Agenda packet — Desert Community Energy Board of Directors, October 17, 2022

ATTENTION: DCE VOTING MEMBERS WILL RECEIVE A UNIQUE PANELIST LINK BY EMAIL. PLEASE USE THIS LINK TO PARTICIPATE IN THIS MEETING.

DESERT COMMUNITY ENERGY

BOARD MEETING AGENDA
Monday, October 17, 2022
2:00 p.m.

Pursuant to Assembly Bill 361 and the findings made by the DCE Board, this meeting will only be conducted via video/teleconferencing.

INSTRUCTIONS FOR PUBLIC PARTICIPATION
Online:
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Dial In #: +1 669 900 9128
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This will provide listening access and ability to address the DCE Board when called upon.

IF YOU ARE UNABLE TO CONNECT VIA DIAL IN OPTION, PLEASE CALL 760-346-1127 Members of the public are encouraged to submit comment in connection with the Desert Community Energy meeting by email to: [email protected] by 5:00 p.m. on the day prior to the committee meeting. Comments intended to be read aloud into the record should be no more than 300 characters in length.

THIS MEETING IS HANDICAPPED ACCESSIBLE.

ACTION MAY RESULT ON ANY ITEMS ON THIS AGENDA.

1. CALL TO ORDER- Chair Geoff Kors, Councilmember, City of Palm Springs

2. 3.

ROLL CALL –
A. Member Roster P4

AGENDA MODIFICATIONS (IF ANY)

4. PUBLIC COMMENTS ON AGENDA ITEMS
Any person wishing to address the Desert Community Energy Board on items appearing on this agenda may do so at this time. Please limit comments to 3 minutes. At the discretion of the chair, additional public comment time and/or opportunities during the meeting may be granted.

5. BOARD MEMBER / DIRECTOR COMMENTS

6. CONSENT CALENDAR
A. Approve Minutes from the September 28, 2022 Board Meeting P5

B. Reaffirm that findings still exist, pursuant to Assembly Bill 361, and P8 authorize continuation of remote teleconference/virtual meetings of Desert Community Energy

7. DISCUSSION / ACTION
A. DCE’s 2022 Integrated Resource Plan – David Freedman P9 Recommendation: Adopt Resolution 2022-09 approving the Desert Community Energy 2022 Integrated Resource Plan and authorize the Executive Director to make any clarifying changes and complete all actions necessary for submittal to the California Public Utilities Commission
B. DCE Financial Outlook – Jaclyn Harr
C. October 2022 Rate Adjustment Summary – Don Dame P62
Recommendation: Information

8. INFORMATION
A. Attendance Record P64
B. Unaudited Financial Report as of August 31, 2022 P65 C. Unaudited Year-to-Year Financial Report as of August 31, 2022 P67

9. PUBLIC COMMENTS ON NON-AGENDA ITEMS
Any person wishing to address the Board on items not appearing on this agenda may do so at this time. Please limit comments to 2 minutes. At the discretion of the chair, additional public comment time and/or opportunities during the meeting may be granted.

10. ANNOUNCEMENTS
The next DCE meeting will be held November 21, 2022 at 3:00 p.m. via Zoom webinar.

11. ADJOURNMENT

DESERT COMMUNITY ENERGY

BOARD MEMBER ROSTER
Voting Members Seat on Committee Representative
City of Palm Desert DCE Vice Chair
Sabby Jonathan
Mayor Pro Tem
Alternate: Councilmember Kathleen Kelly
City of Palm Springs DCE Chair
Geoff Kors
Councilmember
Alternate: Mayor Lisa Middleton
DCE Staff
Tom Kirk, Executive Director
Kenyon Potter, Director of Energy & Sustainability
Katie Barrows, Part-Time Interim Director
David Freedman, Program Manager
Liz Barnwell, Management Analyst
Janice Reitman, Accounting Manager
ITEM 6A

1. CALL TO ORDER
The meeting of the DCE Board was called to order by Chair Geoff Kors, City of Palm Springs, at 3:30 p.m. via Zoom videoconferencing, pursuant to Assembly Bill 361.

2. ROLL CALL
Roll call was taken, and it was determined that a quorum was present.

Members Present Agency
Councilmember Geoff Kors, Chair City of Palm Springs
Mayor Pro Tem Sabby Jonathan, Vice Chair City of Palm Desert

3. AGENDA MODIFICATIONS (IF ANY)
Executive Director Tom Kirk noted that the next meeting, on October 17, would be starting at 2 p.m.

4. PUBLIC COMMENTS ON AGENDA ITEMS
None.

5. BOARD MEMBER / DIRECTOR COMMENTS
Mr. Kirk noted the recent weather patterns and impact on energy prices and use. He also detailed a recent analysis of the impact DCE was having, noting that Southern California Edison has about 100 times more customers but that, through DCE, the City of Palm Springs has 10 times more Carbon Free customers than Edison. Members requested additional details be sent to Cities.

Mr. Kirk also introduced Kenyon Potter, new Director of Energy and Sustainability, who made brief remarks.

Noting the upcoming council elections will impact the representation on DCE’s Board, Vice Chair Jonathan inquired about how Board members are chosen. Mr. Kirk said correspondence would be sent to cities to clarify the process and timing.

Desert Community Energy Board of Directors
Meeting Minutes – September 28, 2022

6. CONSENT CALENDAR
IT WAS MOVED BY VICE CHAIR JONATHAN AND SECONDED BY CHAIR KORS TO:

A. Approve Minutes from the July 18, 2022 Board Meeting

B. Reaffirm that findings still exist, pursuant to Assembly Bill 361, and authorize continuation of remote teleconference/virtual meetings of Desert Community Energy
C. Authorize the Chair to execute Amendment No. 1 to the Implementation and Management Services Agreement with the Coachella Valley Association of Governments, extending the existing staffing arrangement until October 30, 2027
D. Authorize the updating of the signature cards and signatories for DCE investments and banking
E. Adopt Resolution 2022-06, approving the 2021 Power Content Label THE MOTION CARRIED WITH 2 AYES.

Mayor Pro Tem Jonathan Aye
Councilmember Kors Aye
.

7. DISCUSSION / ACTION
A. Master Power Purchase and Sale Agreement with Southern California Edison and Resource Adequacy Confirmation – David Freedman
Program Manager David Freedman presented the staff report.

IT WAS MOVED BY VICE CHAIR JONATHAN AND SECONDED BY CHAIR KORS TO ADOPT RESOLUTION NO. 2022-07, APPROVING A MASTER POWER PURCHASE

AND SALE AGREEMENT AND CONFIRMATION LETTER FOR RESOURCE

ADEQUACY WITH SOUTHERN CALIFORNIA EDISON COMPANY
THE MOTION CARRIED WITH 2 AYES.

Mayor Pro Tem Jonathan Aye
Councilmember Kors Aye
B. DCE Mid-term Reliability Procurement: Cape Generating Station 1 LLC Geothermal Project – David Freedman
Mr. Freedman presented the staff report. Member discussion ensued.

IT WAS MOVED BY VICE CHAIR JONATHAN AND SECONDED BY CHAIR KORS TO ADOPT RESOLUTION 2022-08, APPROVING A 15-YEAR RENEWABLE POWER PURCHASE AGREEMENT WITH CAPE GENERATING STATION 1 LLC, AND Desert Community Energy Board of Directors
Meeting Minutes – September 28, 2022

AUTHORIZING THE EXECUTIVE DIRECTOR AND/OR LEGAL COUNSEL TO MAKE

MINOR MODIFICATIONS BEFORE EXECUTION OF THE AGREEMENT
THE MOTION CARRIED WITH 2 AYES.

Mayor Pro Tem Jonathan Aye
Councilmember Kors Aye

8. INFORMATION
The following items were included in the agenda packet for members’ information :

A. Attendance Record
B. Unaudited Financial Report as of June 30, 2022
C. Unaudited Year-to-Year Financial Report as of June 30, 2022

9. PUBLIC COMMENT ON NON-AGENDA ITEMS

None.

10. ANNOUNCEMENTS
The next DCE meeting will be held October 17, 2022 at 2:00 p.m. via Zoom webinar.

11. ADJOURNMENT – Chair Kors adjourned the meeting at 3:50 p.m.

Respectfully submitted,
Erica Felci, Assistant Executive Director
ITEM 6B
a

STAFF REPORT
Subject: Remote Teleconference/Virtual Meetings Pursuant to Assembly Bill 361 Contact: Erica Felci, Assistant Executive Director ([email protected]) Recommendation: Reaffirm that findings still exist, pursuant to Assembly Bill 361, and authorize continuation of remote teleconference/virtual meetings of Desert Community Energy
Background: All meetings of the Desert Community Energy Board and its Community Advisory Committee are subject to the Ralph M. Brown Act (Gov. Code §§ 54950 et seq.), and must be open and public so that any member of the public may attend and participate in the meetings.

Starting in March 2020, Governor Newsom issued a series of executive orders aimed at preventing the spread of COVID-19, as it was determined that social distancing was an important factor addressing the pandemic. Among these were Executive Orders N-25-20, N-29-20 and N-35-20 (collectively, the “Brown Act Orders”) that waived the teleconferencing requirements of the Brown Act to allow legislative bodies to meet virtually.

