount of additional capacity needed to meet
reliability targets), among others. PowerSIMM’s resource adequacy module can also be used to assess the
capacity contribution from specific resources or technology types, which is typically measured with the
2024 Integrated Resource Plan |Appendix 125 | Page
effective load-carrying capability (ELCC) metric. As shown in Figure 9-3, PowerSIMM’s simulation engine
provides simulations of load, renewables, and forced outages used to analyze the ability of a portfolio of
resources to serve load. Resource adequacy models may also include transmission constraints.
Figure 9-3: PowerSimm Flow Chart
The PowerSIMM resource adequacy model considers weather variability as a key driver to renewable and
load simulation. These simulations are coupled with stochastically imposed forced outage in the dispatch
module to measure common metrics, including loss-of-load probabilities, expectations, or hours (LOLP,
LOLE, or LOLH), expected unserved energy (EUE), and capacity deficit (MW Short).
The dispatch algorithm in a resource adequacy model differs from that used in production cost or capacity
expansion models. Resource adequacy models evaluate systems based on how well they can meet system
needs, so the ability to import power is typically eliminated (or significantly restricted). The model
dispatches resources to minimize load shedding without regard to dispatch cost. Market prices also have
no bearing on the dispatch decision in a resource adequacy model. Instead, the important inputs driving
resource adequacy results include forced outage rates, correlation between load and renewables, and
operational constraints. In each simulated hour of a resource adequacy study, the model calculates hourly
load requirements and compares this to the sum of total renewable generation, available thermal capacity
(i.e., not on forced or scheduled outage), and available energy in storage (which is charged with excess
energy when it is available). The model then dispatches thermal and energy storage resources
chronologically (hour-by-hour) to determine how much (if any) load cannot be met in each hour.
Resource adequacy models provide metrics to evaluate the reliability of a system. Additionally, resource
adequacy models provide a useful means of determining the capacity contribution of a specific resource,
known as the effective load carrying capacity (ELCC). The reliability contribution of the ELCC resource is
compared to the reliability contribution from a “perfect” generator to determine the capacity value of the
ELCC resource.
Simulation Details
Weather Simulation
PowerSIMM has the ability to simulate weather across dozens of weather variables. Weather simulations
in PowerSIMM typically include daily maximum and minimum dry bulb temperatures. These temperatures
2024 Integrated Resource Plan |Appendix 126 | Page
are then used as fundamental drivers for the load and for alignment with renewable simulations. The
weather simulation engine requires historical daily maximum and minimum temperatures from weather
stations in proximity to the weather-related resources in the model. PowerSIMM stores historical data for
hundreds of weather stations via automated data pulls from the National Climate Data Center. PowerSIMM
users select weather stations to create weather zones for use in their specific studies.
PowerSIMM creates weather simulations by decomposing historical daily maximum and minimum
temperature data into seasonal and irregular components. The seasonal component represents a smooth
function showing how temperature changes over the year. The irregular component captures fluctuations
around the seasonal component and represents the day-to-day variability in weather, which is the
stochastic part of the weather simulations. The model structure for the irregular component includes 30-
day, 60-day, and 90-day moving averages combined in a linear fashion with autoregression and random
error terms. Annual patterns drive most of the temperature simulations, but the irregular component of
the model allows for deviations from annual and seasonal norms, enabling potential periods of cooler
weather in the summer and warmer days in the winter.
PowerSIMM’s default method for creating temperature simulations does not use a temperature forecast
or include trends in temperature. The result is a set of simulations that resemble historical weather
conditions. However, the models can be configured to account for changes in future temperatures to
reflect predictions of a changing climate.
The following steps outline the process for creating simulations of daily maximum and minimum
temperature:
1. Pull historical weather data – minimum and maximum daily dry bulb temperatures for all selected
weather stations.
2. Use an unobserved components model (UCM) to separate temperatures into a seasonal component
that captures annual patterns, and an irregular component that captures the uncertainty in
temperature data.
3. Apply a transform to the irregular portion of the temperature data to obtain a normally distributed
dataset.
4. Fit a Mixed Data Sampling (MIDAS) regression model to the transformed irregular temperature data.
5. Simulate future timeseries for the irregular component of temperatures using the MIDAS model,
maintaining the correlations between error terms for each weather station pair.
6. Apply an inverse transformation to the irregular temperature data to bring it back to the original
form.
7. Add the seasonal component back into the simulations.
The resulting simulations should reasonably match historical data. Figure 9-4 shows an example of daily
max temperature simulations. The stochastic framework captures variations in weather conditions and
extreme events. PowerSIMM has the capability to modify the statistical parameters of the temperature
2024 Integrated Resource Plan |Appendix 127 | Page
distribution to capture extreme events. Ascend runs validations to ensure that simulated temperatures
align with historical values at the mean level along with the fifth percentile and ninety-fifth percentile.
Figure 9-4: Multiple simulations of daily maximum dry bulb temperature across a single year.
Load Simulation
PowerSIMM creates realistic simulations of load that maintain a strong non-linear relationship between
load and temperature. The load simulations capture the range of uncertainty exhibited in historical load
data. After fitting historical load data to a time series model, PowerSIMM scales the load simulations to
match future expectations for energy consumption, peak demand growth, and daily load shapes.
Simulations of load rely on past data to create accurate representation of the utility load that matches
historical statistics in the near term while matching the load forecast inputs through the simulation time
frame. By scaling load simulations to forecast values, PowerSIMM produces accurate simulations of load
that provide a realistic range of future load values around the expected mean. Figure 9-5 shows a time
series of multiple load simulations while Figure 9-6 shows the load – temperature relationship maintained
in the load simulations.
Load simulations are conducted by using the following steps:
2024 Integrated Resource Plan |Appendix 128 | Page
1. Gather historical load data, historic temperature data, and temperature simulations.
2. Perform a log transformation on the historical load data to improve the model fit.
3. Decompose the transformed load data with an unobserved components model into an annual shape,
a trend, a cycle, and an irregular component. The decomposed parts will be fit to separate models.
4. Fit a two-component linear regression model to the historical data to determine the break point in
the historical load data. The break point is the temperature associated with the lowest load levels
where an increase or decrease in temperature results in higher load.
5. The cyclical component of the load data decomposed in the UCM model, found in step 3, is fit to a
time series model to determine the effects on load due to the day or week, holidays, temperature
(relative to the breakpoint temperature), hour of day, and autoregressive terms. The results provide
average hourly load over a variety of conditions.
6. In the load simulations, the output from step 5 provides a method to simulate the cyclical portion of
load as a function of the variables estimated in step 5. The cyclical portion is recombined with the
annual load trend and shape components determined in step 3 and with a random irregular load
component to provide the stochastic nature of the load simulations.
7. An inverse transform applied to the simulations reverses the log transform from step 2.
8. The loads are scaled to match the forecasts input by the user for energy and peak demand.
Figure 9-5: Multiple simulations of load over a single week.
2024 Integrated Resource Plan |Appendix 129 | Page
Figure 9-6: Load vs Temperature
Wind and Solar Simulation
PowerSIMM generates simulations of renewables with time series models fit to hourly historical data.
Accurate wind and solar generation simulations are an essential part of power system modeling for
determining cost of service, loss of load risks, resource valuation, and many other modeling outputs used
in utility decision making.
Wind and solar simulation models use a structure that assumes generation is a function of maximum and
minimum temperature inputs from the weather simulations. The model also allows structural variables,
like time of day and month of year, to affect generation. For example, if generation is typically highest on
afternoons in spring, even apart from the influence of temperature, then the model will be able to capture
that. Finally, the model includes autoregressive terms to capture the influence of generation in the previous
hour to the current hour’s generation. In addition to daily temperatures, hour, and month, solar simulations
include the solar irradiance calculated at the location of the solar resource. Solar irradiance is a function of
the time of day, day of the year, and the longitude and latitude of a project.
PowerSIMM scales monthly wind and solar simulations to match monthly forecasts.
The general simulation process for wind and solar items uses the following steps:
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1. Pull historical hourly wind or solar generation and daily minimum and maximum temperature data.
2. Transform the historical generation data by fitting the data to a Beta distribution and mapping to a
Normal distribution, resulting in a well-behaved dataset.
3. Fit the transformed data to the time series model.
4. Simulate future wind or solar generation with the temperature simulations used as inputs to the
simulations.
5. Perform an inverse transformation on the simulated data to bring it back to the original form of
generation.
6. Scale the simulated generation time series so that it matches forecasts on average. For example, the
average of all simulations will match the forecast values for energy and expected peak generation.
Simulated values will also be kept at or below the input nameplate capacity.
7. For sub-hourly studies, expand hourly simulations with interpolation and added noise at the sub-
hourly level.
Realistic simulations of variable renewable energy generation lead to accurate analysis of the value of
renewable assets and the effect of renewables in production cost studies, resource adequacy, or capacity
expansion. Figure 9-7 and Figure 9-8 provide examples of solar and wind simulations over a week.