On June 11, 2021, the Governor issued Executive Order N-08-21 to begin winding down some of the prior measures that were adopted to respond to COVID-19. Notably, this order rescinds the Brown Act Orders, effective September 30, 2021. On September 16, 2021, Governor Newsom signed Assembly Bill 361 (AB 361), which effective October 1, 2021, allows legislative bodies to meet virtually provided the legislative body makes specific findings.

Specific Findings Required under AB 361:

The DCE Board has previously made the following findings pursuant to AB 361:

1. A statewide state of emergency is currently in place;

2. State or local officials have imposed or recommended measures to promote social distancing in connection with COVID-19; and

3. Meeting in person would present imminent risks to the health or safety of attendees.

With this item, staff is recommending the DCE Board confirm these findings still exist and continue virtual meetings, pursuant to AB 361.

Fiscal Analysis: There are no additional costs to DCE for hosting virtual meetings.

Item 7A

STAFF REPORT
Subject: DCE’s 2022 Integrated Resource Plan
Contact: David Freedman, Program Manager ([email protected]) Recommendation: Adopt Resolution 2022-09 approving the Desert Community Energy 2022 Integrated Resource Plan and authorize the Executive Director to make any clarifying changes and complete all actions necessary for submittal to the California Public Utilities Commission
Background: The Integrated Resource Plan (IRP) is a requirement for all load serving entities (LSEs) including Desert Community Energy (DCE) and other community choice aggregation agencies (CCAs). The overarching purpose of the IRP process is to ensure that California’s electricity sector meets it greenhouse gas (GHG) reduction goals while maintaining reliability at the lowest possible costs. It is an important part of the statewide effort to keep California on a path toward achieving the state’s ambitious clean energy targets while ensuring system reliability.

A focus of the IRP is to ensure that DCE is providing enough energy to serve DCE’s load and to quantify its GHG emissions reduction objectives. The IRP process and coordination of this statewide planning effort has gained more significance as recent heat events strain energy resources.

The IRP must be submitted every two years to the California Public Utilities Commission (CPUC).

This year, the IRP is due on November 1. For the 2022 IRP, the LSEs are required to provide planning information out to 2035, and planning efforts will be focused around 2035 GHG reduction and reliability results. The CPUC also adopted a GHG planning target of 38 million metric tons (MMT) of GHG emissions in aggregate for the electricity sector for 2030 and 30 MMT GHG in 2035. In addition, LSEs are required to include in their individual IRPs a plan for achieving a 30 MMT GHG target in 2030 and 25 MMT GHG target in 2035.

In July 2022, the DCE Board authroized the Executive Director to negotiate and execute an agreement with MRW & Associates, LLC to complete the IRP. Preparation of the IRP included review and evaluation of the requirements provided by the CPUC in formal rulings and informal workshops and webinars. It also involved preparing detailed estimates of the GHG and criteria pollutant emissions of DCE’s portfolio as well as verifying that assigned GHG planning benchmarks are met. The IRP provides an opportunity to communicate DCE’s resource planning policies, objectives, and planning framework to the public and key stakeholder groups. As required by the CPUC, IRP filings are posted on DCE’s website.

DCE staff is now recommending the Board approve the 2022 IRP. It addresses how DCE will meet the statewide targets by managing its portfolio of energy and capacity resources. The IRP incorporates CPUC requirements and new planning targets adopted in early 2022, including:
• Meet more stringent requirements for California’s retail electricity sales to come from renewable energy sources and GHG-free resources;
• Include more solar and battery storage, as well as new long-duration storage, out-of-state wind, and offshore wind resources;
• Ensure system and local reliability on both a near-term and long-term basis, including meeting the near-term and forecast long-term resource adequacy requirements; and • Strengthen the diversity, sustainability, and resilience of electric transmission and distribution systems, and local communities.

DCE’s 2022 IRP also addresses the following objectives:
• Report on recent procurement activity, including expected long-term contracts for renewable energy and compliance with the mid-term reliability (MTR) procurement mandate in D.21-06-035 (MTR Decision);
• Quantify how expected long-term contracts for renewable energy from DCE’s 2020 request for offers (RFO) will help DCE meet California’s contracting requirements, including renewable portfolio standard (RPS) requirements, MTR requirements, and greenhouse gas (GHG) emissions reductions;
• Quantify how much additional “green” power supply is still needed to meet California’s 2030 GHG emissions reduction goals and the DCE Board’s long-term procurement objectives; and
• Guide DCE’s future procurement activities such that all California’s contracting requirements and DCE Board goals are achieved in a timely fashion.

To meet these objectives, DCE has modeled two portfolios as part of the IRP. The first is targeted to meet the 30 MMT GHG emissions target in 2035. The second is targeted to meet the 25 MMT GHG emissions target in 2035. Both portfolios are considered conforming portfolios based on the CPUC’s IRP filing requirements and both meet DCE’s internal goals for green power supply set by its Board. For each portfolio, GHG emissions were estimated using the CPUC’s approved methodology. Further information on the portfolios is provided in Section III of the IRP. The Action Plan in Section IV of the IRP provides further detail on how the IRP will guide DCE’s future procurement activities. Finally, Section V of the IRP discusses lessons learned and makes recommendations for CPUC consideration.

The portfolios were also constructed to capture DCE’s broad green energy procurement goals:
• DCE’s preferred resource types for RPS-qualified procurement for its Carbon Free product are solar, wind, small hydro, and geothermal with carbon-free technology. Biomass/biogas resources are excluded over concern they may have carbon emissions. • DCE only procures non-RPS qualifying carbon-free energy from existing large hydro generation, not nuclear or new large hydro.
• DCE prefers to source green energy from local generation, with preference in the following order: Riverside County, Southern California, all of California, in Western Electricity Coordinating Council (WECC) but outside California.
• DCE only uses portfolio content category one (PCC1) renewable energy credits (RECs) or PCC0 RECs from the voluntary allocation market offer process to satisfy RPS requirements.

DCE procurement efforts emphasize local projects that will bring local jobs and economic benefits to the community. In addition, the portfolios address how DCE will meet California’s RPS requirements of 60% of retail electricity sales to come from renewable energy sources by 2030.

The IRP describes how DCE will procure Resource Adequacy to meet all regulatory requirements for load-serving entities and contribute its fair share to California’s grid reliability.

The next DCE IRP will be due to the CPUC in 2024. Updates in the next IRP will address additional load from participating member agencies, applicable regulatory requirements and state goals for carbon neutrality and clean energy, DCE policy objectives, energy market conditions, anticipated changes in electricity sales, ongoing procurement activities, and any other considerations that may affect how DCE carries out its resource planning.

With the adoption of Resolution 2022-09, DCE staff will work to finalize the 2022 IRP and file it with the CPUC by the November 1 deadline.

Fiscal Analysis: There is no fiscal impact as a result of filing the IRP. The costs of preparing the IRP were covered under the contract with MRW, which was authorized in July 2022 for a not-to-exceed amount of $65,000.

Additional resources were provided under existing staff time and the existing contract with The Energy Authority (TEA).

Attachments:

1. Resolution No. 2022-09

2. DCE 2022 Integrated Resource Plan
RESOLUTION NO. 2022-09

A RESOLUTION OF THE BOARD OF DIRECTORS OF

DESERT COMMUNITY ENERGY
APPROVING DESERT COMMUNITY ENERGY’S
2022 INTEGRATED RESOURCE PLAN
A. Desert Community Energy (“DCE”) is a joint powers authority established on October 30, 2017, for the purpose of implementing a community choice aggregation program under Public Utilities Code Section 366.2.0.

B. The Board has established a set of strategic goals to guide DCE energy procurement to promote renewable energy, carbon-free energy, and greenhouse gas emissions reduction.

C. DCE has ongoing commitments to fulfill regulatory requirements related to energy procurement, including submittal of an Integrated Resource Plan (“IRP”) to the California Public Utilities Commission (“Commission”) pursuant to SB 350 as implemented through Commission Rulemaking Proceeding R.20-05-003 (“IRP Proceeding”).

D. The IRP Proceeding is a central element of the Commission’s planning process through which the electric procurement policies and programs of load serving entities (“LSE”) are examined to ensure that California has a safe, reliable, and cost-effective electricity supply.

E. DCE’s 2022 Integrated Resource Plan has been prepared to address how DCE will meet these strategic goals and regulatory requirements by managing a portfolio of energy and capacity resources.

F. The Integrated Resource Plan documents DCE’s current procurement status and outlines resource planning objectives and future procurement plans.

G. Projecting the resources that an LSE may procure over the planning horizon covered by the IRP is an inexact matter and subject to change. Future projections of resources identified in DCE’s IRP represent a current good-faith projection of such procurement activities over the IRP planning horizon, in consideration of currently applicable mandates and adopted policies of DCE’s Board of Directors.

H. The resources identified in future iterations of DCE’s IRP may change due to new information, changed circumstances, and additional power sources that DCE may acquire in the future.

I. The 2022 Integrated Resource Plan was presented to the Board of Directors at a duly noticed public hearing for its consideration and approval.