Figure 9-7: Multiple simulations of solar generation over a single week.
2024 Integrated Resource Plan |Appendix 131 | Page
Figure 9-8: Multiple simulations of wind generation over a single week.
Small Hydro Simulation
PowerSIMM models small hydro resources as run-of-the-river hydro. Dispatchable hydro resources are set
up as a hydro project in PowerSIMM. Like other variable renewable resources in PowerSIMM, hydro
simulations use a time series model fit to historical hourly generation data. The outcome is a set of
simulations that capture the full range of potential hydro generation to provide accurate results for utility
decision making.
While the structural details of the hydro simulation model differ from the wind and solar simulation models,
the general inputs are similar. Hydro simulation models also assume generation is a function of maximum
and minimum temperature inputs from the weather simulations. Like wind and solar simulations, the
model used for hydro simulations also allows structural variables, like time of day and month of year, to
affect the generation. The hydro model also includes autocorrelation terms.
Hydro simulations are scaled to match future expectations for monthly generation and capacity.
PowerSIMM ensures that average monthly hydro simulations match the hydro forecast values. Figure 9-9
shows hydro simulations over a one-week period.
The general simulation process for hydro items uses the following steps:
2024 Integrated Resource Plan |Appendix 132 | Page
1. Pull historical hourly hydro generation and daily minimum and maximum temperature data.
2. Transform the historical generation data by fitting the data to a Beta distribution and mapping the
Beta CDF (Cumulative Distribution Function) to a Normal CDF, resulting in a well-behaved dataset.
3. Fit the transformed data to the time series model.
4. Simulate future hydro generation with the temperature simulations used as inputs for hydro
generation.
5. Perform an inverse transformation on the simulated data to bring it back to the original form of
generation.
6. Scale the simulated generation time series so that it matches forecasts on average. For example, if
the model uses 100 simulations, the average of all simulations will match the forecast values for
energy and expected peak generation. Simulated values will also be kept at or below the input
nameplate capacity.
7. For sub-hourly studies, expand hourly simulations with interpolation and added noise at the sub-
hourly level.
Figure 9-9: Multiple simulations of hydro generation over a single week.
Forward Price Simulation
PowerSIMM simulates forward curves using a stochastic model with parameters derived from recent
historical transaction dates and defined user inputs (as applicable). PowerSIMM constructs a system of
equations for forward contracts that includes the stochastic component of the forward price, as well as the
correlation with neighboring contract months, and other commodities. This framework produces price
simulations that are realistic, benchmark well to historical data, and produce a payoff of cash flows
consistent with market option quotes at multiple strike prices.
2024 Integrated Resource Plan |Appendix 133 | Page
Forward contract prices are modeled with an autoregression, or AR, model with volatilities and correlations
maintained in accordance with historical data or with inputs provided in the forward price constraints.
PowerSIMM uses an AR lag of one while limiting the coefficient to a value of less than 1. An AR coefficient
less than 1 is equivalent to a Geometric Brownian Motion (GBM) model with mean reversion. Thus, the
forward prices tend to do a random walk with a constant pull back to the monthly mean values.
Forward simulations are conducted by using the following steps:
1. Calculate the log prices of all historical data.
2. Calculate a target covariance matrix between contracts using historical log price data.
3. Apply any user-input correlation constraints to calculated target covariance matrix (internally stored
as a correlation matrix and vector of variances). Correlation constraints in the model force the
forward simulations to maintain expected correlations between forward prices for gas, on/off peak
power, coal, carbon, and other commodity prices in the model.
4. Fit a time series model with autoregression and moving average terms to the historical log price data
(from step 1) while respecting any autoregression or moving average restrictions input by the user.
PowerSIMM uses separate models for each commodity (natural gas, on-peak power, off-peak power,
coal, etc.).
5. Set the target covariance matrix as the initial residual covariance matrix.
6. Iterate the following steps to construct the forward price simulations while meeting the correlation
inputs:
a) Simulate future forward contract log prices using the autoregressive terms, moving average, and
intercept parameters fit above and the current residual covariance matrix. The error terms in these
simulations are drawn from a normal distribution, with correlations and variances specified by the
residual covariance matrix.
b) Calculate correlation and variance of simulated price paths.
c) Adjust current residual covariance matrix based on the difference between:
i) Simulated correlation and target correlation
ii) Simulated variances and target variances
d) Adjust residual covariance matrix to ensure it is positive semi-definite.
7. Calculate volatility of the simulated price paths.
8. Adjust daily log returns of simulated price paths to enforce any volatility constraints.
9. Scale the average of simulated prices to input forecast if indicated by user (those are usually
forecasted based on market fundamentals). The mean across all simulations equals to the input
forecast.
.
2024 Integrated Resource Plan |Appendix 134 | Page
Figure 9-10: Multiple simulations of forward prices.
Spot Price Simulation
PowerSIMM simulates spot prices beginning with the market expectations of monthly blocks of energy
represented as the average forward or forecast price over the monthly block. Following the forward price
simulations, spot prices are simulated with a hybrid approach that captures the uncertainty in price risk in
power markets and trading hubs, including variability in weather, load, renewable output, congestion risk,
and LMPs (Locational Marginal Prices), while maintaining consistency with forward price simulations. A
sample of hourly spot price simulations are shown in Figure 9-11 over the course of a week.
Figure 9-11: Simulations for spot prices over a single week
Basis Price Simulation
Basis price items in PowerSIMM allow for models to contain multiple pricing nodes. The main market
configuration in PowerSIMM must select a primary forward price and spot price for use in the price
2024 Integrated Resource Plan |Appendix 135 | Page
simulations. PowerSIMM derives basis prices as “structural” (regression-based model) or “basic” (random
noise) items from the main spot price configured in the model. Basis prices are an important feature of
PowerSIMM because they allow for market interactions and simulate locational marginal prices of different
nodes.
Scalars applied in the Basis model allow users to set up expected deviations in prices between the basis
price (node) and the reference spot price (hub). Users may set up scalars as a constant value across all
hours or as random variables where the parameters are a function of time. The Basis module can also be
used to produce sub-hourly simulations and ancillary services prices.
Basic model simulations can be broken down into the following steps:
1. Generate a time series of values, drawn from a user defined distribution (such as normal distribution,
lognormal, triangular, etc.) with autoregressive and moving average terms included based on the
input configuration for that basis.
2. Scale resulting values using input scalers, most often fundamental basis projections
3. Add values from step 2 to reference price to produce final basis price.
4. Output simulated prices to the database.
Structural model simulations can be broken down into the following steps:
1. Gather historical basis price data and simulated and historical main market gas and power price.
2. Transform the historical price data (typically using a power transformation, though log, beta and
arcsinh transformations are also available).
3. Fit a daily model to the historical basis price data.
4. For hourly electric basis prices, fit an hourly model to the residuals of the daily basis price model.
5. Simulate daily basis prices and hourly price residuals and sum the hourly residuals to the daily prices
to obtain simulated hourly basis prices.
6. Scale prices to the forward curve, which represents the price forecast for the basis node. Recall that
scaling a price to a forward curve means the average monthly prices will match the forward prices,
while some simulations will be higher, and some will be lower.
7. Summarize to monthly peak period values.
8. Output simulated values to the database.
2024 Integrated Resource Plan |Appendix 136 | Page
9.2 Study Summaries
Transmission System Assessment (SMUD)
Executive Summary – Phase 1 Study
This REU Transmission System Assessment (TSA) evaluated and identified the system limitations in the REU
system to serve the 1-in-10 year load forecast, year 2032 load with the Redding Power Plant out of service.
Steady State Analysis
Thermal Violations:
For P0, P1, P2, P3, P4, P5 and P7 contingencies - There are no thermal violations.
For P6 contingencies (before allowable system adjustments) - There are multiple thermal
violations. Per TPL-001-4, system adjustments are allowed between consecutive outages in a
P6 contingency.
System Voltage Limits Exceedances:
For P0, P5 and P7 contingencies - There are no voltage violations.
For P1 contingencies – The East Redding-Canby 115 kV line outage caused two low bus voltage
exceedances at the Canby 115 kV bus (0.9412 per unit) and Sulphur Creek 115 kV bus (0.9448
per unit).
For P2 contingencies – The East Redding 115 kV bus fault (or equivalent breaker fault) caused
the same low bus voltage exceedances at the Canby 115 kV bus (0.9420 per unit) and Sulphur
Creek 115 kV bus (0.9458 per unit).
For P3 contingencies (before allowable system adjustments) – The same low bus voltage
exceedances at the Canby 115 kV bus (0.9412 per unit) and Sulphur Creek 115 kV bus (0.9449
per unit). Per TPL-001-4, system adjustments are allowed between consecutive outages in a P3
contingency.