NOW, THEREFORE, BE IT RESOLVED BY THE BOARD OF DIRECTORS OF DESERT COMMUNITY ENERGY, AS FOLLOWS:

1. Approves the Desert Community Energy 2022 Integrated Resource Plan.

ADOPTED AND APPROVED by the Board of Directors of Desert Community Energy on this 17th day of October 2022.

ATTEST:
________________________ ________________________
Geoff Kors, Chair Tom Kirk, Secretary
Desert Community Energy Desert Community Energy
AYES: NAYS: ABSENT: ABSTAIN: _
Standard LSE Plan

DESERT COMMUNITY ENERGY
2022 INTEGRATED RESOURCE PLAN
November 1, 2022
1 Table of Contents
I. Executive Summary.................................................................................................................... 4 II. Study Design................................................................................................................................. 5 a. Objectives................................................................................................................................... 6 b. Methodology ............................................................................................................................ 6 i. Modeling Tool(s)................................................................................................................. 6 ii. Modeling Approach ...................................................................................................... 7 III. Study Results...........................................................................................................................10 a. Conforming and Alternative Portfolios........................................................................10 b. Preferred Conforming Portfolios....................................................................................15 c. GHG Emissions Results .......................................................................................................17 d. Local Air Pollutant Minimization and Disadvantaged Communities..........18 i. Local Air Pollutants ..........................................................................................................18 ii. Focus on Disadvantaged Communities ..............................................................19 e. Cost and Rate Analysis .......................................................................................................21 f. System Reliability Analysis ................................................................................................22 g. High Electrification Planning............................................................................................28 h. Existing Resource Planning...............................................................................................28 i. Hydro Generation Risk Management...........................................................................29 j. Long-Duration Storage Planning...................................................................................31 k. Clean Firm Power Planning...............................................................................................32 l. Out-of-State Wind Planning ............................................................................................32 2 m. Offshore Wind Planning ................................................................................................33 n. Transmission Planning........................................................................................................33 IV. Action Plan...............................................................................................................................34 a. Proposed Procurement Activities and Potential Barriers .....................................34 i. Resources to meet D.19-11-016 procurement requirements .......................34 ii. Resources to meet D.21-06-035 procurement requirements, including:
35 a. 1,000 MW of firm zero-emitting resource requirements ................................35 b. 1,000 MW of long-duration storage resource requirements ....................36 c. 2,500 MW of zero-emissions generation, generation paired with storage, or demand response resource requirements ...............................................................36 d. All other procurement requirements...................................................................36 iii. Offshore wind ................................................................................................................36 iv. Out-of-state wind.........................................................................................................37 v. Other renewable energy not described above................................................37 vi. Other energy storage not described above......................................................39 vii. Other demand response not described above................................................39 viii. Other energy efficiency not described above..................................................39 ix. Other distributed generation not described above ......................................39 x. Transportation electrification, including any investments above and beyond what is included in Integrated Energy Policy Report (IEPR)..................40 xi. Building electrification, including any investments above and beyond what is included in Integrated Energy Policy Report (IEPR)...................................40 xii. Other..................................................................................................................................41 3 b. Disadvantaged Communities...........................................................................................42 c. Commission Direction of Actions...................................................................................43 V. Lessons Learned........................................................................................................................43 Glossary of Terms...............................................................................................................................44 4 I. Executive Summary
Desert Community Energy (DCE) was formed to offer a Community Choice Aggregation program in the desert region of Riverside County. DCE is a California joint powers authority located within the geographic boundaries of Riverside County, which formed in 2017 for the purpose of offering rate savings to electricity customers and developing and implementing sustainable energy initiatives that reduce energy demand, increase energy efficiency, and advance the use of clean, efficient, and renewable resources available in the region. DCE is governed by a board of directors that includes an elected representative from each participating city. While DCE formed in 2017, DCE only began serving load on April 1, 2020, for one of its two member agencies, the City of Palm Springs. DCE’s other founding member agency is the City of Palm Desert. The next possible launch date for Palm Desert is 2024.

Cathedral City has withdrawn from DCE effective July 1, 2021.

DCE’s Integrated Resource Plan (IRP) objectives include the following:
• Report on recent procurement activity, including expected long-term contracts for renewable energy and compliance with the mid-term reliability (MTR) procurement mandate in D.21- 06-035 (“MTR Decision”);
• Quantify how expected long-term contracts for renewable energy from DCE’s 2020 request for offers (RFO) will help DCE meet California’s contracting requirements, including renewable portfolio standard (RPS) requirements, MTR requirements, and greenhouse gas (GHG) emissions reductions;
• Quantify how much additional “green” power supply is still needed to meet California’s 2030 GHG emissions reduction goals and the DCE Board’s long-term procurement objectives; and • Guide DCE’s future procurement activities such that all California’s contracting requirements and DCE Board goals are achieved in a timely fashion.

Both portfolios include resources for which DCE has executed contracts as well as planned resources needed to meet midterm reliability (MTR) requirements per D.21-06-035. Both portfolios also include additional local wind generation resources in 2035 to meet DCE’s goal to make its Carbon Free product 100% renewable on an annual basis beginning in 2030 and to meet GHG emissions requirements. (The Carbon Free product is the default product upon DCE customer enrollment and is estimated to be 75% of DCE’s load.) Because the 25 MMT GHG reduction target is lower, this portfolio includes twice the added wind in 2035 (28 MW) than the 30 MMT Portfolio (14 MW).

DCE is also committed to procuring resource adequacy (RA) to meet all CPUC requirements and contribute its fair share to grid reliability. DCE has performed a reliability analysis using marginal effective load carrying capabilities for each conforming portfolio per the CPUC’s instructions. DCE 5 acknowledges it may need to change its future procurement targets to accommodate new RA requirements post RA reform. DCE will report on this in its next IRP.

This IRP was reviewed and approved by the DCE Board of Directors on October 17, 2022, at a public meeting to be ready for submittal by the deadline. This document reflects the intent of the DCE Board of Directors to increase the procurement of renewable energy and continue to offer a 100% carbon-free option. DCE will also comply with the long-term procurement requirements set forth by Senate Bill (SB) 350.

In addition, Board priorities in the near term, include the following:
• Approving contracts to complete DCE’s procurement to meet MTR requirements. • Working with TerraVerde Energy (“TerraVerde”) on a new distributed generation pilot program that enables CCAs to partner with customers in deploying distributed solar plus battery energy storage systems.
• Providing economic development opportunities for local disadvantaged communities.

Longer term, the Board also intends to consider new programs, which could include electric vehicle incentives, building electrification, grid resiliency, and energy efficiency.

DCE will report on its progress with these activities in future IRPs.

DCE has learned much throughout the IRP process, including how critical the role of regulatory uncertainty plays in DCE’s planning. For instance, there were significant changes between the previous IRP plan and this IRP due to the creation of MTR requirements and the introduction of the voluntary allocation market offer (VAMO) process. DCE urges the Commission to reduce this uncertainty to the maximum extent possible prior to setting IRP requirements to avoid a situation where IRPs become out-of-date as soon as they are printed. DCE hopes the creation of the programmatic approach to IRP will be a significant improvement in this regard.

II. Study Design
Desert Community Energy (DCE) was formed to offer a Community Choice Aggregation program in the desert region of Riverside County. DCE is a California joint powers authority located within the geographic boundaries of Riverside County, which formed in 2017 for the purpose of offering rate savings to electricity customers and developing and implementing sustainable energy initiatives that reduce energy demand, increase energy efficiency, and advance the use of clean, efficient, and renewable resources available in the region. DCE is governed by a board of directors that includes an elected representative from each participating city. While DCE formed in 2017, DCE only began serving load on April 1, 2020 for one of its two member agencies, the City of Palm Springs. DCE’s other founding member agency is the City of Palm Desert. The next possible launch date for Palm Desert is 2024.

Cathedral City has withdrawn from DCE effective July 1, 2021.

DCE was established with founding principles, as described in the 2017 joint powers agreement, which guide the development of this IRP and related procurement activities:
6 • Reducing greenhouse gas emissions related to the use of power throughout DCE jurisdictions and neighboring regions;
• Providing electric power and other forms of energy to customers at a competitive cost; • Carrying out programs to reduce energy consumption;
• Stimulating and sustaining the local economy by developing local jobs in renewable and conventional energy; and
• Promoting long-term electric rate stability, energy security, and reliability for residents through local control of electric generation resources.

These broad policy objectives were used as the basis for the more specific energy procurement strategies included in this IRP. These objectives underpin decision making to create conforming resource portfolios within the IRP requirements framework that include use of DCE’s assigned load forecast and GHG emissions targets.
a. Objectives
DCE’s Integrated Resource Plan (IRP) objectives include the following:
• Report on recent procurement activity, including expected long-term contracts for renewable energy and compliance with the mid-term reliability (MTR) procurement mandate in D.21- 06-035 (“MTR Decision”);
• Quantify how expected long-term contracts for renewable energy from DCE’s 2020 request for offers (RFO) will help DCE meet California’s contracting requirements, including renewable portfolio standard (RPS) requirements, MTR requirements, and greenhouse gas (GHG) emissions reductions;
• Quantify how much additional “green” power supply is still needed to meet California’s 2030 GHG emissions reduction goals and the DCE Board’s long-term procurement objectives; and • Guide DCE’s future procurement activities such that all California’s contracting requirements and DCE Board goals are achieved in a timely fashion.

To meet these objectives, DCE has modeled two portfolios as part of this IRP: 1) targeted to meet the 30 MMT GHG emissions target in 2035 (“30 MMT Portfolio”) and 2) targeted to meet the 25 MMT GHG emissions target in 2035 (“25 MMT Portfolio”). Both portfolios are considered conforming portfolios based on the CPUC’s IRP filing requirements and both meet DCE’s internal goals for green power supply set by its Board. The 25 MMT Portfolio will function as an aspirational portfolio that DCE will actively plan towards for meeting its internal GHG emission reduction goals. Further information on the portfolios is provided in Section III of the IRP. The Action Plan in Section IV of the IRP provides further detail on how the IRP will guide DCE’s future procurement activities. b. Methodology
i. Modeling Tool(s)
DCE developed a spreadsheet model to create each portfolio. DCE relied on the CPUC’s Clean System Power (CSP) calculator spreadsheet tool (“CSP calculator”) to estimate the emissions 7 from each portfolio. It did not conduct any production cost modeling or portfolio optimization studies. The independent spreadsheet model and CSP calculator results are attached to this IRP.

DCE also used a spreadsheet to develop a custom hourly dispatch profile for its one-to-one configuration hybrid resources as discussed in more detail in the Modeling Approach section below. This spreadsheet is also attached to the IRP.
ii. Modeling Approach
Load
As part of the 2022 IRP process, each LSE is assigned a retail sales forecast to use for resource planning through 2035 for all conforming portfolios. The assigned forecast is based on the 2021 Integrated Energy Policy Report (IEPR) mid case forecast,1 with modifications by LSEs approved by the Administrative Law Judge in the IRP proceeding. 2 In DCE’s case, only Palm
Springs’ load is included in this IRP. Future IRPs may include expansion, such as if the city of Palm Desert decides to begin serving customers in future years.

Because GHG emissions are calculated on an hourly basis in the CSP calculator, an hourly load shape must be applied to the approved annual load forecast. DCE elected to use a mix of the default load shapes provided in the CSP calculator. DCE assumes a mix of approximately 44% commercial and industrial sales based and 56% non-commercial and industrial sales. This is consistent with the assumption from the previous IRP.

GHG Emissions Targets
As part of the 2022 IRP process, the CPUC planned for two different GHG emissions reduction scenarios for California: one targeting 38 MMT of GHG emissions in 2030 and one targeting 30 MMT of GHG emissions in 2030. Each scenario also included a 2035 GHG emissions target of 30 MMT and 25 MMT respectively. Each LSE was assigned 2030 and 2035 emissions benchmarks corresponding to each of these goals. These benchmarks were used for DCE’s IRP portfolio planning. All four of the assigned emissions benchmarks are shown in the table below.
1 For more information on the IEPR, please refer to https://www.energy.ca.gov/data-reports/reports/integrated-energy-policy-report. 2 See Administrative Law Judge’s Ruling Finalizing Load Forecasts And Greenhouse Gas Emissions Benchmarks For 2022 Integrated Resource Plan Filings, June 15, 2022, https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M485/K625/485625915.PDF. 8 Table 1. DCE 2030 and 2035 GHG Emission Benchmarks, millions of metric tons (MMT). 30 MMT Scenario 25 MMT Scenario
Assigned 2030 Benchmark 0.057 0.043
Assigned 2035 Benchmark 0.044 0.035
DCE Rate Products
DCE currently offers two rate products to its customers. The first option, which was the default option for the April 2020 enrollment, is the Carbon Free product, which provides 100% carbon-free electricity at rates at a premium to SCE’s current rates, and targets this product to be 100% renewable by 2030. The second option is Desert Saver, which offers comparable renewable content to SCE’s base product at a slightly lower rate. Based on recent opt-down activity, DCE assumed 75% of its sales would be Carbon Free and 25% would be Desert Saver for all years between 2024 and 2035. This represents a higher proportion of opt-downs since the 2020 IRP analysis, which modeled 95% Carbon Free.

Green Energy Portfolio Supply Approach
The portfolios were constructed to capture the following broad procurement goals by DCE:
• DCE’s preferred resource types for RPS-qualified procurement for its Carbon Free product are solar, wind, small hydro, and geothermal with carbon-free technology.

Biomass/biogas resources are excluded over concern they may have carbon emissions. • DCE only procures non-RPS qualifying carbon-free energy from existing large hydro generation, not nuclear or new large hydro.
• DCE prefers to source green energy from local generation, with preference in the following order: Riverside County, Southern California, all of California, in Western Electricity Coordinating Council (WECC) but outside California. • DCE only uses portfolio content category one (PCC1) renewable energy credits (RECs) or PCC0 RECs from the voluntary allocation market offer (VAMO) process to satisfy RPS requirements.3
For the current IRP, DCE created two resource portfolios for years 2024-2035. Section III of the IRP provides a specific listing of the resources in both portfolios. The assumptions used to build the portfolios are described here. Both portfolios include the following:
• DCE’s executed long-term contracts for renewable energy. 3 The Board has provided DCE some flexibility to use PCC3 RECs for compliance, but so far has opted not to use PCC3 RECs. No PCC3 RECs were modeled for this IRP. 9 • DCE’s allocation of existing renewable resources procured through the VAMO process from SCE.
• DCE’s allocation of CAM battery storage resources that are eligible for entry into the CSP calculator.
• A generic solar hybrid resource with an online date of 2024 modeled to ensure MTR compliance.

DCE selected a generic solar plus storage resource because it can also supply energy to meet the zero-emission capacity needed in 2025 given the only other resource in DCE’s portfolio capable of meeting that requirement (Deer Creek) is currently at risk. This is discussed further in Section IV.a.ii.c of the IRP.

Once the above resources were modeled, DCE discovered two gaps to fill to meet green energy targets:
• In 2024, DCE was short of the necessary carbon-free energy procurement to meet its internal procurement goals for its Carbon Free product. Therefore, 37 GWh of short-term imported hydro purchases were included in that modeled year, which is consistent with DCE’s current procurement practices for its Carbon Free product. • In 2035, due to contract expiration and load growth, DCE will need to purchase additional renewable energy and additional carbon-free power to meet emissions requirements. DCE added approximately 14 MW of local existing wind and 28 MW of local existing wind for the 30 MMT and 25 MMT scenarios respectively to meet these targets. Local wind was selected in accordance with DCE’s preferred resources, but DCE is open to alternative resources depending on availability as discussed further in Section IV.a.v.

Resources were modeled using the default profiles in the CSP calculator, except for DCE’s hybrid resources. As the CSP calculator documentation explains, the default hybrid or paired solar plus storage resource is modeled as a two-to-one solar to battery configuration, meaning the nameplate rating of the solar resource is twice that of the battery. DCE’s hybrid resources are a one-to-one configuration. The one-to-one configuration’s larger battery size relative to the energy from the solar resource allows it to move a greater fraction of the solar generation out of the midday period subject to the most curtailment. This increases the emissions reduction potential of the resource. The CSP calculator documentation suggests using a custom hourly dispatch profile to capture this additional functionality, so one was developed for this purpose.

The custom dispatch reflects the following constraints:
• The hourly solar profile for new Southern California solar from the CSP calculator was used to model the dispatch of the solar resource prior to any battery charging or discharging.
• Charging was prioritized during midday hours as opposed to early morning or evening. • Discharging was prioritized in early evening hours when the net peak is most likely to occur.
10 • Total dispatch was kept under the interconnection limit, which is equal to the battery capacity.
• The battery was cycled daily and fully charged most days. • A loss factor of 10% was assumed.

The same profile was used for both the Deer Creek resource, which DCE has a signed contract for, and the generic hybrid resource modeled to meet MTR requirements.

Reliability
Both portfolios take a similar approach to meet reliability requirements for IRP planning purposes. Both IRP portfolios include the following:
• Resource adequacy from DCE’s executed long-term renewable contracts and an executed contract for demand response.
• DCE’s allocated share of resources SCE procured on its behalf in response to D.19-11- 016, which DCE has purchased via the one-time allocation opportunity specified in D.22- 05-015.
• Resource adequacy from a generic long-duration battery storage resource and solar + storage hybrid resource modeled to meet MTR compliance. • DCE’s proportional share of resources subject to the cost allocation mechanism (CAM). • DCE’s allocated share of SCE’s demand response resources. • To the extent there is still a gap in RA procurement needs, DCE assumes it will procure System RA using short-term, RA-only contracts from existing gas resources.

These portfolios are discussed in more detail in the System Reliability Analysis Section of the IRP.

III. Study Results
a. Conforming and Alternative Portfolios
DCE has modeled two portfolios, both of which are considered conforming portfolios based on the CPUC’s IRP filing requirements:
• 30 MMT Portfolio: a portfolio that meets DCE’s assigned 30 MMT emissions benchmark in 2035.
• 25 MMT Portfolio: a similar portfolio to the 30 MMT portfolio, but with additional local wind procurement needed to meet DCE’s assigned 25 MMT emissions benchmark in 2035.