For P4 contingencies – The same low bus voltage exceedances at the Canby 115 kV bus (0.9409
per unit) and Sulphur Creek 115 kV bus (0.9447 per unit).
For P6 contingencies (before allowable system adjustments) – There are multiple low bus
voltage exceedances. Per TPL-001-4, system adjustments are allowed between consecutive
outages in a P6 contingency.
The identified emergency voltage exceedances were based on the REU’s current voltage limit of 0.948 per
unit post contingencies. If REU lower the emergency low voltage limit to 0.923 per unit according to REU
comments received during reviewing the draft TSA report, the emergency system voltage exceedances
identified for P1-P4 contingencies would be mitigated. However, even with the revised emergency low
voltage limit of 0.923 per unit, the P6 contingencies would still cause low voltage exceedance problem. The
allowable system adjustment between consecutive outages may mitigate the emergency low voltage
exceedances.
2024 Integrated Resource Plan |Appendix 137 | Page
Voltage Deviation Exceedances:
For P1 contingencies - There are no voltage deviation violations. P2-P7 contingencies are not
applicable.
Voltage Stability Analysis
REU’s total system load was increased by 5% for P1 contingencies and 2.5% for P7 contingencies. All of
REU’s P1 contingencies’ cases were solved with the 5% increased load. In addition, all of REU’s applicable
P7 contingency cases were solved with the 2.5% increased load. Results indicated that REU’s transmission
system still maintains a reasonable reactive margin with the Redding Power Plant out of service to serve
year 2032 forecast load.
Q-V margin analyses were conducted based on the worst P1 and P7 contingencies for the 5% and 2.5%
increased load base cases. With the worst P1, East Redding-Canby 115 kV line outage, results concluded
that there are 85 MVAr of reactive margin at the Canby 115 kV bus and 96 MVAr of reactive margin at the
Sulphur Creek 115 kV bus. With the worst P7, Moore-Airport and Redding Power-Moore 115 kV line
outage, results concluded that there are 130 MVAr of reactive margin at the Redding Power Plant 115 kV
bus.
Dynamic Stability Analysis
Dynamic Stability analyses were performed for P1 and P7 contingencies and stability plots indicated that
REU’s transmission system remains stable and positively damped.
System Study Summary
In summary, to serve REU’s year 2032 forecast load of 253.73 MW with the Redding Power Plant out of
service, study results concluded that the REU’s transmission system experienced low voltage exceedance
problems at the Canby 115 kV bus and the Sulphur Creek 115 kV bus following various contingencies based
on the REU’s current emergency low voltage limit of 0.948 per unit. Therefore, REU is not able to serve its
year 2032 forecast load reliably and meet the REU current emergency low voltage limit.
If REU’s emergency low voltage limit would be lowered to 0.923 per unit, the identified low voltage
exceedances caused by P1-P4 contingencies would be mitigated, and REU would be able to serve its year
2032 forecast load. It is assumed that allowable system adjustment between consecutive outages may
mitigate the emergency low voltage exceedances caused by P6 contingencies.
Mitigations are not being evaluated in this study and it is recommended that REU explores possible
mitigation options. Mitigation options may include various combinations of, but not limited to, the
following:
Install reactive support device (capacitors);
Convert the existing Redding Power Plant into synchronous condenser;
Install solar and/or battery systems; and
Possibly increase import capability (add additional transmission ties).
2024 Integrated Resource Plan |Appendix 138 | Page
Executive Summary – Phase 2 Study
The Redding Electric Utility (REU) Transmission System Assessment (TSA)1 Phase II evaluated, identified
system limitations, and provided possible mitigations. The proposed mitigations will enable REU’s
transmission system to have approximately 350 MVA import capability to serve the future year load of
341.53 MW (388.97 includes Shasta and Knauf load) without violations following Categories P1-P7
contingencies of the NERC Reliability Standard TPL-001-4.
REU system load was uninformly increased until an import level of 350 MVA was reached. In addition to
the load increased, the REU’s new Future South Business Park 115 kV substation was modeled via looping
in the East Redding-Airport 115 kV Line #2. Due to to the high level of import and not allowing load
dropping for P3 or P6 outages, REU’s system reinforcements are necessary to mitigate criteria violations
specified within the NERC Reliability Standard TPL-001-4.
System Reinforcements
The proposed system reinforcements or mitigations are as follows based on the results of this study:
1. Convert the Redding Power Plant generator into synchronous condenser for voltage support.
2. Loop-in the WAPA’s Keswick-Olinda 230 kV Line into the Redding Power Plant (Redding
Substation) 115 kV substation as new tie lines for voltage support and eliminating identified
thermal overloads.
3. Re-rate or replace the Airport 230/115 kV Banks with 140 MVA rating or higher to mitigate
identified thermal overloads.
4. Re-rate or replace the Keswick 230/115 kV Bank #1 with 110 MVA rating or higher to mitigate
identified thermal overload.
5. Add a 2nd Moore-Redding 115 kV Line for voltage support.
6. Add a 2nd Texas Spring-Redding 115 kV Line for voltage support.
7. Loop-in the East Reading-Airport 115 kV Line #1 into the Future South Business Park substation
for voltage support.
8. Add 35 MVAr of shunt capacitors at Canby 115 kV substation for voltage support.
With reinforcements of 1-2, there are several thermal violations and low voltage violations. The facilities
with highest thermal violations are for various P6 contingencies are:
• Oregon-Waltond 115 kV Line at 101.8%
• Airport 230/115 kV Bank #1 at 108.46%
• Aiport 230/115 kV Bank #2 at 108.46%
2024 Integrated Resource Plan |Appendix 139 | Page
• Keswick 230/115 kV Bank #1 at 109.66%.
For emergency low voltage violations, there many bus voltages lower than the emergency low voltage limit
of 0.923 per unit. Hence, system reinforcements 3-8 are needed also to mitigate emergency thermal
violations and emergency low voltage violations identified above. are as followings based on the TSA:
System Enforcment Steady State Analysis Results
Thermal Violations:
• For P0, P1, P2, P3, P4, P5, P6 and P7 contingencies – There are no thermal violations.
System Voltage Limits Exceedances:
• For P0 - There is no voltage violation.
• For P1-P7 contingencies – There are no emergency low bus voltage exceedances.
Voltage Deviation Exceedances:
• For P1 contingencies - There are no voltage deviation violations.
Voltage Stability Analysis
REU’s total system load of 388.97 MW (341.53 MW without Shasta Lake and Knauf) was increased by 5%
for P1 contingencies and 2.5% for P7 contingencies. All of REU’s P1 contingencies’ cases were solved with
the 5% increased load. In addition, all of REU’s applicable P7 contingencies’cases were solved with the
2.5% increased load. The TSA results indicated that REU’s transmission system has adequate reactive
margin. Table 9-1 below summarizes the system reactive power available due to applicable worst P1 and
P7 contingencies.
Q-V margin analyses were conducted based on the worst P1 and P7 contingencies for the 5% and 2.5%
increased load base cases. With the worst P1, East Redding-Canby 115 kV line outage, results concluded
that there are 40 MVAr of reactive margin at the Canby 115 kV bus and 45 MVAr of reactive margin at the
Sulphur Creek 115 kV bus. With the worst P7, Airport-FSBP 115 kV double line outages, results concluded
that there are 70 MVAr of reactive margin at Canby 115 kV bus, 73 MVAr at FSBP 115 kV bus, and 83 MVAr
of reactive margin at Sulphur Creek 115 kV bus.
Table 9-1: Summary of Reactive Margin
2024 Integrated Resource Plan |Appendix 140 | Page
Dynamic Stability Analysis
Dynamic Stability analyses were performed for P1 and P7 contingencies and stability plots indicated that
REU’s transmission system remains stable and positively damped.
Summary
With the above proposed system reinforcements, the TSA study results indicated no thermal violations for
REU to serve the future load future year load of 341.53 MW (388.97 includes Shasta and Knauf load) with
import level of 350 MVA. REU’s transmission bus voltages are greater than the emergency low voltage limit
of 0.923 per unit following P1-P7 contingencies. In addition, no voltage stability and dynamic stability
issues.
Customer Survey (GreatBlue)
Executive Summary
GreatBlue Research was commissioned by the City of Redding Electric Utility (hereinafter “Redding” or
"REU") to conduct market research to understand their customers’ perceptions of electric resource
planning for the future.
The primary goals for this research study were to assess customer sentiments and interest in sustainability
and meeting or exceeding clean energy targets and mandates; electric vehicle technology, incentives,
customer programs, and charging infrastructure’ building electrification measures, electrification benefits,
and customer programs; and various types of rate structures.
In order to service these research goals, GreatBlue employed telephone and digital survey methodologies
from February 7, 2022, through March 28, 2022, to capture the opinions of residential customers and
commercial customers of REU. In total, GreatBlue Research received a total of 641 completed residential
customer surveys via digital methodology and 102 completed commercial customer surveys (62 via phone
and 40 via digital).