Given DCE’s preference for aggressive green energy development, this is DCE’s preferred portfolio of the two.

DCE elected not to model any Alternative Portfolios.
11 The methodology used to construct each portfolio is described in detail in Section IIb above. Here, DCE provides a detailed listing of all resources included in each portfolio.

Resources with Executed Contracts
DCE has executed renewable contracts for three wind projects, one solar hybrid project, and a new geothermal project.
4 It also has executed a contract for demand response, which will be used for MTR compliance and resource adequacy compliance.

Table 2 outlines the various characteristics of each contracted resource:

Table 2. Summary of DCE Resources with Executed Contracts.

Developer Project Product Technology
Contract
Start
Date
Proposed
Size (Solar
Component)
(MW)
Annual
Energy
Delivery
(GWh)
Battery
Storage
Capacity
(MW)
Battery
Storage
Duration
(Hours)
Vesper Energy Deer Creek
Solar I
Energy +
Capacity
New Solar +
Storage Mid 2024 50 181 50 4
Terra-Gen East Wind Energy +
Capacity
Existing
Wind
January
2023 12.6 34 N/A N/A
Terra-Gen
Coachella
Hills Wind
II
Energy +
Capacity
Existing
Wind
May
2021 10.6 36 N/A N/A
Terra-Gen Altwind Energy +
Capacity
Existing
Wind
January
2023 9.8 25 N/A N/A
Resi Station
LLC
(OhmConnect)
Aggregated
DR
Capacity
Only
New
Demand
Response
January
2023 4.5 0 N/A N/A
Cape
Generating
Station I LLC
(Fervo Energy)
Cape
Generating
Station
Energy +
Capacity
New
Geothermal
June
2026 3 24 N/A N/A
VAMO Resources
DCE has procured an allocated share of energy and RECs from SCE’s portfolio of existing renewable resources through SCE’s voluntary allocation in the VAMO process. The amount varies over time, 4 The RDT lists the geothermal contract with a status of "Review" as it was executed after August 2022. 12 starting with 159 GWh in 2023 declining to 99 GWh by 2035 as resources retire. The mix of resource types is shown in the figure below.

Figure 1. Resource mix for DCE’s VAMO resources.

Modified CAM (MCAM) Resources
Pursuant to D.22-05-015, DCE has also elected to purchase its share of resource adequacy from ten battery storage facilities that SCE contracted with to meet D.19-11-016 requirements. All resources are four-hour lithium-ion battery projects with start dates between 2021 and 2023.

Additional Resources
As discussed in Section IIb above, DCE also anticipates needing 37 GWh of additional short-term purchases of existing imported large hydro energy to meet its carbon free procurement goals in 2024.

It also assumes new long-term contracts will be needed per the table below. The long-term contracts for long-duration storage and hybrid resources are included to ensure compliance with MTR requirements, whereas the local wind contract ensures compliance with emissions requirements and DCE’s internal renewable energy goals in 2035. The inclusion of local existing wind to meet emissions requirements is subject to availability, and DCE is open to alternative resource types as discussed in Section IV.a.v.

Solar, 59%
Wind, 37%
Geothermal, 2%
Small Hydro, 1%
DCE VAMO Long-Term Allocation Share
Solar Wind Geothermal Small Hydro
13 Table 3. Additional resources assumed to be procured under long-term contract.

Contract
Begins 30 MMT Portfolio 25 MMT Portfolio
New Resources
Long-Duration
Storage 2026 3.9 MW 3.9 MW
Solar Hybrid 2024

18.5 MW Solar +

18.5 MW 4-Hour
Battery

18.5 MW Solar +

18.5 MW 4-Hour
Battery
Existing
Resources Local Wind 2035 14 MW 28 MW
DCE’s portfolios also include its share of CAM resources and enough capacity from existing gas generation to meet any remaining reliability need as discussed in more detail in the System Reliability Analysis section of the IRP.

Portfolio Results Summary
Figure 4 shows the mix of resources included in the 30 MMT Portfolio over time on an annual energy basis. After the hybrid resources come online in 2024, the amount of green energy procured exceeds DCE’s load until 2031. In 2035, additional wind resources are added to meet emissions requirements and DCE’s renewable energy goals.

Figure 2. DCE 30 MMT Portfolio annual energy resource mix.

Similar results for the 25 MMT Portfolio are shown in the chart below. The results for each portfolio are the same until 2035. The 25 MMT Portfolio includes a larger amount of added wind resources to meet emissions targets, resulting in enough green energy procurement to meet demand that year. -
100
200
300
400
500
600
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 GWh
Imported Large Hydro Solar Wind Geothermal Small Hydro System Power 14 Figure 3. DCE 25 MMT Portfolio annual energy resource mix.

Comparison of New Resources to PSPs
The table below compares the mix of new resources in 2035 in each DCE conforming portfolio to the mix of new resources in the PSPs with updates. The largest difference between the two is the lack of new wind resources in DCE’s portfolio. However, DCE does have considerable existing wind resources in its portfolio. It also has included new out-of-state wind and offshore wind in the portfolio for the high electrification sensitivity, as discussed further in Section III.g of the IRP.

Table 4. Comparison of mix of new resources in PSPs with updates and DCE conforming portfolios.

PSP With Updates DCE
30MMT 25MMT 30MMT 25MMT Both Portfolios
2035 2035 2035 2035 2035 2035
Biomass MW 134 134 0.3% 0.2% - 0.0%
Geothermal MW 1,135 1,135 2.2% 2.0% 3 2.0%
Wind MW 3,562 4,270 7.0% 7.6% - 0.0%
Wind OOS New Tx MW 4,636 4,828 9.1% 8.6% - 0.0%
Offshore Wind MW 4,707 4,707 9.2% 8.3% - 0.0%
Solar MW 17,418 21,794 34.2% 38.7% 69 46.2%
Battery Storage MW 17,350 17,742 34.1% 31.5% 72 48.8%
Pumped Storage MW 1,000 1,000 2.0% 1.8% - 0.0%
Shed DR MW 977 767 1.9% 1.4% 5 3.0%
Total Resources MW 50,920 56,378 100.0% 100.0% 148 100.0% -
100
200
300
400
500
600
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 GWh
Imported Large Hydro Solar Wind Geothermal Small Hydro System Power 15 b. Preferred Conforming Portfolios
The CPUC requires each LSE to select one conforming portfolio to be its preferred conforming portfolio for each assigned GHG emissions benchmark. Because DCE only modeled one conforming portfolio for each benchmark, each portfolio is considered a “preferred conforming portfolio” for IRP compliance purposes. These portfolios are described in detail in Section II.a above, and each should adequately address all requirements in Public Utility Code Section 454.52(a)(1).

GHG Reduction Goals
Based on the output of the Clean System Power calculator, the 2030 and 2035 GHG emissions from DCE’s 30 MMT and 25 MMT conforming portfolios are equal to the Commission’s assigned benchmarks for each portfolio as shown in Table 5 of Section III.c of the IRP. Thus, DCE’s conforming portfolios meets the Section 454.52(a)(1)(A) goal of reducing GHG emissions to meet state GHG reduction mandates.

Renewable Energy
Section 454.52(a)(1)(B) states that portfolios must be composed of at least 60% eligible renewable resources by 2030. DCE has its own internal green energy procurement goals that exceed this minimum standard, including a 100% renewable energy target by 2030 for its Carbon Free product.

Thus, both conforming portfolios source almost 100% of annual energy from renewable resources, exceeding the minimum 60% renewable requirement. This is shown in Figures 2 and 3 in Section III.a of the IRP.

Minimizing Bill Impact
Section 454.52(a)(1)(D) requires LSEs to select resources to minimize the impact of planned procurement on ratepayers’ bills. Rate competitiveness is one of DCE’s rate setting objectives. DCE conducts competitive solicitations to ensure selection of cost competitive resources. DCE expects it can meet its current procurement objectives as embedded in the 25 and 30 MMT portfolios as well as its rate objectives. More discussion of DCE’s rate setting process and objectives can be found in Section III.e of the IRP.

Ensuring System and Local Reliability
Section 454.52(a)(1)(E) states that LSEs must plan to meet system and local reliability as part of their IRPs. DCE has prepared a forecast of how it plans to meet adequate reliability requirements as detailed in Section III.f of the IRP. As discussed in more detail in that section, DCE’s reliability portfolio includes RA purchased under long-term contract from renewable and battery resources as well as short-term RA-only contracts. DCE also commits to meeting all local RA requirements, except for those local RA requirements that must be contracted by the central procurement entity. To date DCE has never been issued a citation for failing to meet RA requirements. 16 Long-Term Contract Procurement
Section 454.52(a)(1)(F) states that portfolios meet long-term contracting requirements under the RPS standard. DCE has modeled 100% of all renewable purchases as secured through long-term contracts, exceeding the minimum requirement.