The outcome of this research will enable REU to better understand customer sentiments and interest in
various electricity resources, prioritize the potential implementation for those identified resources, and
enhance strategic planning to incorporate those resources into REU’s Integrated Resource Plans and future
customer program offerings.
The REU Ratepayer Survey on electric resource planning leveraged a quantitative research methodology to
address the following areas of investigation:
• Level of concern regarding climate change • Interest and participation in REU programs
• Behavioral changes made to reduce energy
consumption and likelihood of future behavior
modification
• Interest in, and current usage of, electric
vehicles and charging infrastructure
2024 Integrated Resource Plan |Appendix 141 | Page
• Awareness, interest, and implementation of
building electrification measures
• Interest in various types of utility rate
structures and demand response methods
• Preferred methods of communication with REU • Demographic and firmographic profiles of
respondents
Key findings from the study:
Overall, residential customers, particularly low-income (defined as earning $75,000 or less), have a great
concern for climate change within the next five years and would consider paying more to exceed goals
(100% clean energy). Conversely, despite commercial customers being concerned about climate change
over the next ten years, most care about affordability and do not want to pay more to exceed goals.
2024 Integrated Resource Plan |Appendix 142 | Page
Electrification Forecast (Dunsky)
Executive Summary
Introduction
This report presents the findings of the Redding Electric Utility (REU) Building and Transportation
Electrification Study, which forecasts uptake of key electrified building and transportation technologies in
Redding, California over the 2023-2045 study period.
This study provides inputs to the REU 2024-2045 Integrated Resource Plan (IRP). Specifically, the research
objectives were to:
Forecast service territory-wide adoption of electrified technologies to support REU’s long-term
planning efforts
Consider service territory-wide load impacts of Electric Vehicle (EV) adoption, including annual
energy and demand and hourly impacts for a select number of peak and off-peak days
Provide results that will integrate with other REU forecasts for the purpose of resource and
distribution planning
In addition to these objectives, this work can support future program planning initiatives. High potential
program opportunities are highlighted throughout.
Methodology
Market data
The study scope did not include any primary data collection. Market inputs, including baseline building and
equipment characteristics, are sourced from existing datasets. The building and vehicle market
characterization leveraged the County Metric Database owned and managed by Tierra Resource Consulting
(Tierra). The County Metric database is a compilation of publicly available data from Federal, State, and
County data sets. Wherever possible, Redding-specific market data is used in the study. When Redding-
specific data is not available, county, state, or federal-level data is scaled to Redding’s population.
Building Electrification Projections
Building electrification is assessed using Dunsky’s Heating Electrification Adoption (HEAT) model. Building
electrification is modeled under three scenarios: Low, Mid, and High. Key factors expected to influence
adoption are varied among the scenarios: natural gas rates, equipment cost declines, equipment
performance improvements, incentive programs, and building regulations.
Transportation Electrification Projections
Transportation electrification is assessed using Dunsky’s Electric Vehicle Adoption (EVA) model.
Transportation electrification is modeled under two scenarios: Low and High. A third scenario assesses the
grid impacts of the High scenario should a managed charging program be established as part of the Grid
Impacts of Transportation Electrification component of the study. Key factors expected to influence
adoption are varied among the scenarios: fuel (gas and diesel) prices, electric vehicle cost declines, vehicle
charging installations, vehicle model availability, and regulation.
2024 Integrated Resource Plan |Appendix 143 | Page
Grid Impacts of Transportation Electrification Projections
Annual electricity consumption (GWh) is modeled using the transportation electrification projections
developed as part of the study, and using assumptions around vehicle-specific typical driving distances,
vehicle efficiencies, and local climate. Annual peak demand (MW) is defined as the incremental demand
from EVs at the time of the forecasted system peak. Annual peak demand is calculated using hourly load
impacts for each type of EV modeled in this study, and for each type of charging (e.g. home, workplace,
commercial fleet, public level 2, and public DCFC). In addition to annual energy and demand impacts from
EVs, 24-hour system-wide EV load impacts are assessed for four representative days under each scenario:
peak summer day, off-peak summer day, peak winter day, and off-peak winter day. All grid impacts are
modeled at the service territory-wide level.
Results
By 2045, up to 24,700 additional units of space heating heat pumps, 11,400 additional units of electrified
water heating equipment, and 37,000 additional units of electrified cooking equipment could be seen in
Redding. Although variations in near-term market conditions and incentive programs will impact uptake to
some degree, regulations will have the greatest influence over adoption levels. Should they be enacted, all-
electric new construction codes have the ability to electrify new building stocks while gas appliance bans
have the ability to electrify all building types – new and existing.
By 2045, up to 61,000 additional electrified light-duty vehicles and up to 6,400 additional electrified
medium-duty vehicles, heavy-duty vehicles, and buses may be adopted. As with the building sector, uptake
of EVs will be most influenced by regulation. California’s light-duty ZEV sales target will require 100% of
light-duty vehicles sold in the state to be zero-emission vehicles from 2035 onwards, while other
regulations will require zero-emission vehicle adoption by public MDV and HDV fleets and transit buses. By
2045, EV charging could consume up to 490 additional GWh annually and increase demand at the time of
current peaks by up to 87 MW.
Conclusions
Across all end uses, uptake of electrified technologies will present new revenue streams for REU by
increasing energy sales. Although regulation alone could drive considerable adoption of these technologies
over the study period, the utility can also support adoption – especially in early years – through
programming efforts. The utility also has an important role to play in managing emerging loads from
electrification, which have the potential to drive considerable increases in peak capacity requirements.
Demand management programs targeting thermostats, water heaters, and EV smart chargers can limit
increased peak capacity needs and maximize benefits to the utility and its customers.
In the future, more granular geographic assessment of technology uptake and location-specific load
impacts will provide insight into how the utility can best prepare for electrification.
2024 Integrated Resource Plan |Appendix 144 | Page
9.3 Demand-Side Management IRP (DSM-IRP)
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, cost-effective 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.
1.1.1 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 non-
participants
Focus on programs that cost-effectively reduce carbon emissions
1.1.2 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 non-participants 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 rate pressure
2024 Integrated Resource Plan |Appendix 145 | Page
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 cost-effectively
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 9-2, where the three metrics that align with the guiding principles
are highlighted in blue.
Table 9-2: Summary of Cost-Effectiveness Components for Each Measure Test
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
1.1.3 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.
1.1.4 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
2024 Integrated Resource Plan |Appendix 146 | Page
in Table 9-3, which quantifies the performance of past and future programs using the cost tests shown in
Table 9-2. Past programs are based on FY 2019 actual results, and future programs are based on measures
expected to be installed in FY 2023-2027.
Table 9-3: Program Performance of FY 2019 EE Programs (Historic) vs. Future BE and TE Programs
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
Based on the information in Table 9-3, 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.
2024 Integrated Resource Plan |Appendix 147 | Page
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.
1.1.5 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:
• Res. and Comm. Heat Pump Space Heaters • Induction Cooktops
• Panel Upgrades • Residential and Commercial EV Chargers
2024 Integrated Resource Plan |Appendix 148 | Page
9.4 Renewables Portfolio Standard Procurement and Enforcement Plan
2024 Integrated Resource Plan |Appendix 149 | Page
2024 Integrated Resource Plan |Appendix 150 | Page
2024 Integrated Resource Plan |Appendix 151 | Page
2024 Integrated Resource Plan |Appendix 152 | Page
2024 Integrated Resource Plan |Appendix 153 | Page
2024 Integrated Resource Plan |Appendix 154 | Page
2024 Integrated Resource Plan |Appendix 155 | Page
2024 Integrated Resource Plan |Appendix 156 | Page
2024 Integrated Resource Plan |Appendix 157 | Page
2024 Integrated Resource Plan |Appendix 158 | Page
2024 Integrated Resource Plan |Appendix 159 | Page
2024 Integrated Resource Plan |Appendix 160 | Page
2024 Integrated Resource Plan |Appendix 161 | Page
2024 Integrated Resource Plan |Appendix 162 | Page
2024 Integrated Resource Plan |Appendix 163 | Page
9.5 Standardized Tables
State of California
California Energy Commission
Standardized Reporting Tables for Public Owned Utility IRP Filing
Administrative Information
Form CEC 113 (May 2017)
Name of Publicly Owned Utility ("POU")City of Redding
Name of Resource Planning Coordinator Lisa Casner
Name of Scenario Net-Zero Carbon with
Operating Constraints
Persons who prepared Tables CRAT Energy Balance Table Emissions Table RPS Table Application for Confidentiality
Name:Nick Rossow Nick Rossow Nick Rossow Nick Rossow
Title:Senior Resource Planner Senior Resource Planner Senior Resource Planner Senior Resource Planner
E-mail:nrossow@cityofredding.org nrossow@cityofredding.org nrossow@cityofredding.org nrossow@cityofredding.org
Telephone:530-339-7374 530-339-7374 530-339-7374 530-339-7374
Address:3611 Avtech Pkwy 3611 Avtech Pkwy 3611 Avtech Pkwy 3611 Avtech Pkwy
Address 2:
City:Redding Redding Redding Redding
State:CA CA CA CA
Zip:96002 96002 96002 96002
Date Completed:9/13/2023 9/13/2023 9/13/2023 9/13/2023
Date Updated:
Back-up / Additional Contact Persons for
Questions about these Tables (Optional):
Name:Lisa Casner Lisa Casner Lisa Casner Lisa Casner
Title:Electric Manager - Resources Electric Manager - Resources Electric Manager - Resources Electric Manager - Resources
E-mail:lcasner@cityofredding.org lcasner@cityofredding.org lcasner@cityofredding.org lcasner@cityofredding.org
Telephone:530-339-7263 530-339-7263 530-339-7263 530-339-7263
Address:3611 Avtech Pkwy 3611 Avtech Pkwy 3611 Avtech Pkwy 3611 Avtech Pkwy
Address 2:
City:Redding Redding Redding Redding
State:CA CA CA CA
Zip:96002 96002 96002 96002
2024 Integrated Resource Plan |Appendix 164 | Page
State of California
California Energy Commission
Standardized Reporting Tables for Public Owned Utility IRP Filing
Capacity Resource Accounting Table
Form CEC 109 (May 2017)
Scenario Name:
Yellow fill relates to an application for confidentiality.
Units = MW Data input by User are in dark green font.
PEAK LOAD CALCULATIONS 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
1 Forecast Total Peak-Hour 1-in-2 Demand 239.1 224.3 223.9 223.7 223.8 224.2 224.8 225.6 226.6 227.9 229.0 230.4 232.3 235.0 238.0 241.1 244.2 247.5 250.5 254.1 257.5
2 [Customer-side solar: nameplate capacity]15.4 18.1 21.1 22.4 23.3 24.2 25.0 25.8 26.6 27.4 28.2 28.9 29.7 30.4 31.1 31.8 32.5 33.2 33.9 34.5 35.2 35.8
2a [Customer-side solar: peak hour output] [Note 1]
3 [Peak load reduction due to thermal energy storage]
4 [Light Duty PEV consumption in peak hour]
5 Additional Achievable Energy Efficiency Savings on Peak
6 Demand Response / Interruptible Programs on Peak
7 Peak Demand (accounting for demand response and AAEE) (1-5-6)0.0 239.1 224.3 223.9 223.7 223.8 224.2 224.8 225.6 226.6 227.9 229.0 230.4 232.3 235.0 238.0 241.1 244.2 247.5 250.5 254.1 257.5
8 Planning Reserve Margin 15%0.0 35.9 33.6 33.6 33.6 33.6 33.6 33.7 33.8 34.0 34.2 34.3 34.6 34.8 35.3 35.7 36.2 36.6 37.1 37.6 38.1 38.6
9 Firm Sales Obligations
10 Total Peak Procurement Requirement (7+8+9)0.0 275.0 258.0 257.5 257.3 257.3 257.8 258.5 259.4 260.6 262.1 263.3 264.9 267.1 270.3 273.7 277.2 280.9 284.6 288.1 292.2 296.2
EXISTING AND PLANNED CAPACITY SUPPLY RESOURCES
Utility-Owned Generation and Storage (not RPS-eligible):For fuel type, choose from list or enter value
[list resource by name]Fuel type 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
11a Unit 1 Natural Gas 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0
11b Unit 2 Natural Gas 23.0 23.0 23.0 23.0 23.0 23.0 23.0 23.0 23.0 23.0 23.0 23.0 23.0 23.0 23.0 23.0 23.0 23.0 23.0 23.0 23.0 23.0
11c Unit 3 Natural Gas 23.0 23.0 23.0 23.0 23.0 23.0 23.0 23.0 23.0 23.0 23.0 23.0 23.0 23.0 23.0 23.0 23.0 23.0 23.0 23.0 23.0 23.0
11d Unit 4 - Steam Unit used for Combined Cycle with NG Units 5/Unit 6 Natural Gas 27.0 27.0 27.0 27.0 27.0 27.0 27.0 27.0 27.0 27.0 27.0 27.0 27.0 27.0 27.0 27.0 27.0 27.0 27.0 27.0 27.0 27.0
11e Unit 5 Natural Gas 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0
11f Unit 6 Natural Gas 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0 40.0
11g
Long-Term Contracts (not RPS-eligible):
[list contracts by name]Fuel type 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
11h Western - Large Hydro Large
Hydroelectric 91.0 66.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0 74.0
11i
11j
11k
11l
11m
11n
11 Total peak dependable capacity of existing and planned supply
resources (not RPS-eligible) (sum of 11a…11n)260 235 243 243 243 243 243 243 243 243 243 243 243 243 243 243 243 243 243 243 243 243
Utility-Owned RPS-eligible Resources:
[list resource by plant or unit]Fuel type 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
12a Whiskeytown Small
Hydroelectric 2.7 3.6 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
12b
12c
12d
12e
12f
12g
12h
12i
12j
12k
12l
12m
12n
**Note: All line items 2a
through 5 have already
been incorporated into
the load forecast and/or
the specified data does
not exist therefore can
not be reported or
forecasted separately and
reported here.
2024 Integrated Resource Plan |Appendix 165 | Page
Long-Term Contracts (RPS-eligible):
[list contracts by name]Fuel type 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
12o Big Horn Wind 22.0 22.0 18.0 18.0 18.0 18.0 18.0 18.0 18.0 18.0 18.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
12p Western - Small Hydro (Note: capacity is included in 11h)Small
Hydroelectric 0 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
12q Index+ Renewable PPA - Solar Solar PV 0 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
12r Index+ Renewable PPA - Wind Wind 0 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
12s
12t
12u
12v
12w
12x
12y
12z
12 Total peak dependable capacity of existing and planned RPS-
eligible resources (sum of 12a…12t)25 26 20 20 20 20 20 20 20 20 20 2 2 2 2 2 2 2 2 2 2 2
13 Total peak dependable capacity of existing and planned supply resources (11+12)285 261 263 263 263 263 263 263 263 263 263 245 245 245 245 245 245 245 245 245 245 245
GENERIC ADDITIONS
NON-RPS ELIGIBLE RESOURCES:
[list resource by name or description]Fuel type 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
14a 8hr Battery Storage Battery Storage 0 0 0 0 0 0 0 0 0 0 25 25 25 25 25 25 40 40 40 40 55 55
14b
14c
14d
14e
14f
14g
14h
14i
14j
14k
14l
14m
14n
14 Total peak dependable capacity of generic supply resources (not
RPS-eligible)0 0 0 0 0 0 0 0 0 0 25 25 25 25 25 25 40 40 40 40 55 55
RPS-ELIGIBLE RESOURCES:
[list resource by name or description]Fuel type 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
15a Solar Resources Solar PV 0 0 0 0 0 0 0 0 0 0 5 5 5 5 5 5 7 7 7 7 9 9
15b
15c
15d
15e
15f
15g
15h
15i
15j
15k
15l
15m
15n
15 Total peak dependable capacity of generic RPS-eligible resources 0 0 0 0 0 0 0 0 0 0 5 5 5 5 5 5 7 7 7 7 9 9
16 Total peak dependable capacity of generic supply resources (14+15)0 0 0 0 0 0 0 0 0 0 30 30 30 30 30 30 47 47 47 47 64 64
CAPACITY BALANCE SUMMARY
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
17 Total peak procurement requirement (from line 10)0 275 258 258 257 257 258 259 259 261 262 263 265 267 270 274 277 281 285 288 292 296
18 Total peak dependable capacity of existing and planned supply
resources (from line 13)285 261 263 263 263 263 263 263 263 263 263 245 245 245 245 245 245 245 245 245 245 245
19 Current capacity surplus (shortfall) (18-17)285 (14)5 5 6 6 5 4 4 2 1 (18)(20)(22)(25)(29)(32)(36)(40)(43)(47)(51)
20 Total peak dependable capacity of generic supply resources (from
line 16)0 0 0 0 0 0 0 0 0 0 30 30 30 30 30 30 47 47 47 47 64 64
21 Planned capacity surplus/shortfall (shortfalls assumed to be met
with short-term capacity purchases) (19+20)285 (14)5 5 6 6 5 4 4 2 31 12 10 8 5 2 15 11 7 4 17 13
2024 Integrated Resource Plan |Appendix 166 | Page
State of California
California Energy Commission
Standardized Reporting Tables for Public Owned Utility IRP Filing
Energy Balance Table
Form CEC 110 (May 2017)
Scenario Name: Units = MWh
Yellow fill relates to an application for confidentiality.