Diversity, Sustainability, and Resilience of Transmission, Distribution, and Local Communities Consistent with the goals in Section 454.52(a)(1)(G), DCE has selected a diverse set of resources for its conforming portfolios, including solar, wind, small hydro, geothermal, demand response and battery storage resources. DCE also has a preference for developing local renewable energy resources in the Riverside County-Palm Springs area, which would reduce the need for long distance transmission lines to serve its load. DCE also offers a net energy metering program to support behind-the-meter resource development, which can enhance system resilience at the distribution level. DCE is also exploring additional programs to enhance distributed generation development and grid resiliency as described in Section IV.a of the IRP.

Demand-Side Energy Management
Section 454.52(a)(1)(G) states portfolios must have a goal of enhancing demand-side energy management. DCE includes an executed contract for shed demand response (DR) directly in its conforming portfolios. Section IV.a of the IRP also provides a list of energy programs DCE is exploring, which include demand-side energy management programs, such as transportation electrification and energy efficiency. DCE customers also remain eligible for demand-side energy management programs run by SCE.

Minimizing Localized Air Pollutants With Emphasis on Disadvantaged Communities (DACs) Section 454.52(a)(1)(H) requires LSE portfolios work to minimize local air pollutants with an emphasis on DACs. The CSP tool results for localized air pollutants associated with DCE’s conforming portfolios are provided in Section III.d. These emissions are solely from DCE’s system power purchases, which DCE seeks to minimize through its aggressive green energy procurement goals including a 100% renewable energy goal by 2030 for its Carbon Free product.

As noted in Sections III.d and IV.b of the IRP, DCE does not serve any DACs other than Tribal lands as identified using the CalEnviroScreen tool. However, DCE does conduct outreach to low-income communities to encourage enrollment in rate discount programs. Moreover, DCE’s Board has adopted procurement guidelines for improving service to and providing economic development opportunities for local DACs. Further discussion of DCE’s DAC-related activities are described in Sections III.d and IV.b of the IRP.
17 Portfolio Operations
As shown in the next section, the 25 MMT Portfolio has emissions below its assigned 2030 benchmark. DCE does not anticipate this portfolio will operate significantly differently from a reliability perspective depending on whether other LSEs procure in a manner consistent with a 30 MMT or 25 MMT target for the following reasons:
• Its new solar resources will all be backed by battery storage to avoid curtailment. • DCE plans to have RA-only contracts with natural gas resources to support grid reliability.

DCE acknowledges that increased procurement of wind, solar, and battery resources could cause the effective load carrying capability of those resource types to decrease but did not attempt to quantify that for purposes of this IRP. However, DCE emphasizes its commitment to meeting all CPUC reliability requirements in its future procurement. DCE acknowledges the uncertainty in those requirements and may need to change its future procurement targets to accommodate those requirements.
c. GHG Emissions Results
The table below shows the GHG emissions results for both DCE conforming portfolios as output by the CPUC’s CSP calculator. (The load modeling assumptions used for the calculator are described in Section II.b above.) For both portfolios, emissions are below the 2030 benchmarks and equal to the 2035 benchmarks.

Table 5. DCE GHG Emissions Results.

Despite DCE’s aggressive renewable procurement goals in 2030 and 2035, the GHG emissions are not zero. This is because: a) the Desert Saver portfolio is allowed to rely on system power, and b) the 100% renewable target for the Carbon Free portfolio is on an annual basis whereas emissions are calculated on an hourly basis. Some hours have lower emissions reduction potential than other hours in the CPUC’s CSP methodology. Emissions also increase between 2026 and 2035. This is because the procurement is front loaded, such that green energy targets are exceeded in 2026 and 2030, but due to load growth and contract expirations, the surplus is reduced until new procurement is required by 2035 to meet the targets once again.

CO2 Unit 2024 2026 2030 2035
GHG Emissions Benchmark
2030 2035
30 MMT Portfolio MMt/yr 0.037 0.007 0.025 0.043 0.057 0.044 25 MMT Portfolio MMt/yr 0.036 0.009 0.032 0.034 0.043 0.035 18 d. Local Air Pollutant Minimization and Disadvantaged Communities i. Local Air Pollutants
The Coachella Valley desert climate creates excellent conditions for renewable energy development. There is a significant amount of generation already in the Coachella Valley, especially near North Palm Springs. This includes multiple wind farms, several solar farms and natural gas-fired plants, as well as one small hydro plant. The map below from the California Energy Commission shows the general location of these facilities.

Figure 4. Map of local generation resources.

The largest natural gas-fired station in the local area is the Sentinel Energy Center, an 800 MW facility in North Palm Springs.

Table 6 shows emissions results for local criteria air pollutants for each DCE portfolio. Results are generated by the CPUC CSP calculator using assumed hourly emissions rates. All emissions are from system power, and thus will be spread throughout the state of California, and not just the Coachella Valley. DCE expects to reduce reliance on system power through its aggressive renewable energy procurement goals, which is shown graphically in Figures 2 and 3 above.
19 Table 6. DCE Portfolio local criteria air pollutant emissions.

Emissions Total Unit 2024 2026 2030 2035
30 MMT Portfolio PM2.5 tonnes/yr 0.7 (0.3) 0.8 1.8
SO2 tonnes/yr 0.1 (0.0) 0.1 0.2
NOx tonnes/yr 3.0 1.8 2.8 3.0
25 MMT Portfolio PM2.5 tonnes/yr 0.7 (0.4) 0.9 1.5
SO2 tonnes/yr 0.1 (0.0) 0.1 0.1
NOx tonnes/yr 3.0 1.6 2.8 1.8
Both portfolios include plans for contracts with local resources, both new and existing. DCE plans to pursue continued development of new renewable resources in the Coachella Valley area. Such development is expected to reduce emissions and provide local economic development. DCE does not plan to contract with any new local fossil fuel resources. Thus, when customers elect to take service from DCE, it should not increase local emissions, and it may decrease local emissions, depending on how new renewable development impacts the dispatch of local natural gas-fired generation.
ii. Focus on Disadvantaged Communities
DCE’s service territory lies within Riverside County’s Coachella Valley. The valley has long been and continues to be a popular winter tourist destination and is home to a diverse population year-round. It is also known as a retirement haven and has a large population of people over 65.

DCE identified 32 census tracts that at least partially overlap with DCE’s two-city service territory. Excerpt for the Tribal lands discussed below, there are no census tracts within DCE’s service area that CalEPA has designated as disadvantaged communities under SB 535.

However, there are 12 census tracts that at least partially overlap with areas considered low income under AB 1550. Figure 5 shows these areas graphically. 20 Figure 5. Map of low-income communities in DCE service territory.

The DCE service territory also includes Tribal lands of the Agua Caliente Band of Cahuilla Indians (ACBCI). For purposes of the IRP, these Tribal lands are considered a disadvantaged community. Figure 6 shows these Tribal lands and their overlap with the low-income communities in DCE service territory.

Figure 6. Map of Tribal lands and low-income communities in DCE service territory.

Due to the checkerboard pattern of the Reservation lands, these lands are occupied by non-tribal Palm Springs residents and business pursuant to long-term land leases (up to 99 years), and those residents and businesses would not separately qualify as a disadvantaged community.

In June 2022, members of the ACBCI Tribal Council received an update on DCE as part of the annual General Assembly of the Coachella Valley Association of Governments (CVAG).

CVAG provides administrative and staffing services to DCE pursuant to an Implementation and Management Services Agreement. Tribal Council members did not provide any feedback 21 to DCE following that presentation. The Tribe itself is a direct access customer for most of its facilities (offices, casino etc.), and is not enrolled in DCE.

DCE recognizes its responsibility to consider equity issues for disadvantaged communities and others as part of its Least-Cost Best Fit evaluation criteria. Although DCE does not serve any disadvantaged communities based on the definition used for IRP purposes (except for the Tribal lands noted above), the greenhouse gas emissions reduction and air quality improvements associated with DCE’s conforming portfolios are expected to benefit the low income and disadvantaged communities in the region, even though they may be outside the DCE territory.

DCE has also focused on programs that would assist low income and disadvantaged communities. In 2020, DCE initiated an outreach program to encourage income eligible customers who are not currently enrolled in utility discount programs. These programs include California Alternate Rates for Energy (CARE) that reduces energy bills for eligible customers by about 30% and Family Electric Rate Assistance (FERA) which provides an approximate 18% bill discount. CARE, FERA and Medical Baseline customers account for approximately 17% of all customers in Palm Springs.

DCE procurement efforts have emphasized local projects that will bring local jobs and economic benefits to the community. In July 2022, the DCE Board adopted a procurement policy. For procurements that are solely for DCE, it is the policy of DCE to promote employment and business opportunities for local residents and local businesses on all contracts and give preference to local residents, workers, businesses, contractors, and consultants to the extent consistent with the law and the interests of DCE and its customers. e. Cost and Rate Analysis
DCE Rates
Providing power at competitive cost is one of DCE’s founding principles. DCE has adopted rate designs and rates based on SCE’s current rates. Pursuant to the Rate Stabilization Schedule adopted by the DCE Board in November 2020, DCE's currently applied rate protocols include designing Desert Saver rates within a 0 - 1% average total bill discount versus SCE's comparable bundled base product and designing DCE’s 100% Carbon Free rates at a 14% or less average total bill premium versus SCE’s bundled base product (averaged across customer classes). Over time, DCE will consider adopting unique rate designs. Rate setting will typically be done in an open and transparent process culminating in a Board decision. The Board retains the right to change rates at any time if circumstances warrant.

Pursuant to the Rate Stabilization Schedule, DCE has adopted the following rates for domestic (residential) customers effective October 1, 2022: $0.11420 /kWh for Desert Saver customers and $0.

0.15948 /kWh for customers electing Carbon Free power. All other rates, including time-of-use rates and commercial rates are available on DCE’s website.5
5 See https://desertcommunityenergy.org/billing-rates/. 22 DCE offers a NEM program that matches SCE’s rates for surplus production exported to the grid.

Existing SCE NEM customers were automatically enrolled upon DCE’s launch. DCE has also continues SCE’s FERA, CARE, and Medical Baseline programs for low-income customers and those with medical limitations. Such customers are enrolled the lower Desert Saver rate unless they opt up to the carbon free rate
DCE Procurement Costs
DCE works with its portfolio manager, The Energy Authority (TEA), to evaluate contracts, including robust quantitative modeling of costs and risk prior to contract execution. As part of the bid evaluation process, a thorough quantitative analysis is undertaken by DCE and TEA staff to determine which projects (and their specific bid variation(s)) present the highest likelihood of value for DCE’s portfolio. This analysis includes a quantitative scoring of each project bid variation’s marginal net present value, based on the project’s expected generation and resource adequacy value in several different scenarios of future market prices. The quantitative evaluation also looks at how closely each offer’s hourly generation coincides with DCE’s projected hourly load, potential grid congestion costs, and the impact of negative pricing events due to overgeneration.

All planned resources in the IRP conforming portfolios will be subject to this quantitative assessment prior to contract execution, and this analysis will serve to verify whether the resources selected for IRP modeling purposes meet the least cost best fit criteria. For instance, for IRP modeling purposes, the conforming portfolios include additional existing local wind resources in 2035. This is in part due to DCE’s past success in contracting for such resources and knowledge that they meet DCE’s preference for local generation, while also being competitive on cost. But this assumption will be tested for all contracts, and DCE may select an alternative resource type if it finds it scores better in its evaluation.
f. System Reliability Analysis
DCE is committed to procuring resource adequacy (RA) to meet all CPUC requirements and contribute its fair share to grid reliability. DCE has performed a reliability analysis using marginal effective load carrying capabilities (ELCCs) for each conforming portfolio per the CPUC’s instructions, the results of which are shown in the tables and charts below. The reliability portfolios include the following:
• DCE’s allocated share of resources subject to the cost allocation mechanism (CAM). Per the CPUC’s IRP filing requirements instructions, DCE included a share of all SCE CAM resources in the most recent year-ahead CAM list as aggregated by Energy Division Staff. DCE’s allocated share is estimated based on the year-ahead share of the total coincident peak load for the SCE service territory, as assigned in the Commission’s annual resource adequacy process.
• DCE’s allocated share of SCE demand response resources. For purposes of the RA tracking table, the 2023 initial allocation was held constant through 2035 and is reported with contract type online.
23 • DCE’s allocated share of resource adequacy from ten battery storage facilities that SCE contracted with to meet D.19-11-016 requirements. DCE has executed a contract to purchase this resource adequacy pursuant to D.22-05-015. All resources are four-hour lithium-ion battery projects and modeled with contract type online or development in the tracking tables.
• The reliability contribution from DCE’s executed contracts with wind, solar hybrid, geothermal, and demand response resources, excluding resources procured through the VAMO process, which does not supply resource adequacy capacity. • The reliability contribution from DCE’s planned contracts with a new long-duration storage resource and new solar hybrid resource needed to ensure compliance with MTR requirements.
• The reliability contribution from DCE’s planned contract with an existing local wind resource needed to ensure compliance with 2035 emissions targets. • To the extent there is still a gap in reliability procurement needs, DCE assumes it will procure System RA using short-term, RA-only contracts from existing gas resources.

These are planned existing contracts for thermal resources in the tracking tables.

The required tracking tables and charts from the RDTs are provided on the following pages. 24 Figure 7. Reliability chart from RDT for the 30 MMT Portfolio. 0 20
40 60
80 100
120
140
160
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 MW
LSE Capacity by Contract Status
BTM PV
PlannedNew
PlannedExisting
Review
Development
25 Table 7. Reliability table from RDT for 30 MMT Portfolio. 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 LSE reliability need (MW)

133

136

139

133

127

124

121

120

118

116

115

114
ELCC by contract status
(effective MW)
Online

32 33

29 24

21 21

20 19

18 17

15 13
Development

10 60

61 57

52 50

48 44

40 34

29 25
Review

3 3

3 3
PlannedExisting

68 20

20 25

29 29

29 34

39 45

51 57
PlannedNew

18 19

22 21

19 19

18 17

15 14

13 11
BTM PV

4 4

5 4

4 3

3 3

3 4

4 5
LSE total supply (effective MW)

133

136

139

133

127

124

121

120

118

116

115

114
Net capacity position (+ve =
excess, -ve = shortfall) (effective
MW)

-
26 Figure 8. Reliability chart from RDT for the 25 MMT Portfolio. 0 20
40 60
80 100
120
140
160
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 MW
LSE Capacity by Contract Status
BTM PV
PlannedNew
PlannedExisting
Review
Development
27 Table 8. Reliability table from RDT for 25 MMT Portfolio. 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 LSE reliability need (MW)

128

131

134

130

126

129

131

127

123

119

115

112
ELCC by contract status
(effective MW)
Online

30 31

28 23

21 22

24 22

20 18

16 13
Development

10 59

59 57

54 56

58 52

46 37

31 25
Review

3 3

3 3
PlannedExisting

68 21

20 23

25 24

22 29

34 42

48 55
PlannedNew

18 18

22 21

20 21

21 19

17 15

13 11
BTM PV

2 2

2 3

3 3

3 4

4 5
LSE total supply (effective MW)

128

131

134

130

126

129

131

127

123

119

115

112
Net capacity position (+ve =
excess, -ve = shortfall) (effective
MW)

-
28 DCE will report back in future IRPs regarding RA procurement once more is known about how RA requirements will change post RA reform.
g. High Electrification Planning
The CPUC requires LSEs to discuss what additional procurement each would do under a high electrification scenario. DCE anticipates more procurement would be necessary under such a scenario to meet the 2035 emissions targets. DCE expects other LSEs would also need to procure more resources to meet the added load growth and create a competitive environment for new resource development. It is difficult to predict what resource types would be available to DCE under such a scenario, but for long-term planning purposes, DCE expects it may need to procure offshore wind, out-of-state wind or some combination of the two. For purposes of this IRP, DCE assumes a 50/50 energy mix of each resource type would be procured, as shown in the table below. Again, this procurement would be subject to availability and is not known until an actual solicitation for new resources is performed if a high electrification future comes to pass.

Table 9. Additional procurement to meet emissions requirements for high electrification scenario.

Resource Type MWs Annual
GWh
2035 GHG
target
Transmission Zone Substation/Bus Alternative
location
Offshore Wind 11 46.5 Both Morro Bay No preference Humboldt Out of State Wind 10 46.5 Both Wyoming No preference Other States h. Existing Resource Planning
DCE’s conforming portfolios both include existing resources. Inclusion of these resources in the conforming portfolios was not directly influenced by the finding in the previous IRP process that the quantity of existing resources that LSEs included in their plans exceeded the amount of existing resources available on the system. However, DCE has considered the risks of reliance on existing resources and has back-up plans if existing resources are ultimately unavailable.

The type and amount of existing resources has changed significantly from the previous IRP portfolios. The portfolios for this IRP include an additional long-term contract for an existing wind farm, the Altwind Project. They also include existing resources procured through the VAMO process, which was not available to DCE at the time of the previous IRP.

The previous IRP also included a mix of existing and new resources to be procured through a future RFO by 2030. Based on the conforming portfolio modeling in this IRP, after the MTR procurement is completed, DCE will not need additional resources from another RFO until 2035. DCE chose to model the procurement from that RFO to be local existing wind. However, DCE cannot confirm what actual resources will be procured until the future RFO is completed. Because it recognizes that 29 existing resource availability is limited and DCE must compete to secure contracts with these resources, it is currently considering issuing a request for information (RFI) regarding existing wind projects in the Coachella Valley area to gather data on what resources may come available in the 2030-2035 timeframe for future procurement. If existing wind is ultimately unavailable, DCE will consider additional resource types for procurement, including new solar or wind resources, offshore wind, and out-of-state wind.

The IRP reliability portfolios also include planned existing gas-fired resources needed for reliability requirements. The amount of these resources in the portfolios increases between 2025 and 2035, largely due to the reduction in ELCC values for DCE’s hybrid resources over time. However, the amount remains lower than the expected amount in 2024, prior to when the hybrid resources included in the conforming portfolios come online. If existing resources are unavailable, DCE may seek further procurement of new battery resources to integrate the renewable generation in its portfolio and enhance reliability. This will be reported on in future IRPs as more is known about RA requirements post RA reform.
i. Hydro Generation Risk Management
Hydro Generation Risk Background
There are two fundamental issues regarding hydro risk management. The first relates to the limited availability of new hydro development. The second relates to the annual variability in hydro generation. Both will be discussed in turn below.