NET ENERGY FOR LOAD CALCULATIONS 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
1 Retail sales to end-use customers 722,772 712,411 673,996 675,142 673,549 675,314 679,158 685,882 690,565 698,375 707,383 717,932 727,465 744,046 758,788 788,916 816,330 848,464 895,345 929,262 972,528 1,004,037
2 Other loads 62,346 50,965 56,861 55,768 55,164 54,676 54,432 54,412 54,220 54,265 54,391 54,703 54,840 55,488 67,059 69,068 70,792 72,978 76,272 78,505 81,398 83,270
3 Net energy for load 785,118 763,376 730,857 730,911 728,713 729,990 733,590 740,293 744,785 752,641 761,774 772,635 782,305 799,534 825,847 857,983 887,123 921,442 971,617 1,007,767 1,053,926 1,087,307
4**Retail sales to end-use customers (accounting for AAEE impacts)722,772 712,411 673,996 675,142 673,549 675,314 679,158 685,882 690,565 698,375 707,383 717,932 727,465 744,046 758,788 788,916 816,330 848,464 895,345 929,262 972,528 1,004,037
5**Net energy for load (accounting for AAEE impacts)785,118 763,376 730,857 730,911 728,713 729,990 733,590 740,293 744,785 752,641 761,774 772,635 782,305 799,534 825,847 857,983 887,123 921,442 971,617 1,007,767 1,053,926 1,087,307
6 Firm Sales Obligations
7 Total net energy for load (accounting for AAEE impacts) (5+6)785,118 763,376 730,857 730,911 728,713 729,990 733,590 740,293 744,785 752,641 761,774 772,635 782,305 799,534 825,847 857,983 887,123 921,442 971,617 1,007,767 1,053,926 1,087,307
8 [Customer-side solar generation]
9 [Light Duty PEV electricity consumption/procurement requirement]
10 [Other transportation electricity consumption/procurement requirement]
11 [Other electrification/fuel substitution; consumption/procurement requirement]
EXISTING AND PLANNED GENERATION RESOURCES
Utility-Owned Generation Resources (not RPS-eligible):
[list resource by name]Fuel type 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
12a Unit 1 Natural Gas 1,351 1,547 919 281 387 144 41 48 25 44 45 42 81 48 76 88 85 41 26 1 0 0
12b Unit 2 Natural Gas 3,099 2,690 2,911 1,201 1,687 653 302 223 133 140 198 153 258 195 244 296 260 143 72 2 0 0
12c Unit 3 Natural Gas 3,229 2,818 2,319 901 1,283 535 210 162 112 133 169 128 196 149 193 227 217 114 64 1 0 0
12d Unit 4 - Steam Unit used for Combined Cycle with NG Units 5/Unit 6
(Note: Generation is included in 12e and 12f)Natural Gas 106,795 119,775 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
12e Unit 5 Natural Gas 138,789 175,233 146,617 147,359 136,032 145,634 139,525 139,908 138,447 139,049 136,435 146,150 133,329 133,829 136,139 131,865 132,419 136,872 98,738 0 0 0
12f Unit 6 Natural Gas 120,666 124,854 139,757 138,876 128,604 141,689 133,352 135,753 132,214 132,393 129,744 141,034 128,126 129,155 132,873 126,689 125,809 131,490 95,901 0 0 0
12g
Long-Term Contracts (not RPS-eligible):
[list contracts by name]Fuel type 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
12h Western - Large Hydro Large
Hydroelectric 136,862 57,857 139,907 243,752 238,877 238,877 238,877 238,877 238,877 238,877 238,877 238,877 238,877 238,877 238,877 238,877 238,877 238,877 238,877 238,877 238,877 238,877
12i
12j
12k
12l
12m
12n
12 Total energy from existing and planned supply resources (not
RPS-eligible) (sum of 12a…12n)510,792 484,775 432,430 532,370 506,871 527,532 512,307 514,970 509,807 510,636 505,468 526,384 500,867 502,253 508,402 498,042 497,666 507,538 433,679 238,882 238,877 238,877
Utility-Owned RPS-eligible Generation Resources:
[list resource by plant or unit]Fuel type 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
13a Whiskeytown Small
Hydroelectric 18,693 25,916 24,091 24,323 24,248 24,250 24,250 24,322 24,247 24,246 23,949 23,734 23,762 23,723 23,500 23,201 22,993 23,003 23,072 22,953 22,187 21,581
13b
13c
13d
13e
13f
13g
13h
13i
13j
13k
13l
13m
13n
Historical Data
**Note: AAEE have already been
incorporated into the load forecast
and/or the specified data does not
exist therefore can not be reported or
forecasted separately here.
2024 Integrated Resource Plan |Appendix 167 | Page
Long-Term Contracts (RPS-eligible):
[list contracts by name]Fuel type 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
13o Big Horn Wind 191,201 163,586 173,337 172,542 170,746 169,466 168,195 167,424 165,681 164,439 122,979 0 0 0 0 0 0 0 0 0 0 0
13p Western - Small Hydro Small
Hydroelectric 2,815 5,306 2,420 4,215 4,131 4,131 4,131 4,131 4,131 4,131 4,131 4,131 4,131 4,131 4,131 4,131 4,131 4,131 4,131 4,131 4,131 4,131
13q Index+ Renewable PPA - Solar (Note: Solar and Wind Generation will
vary, all generation included in 13q)Solar PV 100,000 0 0 0 175,000 175,000 175,000 175,000 175,000 175,000 175,000 175,000 175,000 175,000 0 0 0 0 0 0 0 0
13r Index+ Renewable PPA - Wind (Note: Solar and Wind Generation will
vary, all generation included in 13q)Wind 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
13s
13t
13u
13v
13w
13x
13y
13aa
13 Total energy from RPS-eligible resources (sum of 13a…13aa)312,709 194,808 199,847 201,081 374,126 372,847 371,576 370,877 369,060 367,816 326,060 202,865 202,893 202,855 27,631 27,332 27,124 27,134 27,203 27,084 26,319 25,712
13z Undelivered RPS energy
14 Total energy from existing and planned supply resources (12+13)823,501 679,583 632,277 733,451 880,996 900,378 883,883 885,847 878,867 878,452 831,527 729,250 703,760 705,108 536,033 525,373 524,791 534,672 460,882 265,966 265,195 264,589
GENERIC ADDITIONS
NON-RPS ELIGIBLE RESOURCES:
[list resource by name or description]Fuel type 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
15a 8hr Battery Storage Battery Storage 0 0 0 0 0 0 0 0 0 0 -4,019 -8,178 -7,894 -7,705 -9,586 -9,316 -11,095 -13,343 -15,141 -14,223 -17,657 -18,123
15b
15c
15d
15e
15f
15g
15h
15i
15j
15k
15l
15m
15n
15 Total energy from generic supply resources (not RPS-eligible)0 0 0 0 0 0 0 0 0 0 (4,019)(8,178)(7,894)(7,705)(9,586)(9,316)(11,095)(13,343)(15,141)(14,223)(17,657)(18,123)
RPS-ELIGIBLE RESOURCES:
[list resource by name or description]Fuel type 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
16a Solar Resources Solar PV 0 0 0 0 0 0 0 0 0 0 371,463 500,046 500,046 514,933 572,081 614,942 643,516 673,291 716,153 773,301 832,851 877,513
16b
16c
16d
16e
16f
16g
16h
16i
16j
16k
16l
16m
16n
16 Total energy from generic RPS-eligible resources 0 0 0 0 0 0 0 0 0 0 371,463 500,046 500,046 514,933 572,081 614,942 643,516 673,291 716,153 773,301 832,851 877,513
17 Total energy from generic supply resources (15+16)0 0 0 0 0 0 0 0 0 0 367,444 491,868 492,151 507,228 562,495 605,626 632,422 659,949 701,012 759,078 815,194 859,390
17z Total energy from RPS-eligible short-term contracts [Note 1]0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
ENERGY FROM SHORT-TERM PURCHASES
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
18 Short term and spot market purchases:207,958 227,712 225,855 199,588 208,801 200,785 207,526 212,414 217,301 226,037 142,559 171,956 193,624 202,232 208,226 228,548 236,433 232,308 278,683 383,256 386,708 396,736
18a Short term and spot market sales (only report sales of energy
from resources already included in the EBT):246,341 143,919 127,275 202,127 361,085 371,173 357,819 357,968 351,383 351,848 579,756 620,439 607,230 615,034 480,908 501,564 506,523 505,487 468,959 400,532 413,171 433,408
ENERGY BALANCE SUMMARY
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
19 Total energy from supply resources (14+17+17z)823,501 679,583 632,277 733,451 880,996 900,378 883,883 885,847 878,867 878,452 1,198,971 1,221,117 1,195,911 1,212,336 1,098,528 1,131,000 1,157,212 1,194,621 1,161,894 1,025,044 1,080,389 1,123,979
19a Undelivered RPS energy (from 13z)0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
20 Net Short term and spot market purchases (18 - 18a)(38,383)83,793 98,580 (2,540)(152,284)(170,388)(150,293)(145,553)(134,082)(125,811)(437,197)(448,483)(413,606)(412,802)(272,681)(273,016)(270,090)(273,179)(190,276)(17,276)(26,462)(36,672)
21 Total delivered energy (19-19a+20)785,118 763,376 730,857 730,911 728,713 729,990 733,590 740,293 744,785 752,641 761,774 772,635 782,305 799,534 825,847 857,983 887,123 921,442 971,617 1,007,767 1,053,926 1,087,307
22 Total net energy for load (from 7)785,118 763,376 730,857 730,911 728,713 729,990 733,590 740,293 744,785 752,641 761,774 772,635 782,305 799,534 825,847 857,983 887,123 921,442 971,617 1,007,767 1,053,926 1,087,307
23 Surplus/Shortfall (21-22)0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
2024 Integrated Resource Plan |Appendix 168 | Page
State of California
California Energy Commission
Standardized Reporting Tables for Public Owned Utility IRP Filing
GHG Emissions Accounting Table
Form CEC 111 (May 2017)
Scenario Name:
Yellow fill relates to an application for confidentiality.
Emissions Intensity Units = mt CO2e/MWh
GHG EMISSIONS FROM EXISTING AND PLANNED SUPPLY RESOURCES Yearly Emissions Total Units = Mmt CO2e
Utility-Owned Generation (not RPS-eligible):
[list resource by name]Emissions
Intensity 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
1a Redding Power Plant (Units 1 -6 on CRAT Form)0.423 59,738 147,168 124,884 121,677 113,493 121,653 115,104 116,285 113,955 114,204 112,395 121,394 110,755 111,389 114,075 109,840 109,634 113,603 82,507 4 0 0
1b
1c
1d
1e
1f
1g
Long-Term Contracts (not RPS-eligible):
[list contracts by name] [Note 1]Emissions
Intensity 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
1h Western - Large Hydro 0.000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
1i
1j
1k
1l
1m
1n
1 Total GHG emissions of existing and planned supply
resources (not RPS-eligible) (sum of 1a…1n)59,738 147,168 124,884 121,677 113,493 121,653 115,104 116,285 113,955 114,204 112,395 121,394 110,755 111,389 114,075 109,840 109,634 113,603 82,507 4 0 0
Utility-Owned RPS-eligible Generation Resources:
[list resource by plant or unit]Emissions
Intensity 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
2a Whiskeytown 0.000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
2b
2c
2d
2e
2f
2g
2h
2i
2j
2k
2l
2m
2n
Long-Term Contracts (RPS-eligible):
[list contracts by name]Emissions
Intensity 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
2o Big Horn 0.000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
2p Western - Small Hydro 0.000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
sq Index+ Renewable PPA - Solar 0.000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
2r Index+ Renewable PPA - Wind 0.000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
2s
2t
2v
2u
2w
2x
2y
2z
2 Total GHG emissions from RPS-eligible resources 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
3 Total GHG emissions from existing and planned supply resources (1+2)59,738 147,168 124,884 121,677 113,493 121,653 115,104 116,285 113,955 114,204 112,395 121,394 110,755 111,389 114,075 109,840 109,634 113,603 82,507 4 0 0
2024 Integrated Resource Plan |Appendix 169 | Page
EMISSIONS FROM GENERIC ADDITIONS
NON-RPS ELIGIBLE RESOURCES:
[list resource by name or description]Emissions
Intensity 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
4a 8hr Battery Storage 0.000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
4b
4c
4d
4e
4f
4g
4h
4i
4j
4k
4l
4m
4n
4 Total GHG emissions from generic supply resources 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
RPS-ELIGIBLE RESOURCES:
[list resource by name or description]Emissions
Intensity 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
5a Solar Resources 0.000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
5b
5c
5d
5e
5f
5g
5h
5i
5j
5k
5l
5m
5n
5 Total GHG emissions from generic RPS-eligible 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
6 Total GHG emissions from generic supply resources (4+5)0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
GHG EMISSIONS OF SHORT TERM PURCHASES
Emissions
Intensity 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
7 Net spot market/short-term purchases:0.428 (16,428)35,863 42,192 (1,087)(65,177)(72,926)(64,325)(62,297)(57,387)(53,847)(187,120)(191,951)(177,023)(176,679)(116,708)(116,851)(115,598)(116,921)(81,438)(7,394)(11,326)(15,696)
TOTAL GHG EMISSIONS
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
8 Total GHG emissions to meet net energy for load 43,310 183,032 167,077 120,590 48,316 48,727 50,779 53,988 56,568 60,357 (74,726)(70,556)(66,269)(65,291)(2,633)(7,011)(5,964)(3,318)1,069 (7,390)(11,326)(15,696)
EMISSIONS ADJUSTMENTS
8a Undelivered RPS energy (MWh from EBT)0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
8b Firm Sales Obligations (MWh from EBT)0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
8c Total energy for emissions adjustment (8a+8b)0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
8d Emissions intensity (portfolio gas/short-term and
8e Emissions adjustment (8Cx8D)0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
PORTFOLIO GHG EMISSIONS
8f Adjusted Portfolio emissions (8-8e)43,310 183,032 167,077 120,590 48,316 48,727 50,779 53,988 56,568 60,357 -74,726 -70,556 -66,269 -65,291 -2,633 -7,011 -5,964 -3,318 1,069 -7,390 -11,326 -15,696
GHG EMISSIONS IMPACT OF
TRANSPORTATION ELECTRIFICATION
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
9 GHG emissions reduction due to gasoline vehicle
displacement by LD PEVs 1,908 2,170 2,651 3,419 4,577 6,196 8,175 10,634 13,619 17,255 21,305 25,814 30,880 39,212 53,228 67,171 80,882 94,392 107,702 120,897 134,049 147,201
10 GHG emissions increase due to LD PEV electricity 131 381 526 501 276 385 538 751 1,019 1,385 0 0 0 0 0 0 0 0 133 0 0 0
11
12
Note: The data below is not metered actuals or calculations from metered data. It is best estimate using
reasonable assumptions which are also used in forecast estimates along with factors from CARB EV GHG
Benefits Tool. Line #10 values are already included in System GHG values above.
GHG emissions reduction due to fuel displacement - other transportation
GHG emissions increase due to increased electricity loads - other transportation
2024 Integrated Resource Plan |Appendix 170 | Page
State of California
California Energy Commission
Standardized Reporting Tables for Public Owned Utility IRP Filing
RPS Procurement Table
Form CEC 112 (May 2017)
Scenario Name:
Beginning balances Units = MWh
Start of 2021
RPS ENERGY REQUIREMENT CALCULATIONS 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
1 Annual Retail sales to end-use customers (accounting for AAEE impacts) (From EBT)722,772 712,411 673,996 675,142 673,549 675,314 679,158 685,882 690,565 698,375
2 Green pricing program Exclusion, (may include other exclusions like self generation exclusion) [Note 1]
3 Soft target (%)36%39%41%44%46%50%52%55%57%60%
4 Required procurement for compliance period
Category 0, 1 and 2 Resources (bundled with RECs)
5 Excess balance at beginning/end of compliance period 273,130 19,502 137,398
6 RPS-eligible energy procured (copied from EBT)312,709 194,808 199,847 201,081 374,126 372,847 371,576 370,877 369,060 367,816
6A Amount of energy applied to procurement obligation 312,709 194,808 199,847 201,081 374,126 337,657 353,162 374,972 395,901 419,025
7 Net purchases of Category 0, 1 and 2 RECs 0 0 0 0 0 0 0 0 0 0
7A Excess balance and REC purchases applied to procurement obligation 0 79,470 78,177 95,982 (64,293)0 0 0 0 0
8 Net change in balance/carryover (RECs and RPS-eligible energy) (6+7-6A-7A)0 (79,470)(78,177)(95,982)64,293 35,190 18,413 (4,095)(26,841)(51,209)
Category 3 Resources (unbundled RECs)
9 Excess balance at beginning/end of compliance period 0 0 0
10 Net purchases of Category 3 RECs
11 Excess balance and REC purchases applied to procurement obligation
12 Net change in REC balance 0 0 0 0 0 0 0 0 0 0
13 Total generation plus RECs (all Categories) applied to procurement requirement (6A + 7A + 11)
14 Over/under procurement for compliance period (13 - 4)54,318
1,107,755
1,189,898
0
Compliance Period 4 Compliance Period 5 Compliance Period 6
1,000,652 1,189,898
1,162,073 1,000,652
0
2024 Integrated Resource Plan |Appendix 171 | Page
2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
707,383 717,932 727,465 744,046 758,788 788,916 816,330 848,464 895,345 929,262 972,528 1,004,037
60%60%60%60%60%60%60%60%60%60%60%60%
55,253 866,956 1,451,680 2,030,018 2,849,302
697,522 702,911 702,938 717,788 599,712 642,274 670,641 700,425 743,356 800,385 859,169 903,226
424,430 430,759 702,938 717,788 599,712 642,274 670,641 700,425 743,356 800,385 859,169 903,226
0 0 0 0 0 0 0 0 0 0 0 0
0 0 (266,459)(271,360)(144,440)(168,925)(180,842)(191,347)(206,148)(242,828)(275,653)(300,803)
273,092 272,152 266,459 271,360 144,440 168,925 180,842 191,347 206,148 242,828 275,653 300,803
0 0 0 0 0
0 0 0 0 0 0 0 0 0 0 0 0
Compliance Period 7
1,291,668
1,291,668
0
Compliance Period 8
1,375,050
1,375,050
0
Compliance Period 9
1,536,084
1,536,084
0
Compliance Period 10
1,743,497
1,743,497
0
Presented by: Nicholas ZettelElectric Utility Director
CITY OF REDDING ELECTRIC UTILITY
2024|INTEGRATED RESOURCE PLAN
Agenda
Legislative Requirements & Updates
Summary of the legislative impacts on IRP planning
resulting from the adoption of SB 100
Existing Resources & Demand Forecast
Overview of existing portfolio and options for future
resource technologies
Modeling & Resource Selection
Framework for development of resource modeling and
methodologies
Stakeholder Engagement & Preferred Plan
Summary of the stakeholder engagement process and
identified preferred plan for the 2024 IRP
What is an IRP?
Overview of the purpose of the IRP for resource
planning
An Integrated Resource Plan (IRP) is a
20-year strategic roadmap ensuring all
utility energy decisions align with long-term
objectives and clean energy mandates.
REU is the smallest POU in California
required to file an IRP.
What is an IRP?
Who is required to file an IRP?
SB 350 required all publicly-owned utilities
(POUs) with an annual average annual load
greater than 700 GWh to file an IRP by 2019.
REU’s average annual retail sales are 745 GWh
2024 IRP Timeline
Complete all initial
studies for IRP
development
AUGUST ‘22
Begin stakeholder
engagement &
workshops
JANUARY ‘23
Identify & present
preferred resource
plan to public
MARCH ‘23
Submit 2024 IRP
report to City
Council for approval
NOVEMBER ‘23
Finalize energy
modeling for the
2024 IRP report
SEPTEMBER ‘23
Submit approved
2024 IRP report to
the CEC by April ‘24
APRIL ‘24
This is not a procurement document; all resource procurements will receive prior Council approval.
Key Legislative Updates
Since 2019 IRP Filing
Clean Energy Mandates
Renewable energy and zero-carbon resources
must supply 100 percent of electric retail sales
to end-use customers by 2045
Interim Carbon-Free Targets
90% carbon-free by 2035, 95% carbon-free by
2040; REU’s 3-yr average (2019-2021) is 80%
carbon-free
Transportation + Building Electrification
Stricter building codes, zero-emission fleet
regulations, and 2035 gas vehicle ban are driving
an increase in customer energy demand
REU’s Current Energy
Resource Portfolio
4%
26%
23%
2%
45%
Unspecified, 2%
Market energy not
specifically sourced
Redding Power
Plant
Combined-cycle
natural gas plant in
Redding
Big Horn Wind
Large Hydro, 26%
Wind power contract
in Klickitat Co., WA
Hydropower from
Central Valley
Project, including
Shasta Dam
Small Hydro, 4%
Includes Central Valley
Project small hydro
+ Whiskeytown Dam
20-Year Demand Forecast
Compared to Previous IRP Forecast Key Takeaways:
Annual customer demand
increases by roughly 55%
Energy Efficiency causes
dip in demand until
electrification adoption
increases
Sharp rise and continuous
growth in demand starting
in 2035, aligning with ZEV
requirements
600
700
800
900
1000
1100
1200
An
n
u
a
l
E
n
e
r
g
y
,
G
W
h
2018 vs. 2023 Annual Customer Demand Forecast
2018 Forecast 2023 Forecast Actual
Stakeholder Engagement
Seven community members participated in a series of five
workshops held over six weeks. Ultimately, the group was
tasked with identifying the preferred plan for the 2024 IRP.
The Key Stakeholder Group included representatives from:
Net-Zero Carbon 2045 vs
100% Zero Carbon 2045
Stakeholders were
presented with two plans:
Note that the Base Case was not considered for plan selection due to not meeting mandates
Scenario Modeling Results
Affordability
Energy available to meet
customer demand
Reliability
Allows Redding Power to run as
normal for reliability
Compliance
Assumes no carbon constraints
Affordability
Integrates low-cost renewable
energy to retain affordable rates
Reliability
Continues operation of Redding
Power for on-system reliability
Compliance
Meets renewable mandates and
carbon targets
Affordability
Must procure costly dispatchable
zero-carbon resources
Reliability
Battery storage and dispatchable
resources replace Redding Power
Compliance
Over-procurement is needed to
reach 100% zero carbon
Scenario 1
Base Case (Low)
Scenario 2
Net-Zero Carbon (Mid)
Scenario 3
100% Zero Carbon (High)
Cost Impacts by
Scenario Energy Cost:
A single component
Energy costs are just one part of
utility rates
Achieving 100% Zero Carbon
costs $116 million more, per
year, than Net-Zero Carbon
Equivalent to an additional 69% rate
increase
Must balance sustainability
and affordability
$87 $96
$212
$-
$50
$100
$150
$200
$250
Scenario 1
Base Case
Scenario 2
Net-Zero Carbon
Scenario 3
100% Zero Carbon
An
n
u
a
l
P
r
e
s
e
n
t
V
a
l
u
e
C
o
s
t
,
$
M
M
Annual Energy Cost in 2045
Preferred Plan Identified:
The Group acknowledged Redding Power
Plant’s critical role in maintaining reliability
and affordability, while strongly
encouraging staff to continue seeking zero-
carbon options.
Net-Zero Carbon 2045
is the Preferred Plan for the 2024 IRP
Adds 340 MW of solar + 55 MW of battery
storage by 2045
Maintains affordable rates by integrating
low-cost renewables
Continues operation of Redding Power for
reliability
Achieves compliance by meeting carbon
reduction and renewable energy targets
Conclusion Affordability
Decreases costs by an estimated $8M
over the 20-year planning period and
incorporates cost-effective intermittent
resources
Compliance
Meets the State’s clean energy
requirements while integrating
renewables into the energy portfolio
Reliability
Preserves Redding Power Plant as a
reliable resource that can be leveraged
when intermittent resources are
unavailable
Thanks to the key stakeholder group’s
commitment, participation, and engagement in
the process, a Preferred Plan was identified
that meets the IRP’s objectives and maximizes
community benefit.
Recommendation
Questions?
Approve the 2024 Integrated Resource Plan and
authorize the Electric Utility Director to modify
the IRP if needed to meet the requirements of the
California Energy Commission.
Energy Modeling
Process Inputs
Portfolio Design
Power Supply
Costs
Optimized
Portfolio
Does it meet or exceed
regulatory requirements?
Does it serve load reliably
when customers need it?
Does it help keep rates
affordable?
Meets all identified
IRP objectives
The preferred 2024 IRP scenario
should meet or exceed the State’s
clean energy mandates while
balancing reliability and affordability.
The following strategic
framework was used to
develop modeling scenarios:
EvaluatedResources
Attributes & Characteristics
RESOURCE RELIABLE ELIGIBLE
RENEWABLE
CARBON-
FREE
ANNUAL
CAPABILITY
Solar No Yes Yes 33-34%
Wind No Yes Yes 24-55%
Renewable Gas Yes Yes Yes*Up to 100%
Carbon Capture Yes No*Yes Up to 100%
Hydrogen Yes Yes*Yes Up to 100%
Battery Storage Yes N/A N/A Up to 100%
Geothermal Yes Yes Yes 92%
Biomass Yes Yes Depends 70%
Resources were evaluated based on their
technology type, generating characteristics, and
ability to meet clean energy requirements.
* Renewable or Carbon-free eligibility depends on the fuel source
New Resources Identified by Model
Net-Zero Carbon 2045 (MW)100% Zero Carbon 2045 (MW)
Year Solar 8-hr Battery
Storage Solar 8-hr Battery
Storage
Carbon
Capture Hydrogen
2031 150 25 200 25 --
2034 50 -----
2037 50 15 25 15 --
2041 50 15 35 160 25 95
2045 40 -----
Total 340 MW 55 MW 260 MW 200 MW 25 MW 95 MW
vs
Note: Base Case is not shown as it assumes no changes from the Current Portfolio
Energy Supply Stack
Net-Zero Carbon 2045
-750,000
-250,000
250,000
750,000
1,250,000
1,750,000
Out-of-State Exports
In-State Exports
In-State Imports
Out-of-State Imports
Battery
Solar
Whiskeytown
Big Horn
WAPA
RPP
Total