Hydro Availability
Other than some ongoing development of new large hydro resources in Canada, there is little to no development of new hydro resources in North America. This is largely due to a lack of available sites to build new facilities and concerns over the environmental impacts of creating new impoundments.

However, the existing hydro fleet is expected to continue to provide significant benefits in terms of low-cost, flexible, carbon-free generation. As decarbonization mandates intensify over the coming years, resource planners anticipate hydro generation resources will be in high demand. The problem is that if enough LSEs plan to rely on hydro to meet green power goals, there may be inadequate hydro available to supply this demand, which would ultimately lead to inadequate development of new, non-hydro, carbon-free resources. Thus, for IRP purposes, LSEs are required to assess their reliance on hydro generation.

Hydro Variability
The amount of generation supplied by a hydro facility may vary year-to-year because of variation in water supply. The volume of water available to flow through a hydro turbine determines how much electric generation a hydro facility will produce. In a drought, there will be reduced water supply available for generation. In some hydro systems, large reservoirs can hold water multiple years, including from wet years into dry years, to average out the impact of drought through time.

California’s hydro system does not have such water storage capacity, so the hydro generation varies 30 year-to-year based on hydrological conditions. The chart below shows how during recent droughts, California’s hydro generation has decreased.

Figure 9. California In-State Hydro Generation compared to percent of California land area in at least moderate drought for 15 years.6
Though drought also impacts generation from hydro facilities in the Pacific Northwest region, for purposes of IRP, LSEs are only required to discuss strategies to mitigate the risk from in-state drought.

DCE Hydro Generation Risk
DCE currently relies on imported large hydro for its Carbon Free product portfolio. It also relies on some in-state small hydro resources procured through the VAMO process. It does not rely on in-state hydro resources. DCE is committed to reducing reliance on large hydro over time and instead relying on renewable resources to meet its Carbon Free procurement objectives. Reliance on large hydro is expected to decline as DCE brings new resources online to meet MTR requirements. The conforming portfolios for this IRP show no large hydro reliance after 2025 when its new MTR resources become available.

This is consistent with DCE’s aspirational goal of no large hydro reliance in 2030. DCE is open to continued procurement of small hydro resources, but has limited reliance on small hydro for 2030 and 6 Generation data from CEC at:
https://ww2.energy.ca.gov/almanac/electricity_data/total_system_power.html; Drought index data from: https://www.drought.gov/drought/states/california. 0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
-
10,000
20,000
30,000
40,000
50,000
60,000
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Percent of Land Area (%)
Generation (GWh)
California In-State Hydro Generation (GWh)
Percent of California Land Area In At Least Moderate Drought 31 2035 planning purposes to its share of resources procured through VAMO. DCE has also chosen not to include any new large hydro resources in its portfolio.

The chart below compares the in-state hydro in DCE’s conforming portfolios to DCE’s load ratio share of in-state hydro from the PSP with Updates over time. The small amount of small hydro in DCE’s portfolio is much less than its load ratio share of all in-state hydro. Thus, DCE is much less reliant on hydro generation for meeting GHG emissions compliance goals than California as a whole.

Figure 10. Comparison of hydro reliance in preferred system portfolios (CAISO system) and DCE’s conforming portfolios. Hydro purchases include all small hydro and in-state large hydro.

With regard to risk management from hydro variability and drought, currently DCE relies on imported hydro resources and not in-state hydro resources. To date, DCE has only bought hydro from counterparties guarantying a certain amount or range of amounts of energy delivery. The majority of sellers DCE has procured from are out-of-state generation owners. In-state hydro generation owners are typically investor-owned utilities who are not often offering to sell, perhaps to mitigate their own risk of drought versus a guaranteed delivery contract. For IRP planning purposes, DCE assumes its reliance on imported hydro will continue until resources to meet MTR requirements are online. j. Long-Duration Storage Planning
The CPUC defines long-duration storage as a minimum of 8-hour duration.7 DCE actively sought offers for 8-hour battery storage in its 2020 RFO. However, such resources were not selected due to cost concerns, though DCE did execute a contract for a hybrid resource with 4-hour storage batteries. 7 D.21-06-035, p. 35.
-
10 20
30 40
50 60
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 GWh
Load Ratio Share of PSP With Updates DCE Portfolio
32 DCE has not yet executed a contract with a long-duration storage resource to meet the 2026 long-lead time procurement mandate from the MTR Decision. DCE expects to issue another RFO to secure a contract for such a resource later this year or early next year.

For IRP modeling purposes, DCE did not include any additional long-duration storage beyond what is needed to meet MTR requirements. DCE will consider adding more of this resource to its reliability portfolio post RA-reform when it becomes clearer what additional value the longer duration can bring to DCE’s portfolio.
k. Clean Firm Power Planning
For its MTR compliance procurement efforts, DCE staff worked with other CCAs on a joint procurement, rather than conducting a stand-alone solicitation. As part of this effort, DCE recently executed a contract with Cape Generating Station 1 LLC, a subsidiary of Fervo Energy (Fervo), for a geothermal project located in Beaver County, Utah. DCE’s pro rata share of the project is 3 megawatts (MW) of the 20 MW average net capacity over a 15-year period, with an expected commercial operation date (COD) of June 1, 2026.

Fervo’s geothermal systems make use of horizontal drilling techniques coupled with Organic Rankine Cycle (ORC) generator systems to deliver zero-carbon, zero-emission electricity. ORC power plants are zero-carbon, zero-emission generators. Thermal energy is supplied at high temperature to the ORC by a heat transfer fluid consisting of geothermal brine. The ORC turbogenerator then converts thermal energy from geothermal fluid into electric energy using a turbine coupled with an electric generator. ORC plants are fully dispatchable and flexible, with extremely fast ramping rates of up to 30 percent of nominal capacity per minute. The project will be eligible for RPS certification and inclusion in DCE’s Carbon Free product generation portfolio.

The Cape Generating Station project will be located outside of Milford in Beaver County, Utah, approximately 10-to-15 miles from the Milford Wind Corridor project. That project is connected directly to the Los Angeles Department of Water and Power’s (LADWP) Intermountain Power Project (IPP) Station Switchyard via the Milford Wind Line, which is a dedicated transmission line.

Fervo anticipates negotiating a private user agreement with the owner of that line and entering into a Large Generator Interconnection Agreement with LADWP for an interconnection at the IPP Station Switchyard.

Though DCE did not include additional geothermal resources in its IRP portfolios for this planning cycle, DCE remains open to supporting further geothermal development, especially local development in the Imperial Valley and projects with carbon-free technology. DCE will consider offers from geothermal energy in response to future RFOs, and will report back on this topic in future IRPs.
l. Out-of-State Wind Planning
DCE prefers to procure resources local to its service territory, but it still allowed out-of-state wind developers to submit responses to its 2020 RFO. One out-of-state wind resource did submit an offer, 33 but it was not selected both due to cost and the availability of wind located directly in Palm Springs.

DCE anticipates it will continue to be open to offers for out-of-state wind, but also continue to preference local resources. Thus, for purposes of this IRP, the conforming portfolios include procurement of local wind resources to meet emissions requirements. Out-of-state wind is included in its procurement for the High Electrification sensitivity. m. Offshore Wind Planning
As indicated above in its discussion of out-of-state wind, DCE prefers to procure resources local to its service territory. Thus, for purposes of this IRP, the conforming portfolios include procurement of local wind resources to meet emissions requirements. Offshore wind is only included in its procurement for the High Electrification sensitivity. If a mandate for offshore wind procurement is issued in response to state policy, such as Assembly Bill 525, DCE anticipates it will end up procuring less local wind resources and more offshore wind resources. n. Transmission Planning
DCE does not know of any transmission upgrades needed to ensure interconnection of contracted resources.8 Most of DCE’s contracts are with existing resources. For its new resources, the demand response resource, as a demand-side management resource, will not require transmission upgrades.

Deer Creek plans to interconnect to SCE’s distribution system. The geothermal resource is expected to interconnect through the existing IPP Station Switchyard as discussed above in the Clean Firm Power Planning section of the IRP.

For its planned resources, DCE can provide the following information regarding resource location and transmission upgrades:
• Long-duration storage: DCE has not completed its procurement to meet MTR requirements for new long-duration storage. DCE anticipates this will be for a long-duration battery project in the Southern California Edison territory at a substation where there is available transmission to interconnect storage. DCE would not oppose the Staff modeling an alternative resource location in the CAISO region.
• Imported hydro: DCE actively secures contracts for energy from large hydro resources located outside California and expects such contracts will continue until DCE’s new solar hybrid resources come online. Since these large hydro resources are existing resources, and CAISO currently imports large hydro resources, they are not expected to require transmission upgrades to be deliverable to CAISO.
• Planned hybrid: DCE includes a generic hybrid resource in its conforming portfolios for MTR compliance. DCE does not state a location preference for this resource and does not object to the CPUC and CAISO modeling this resource in any location within CAISO. 8 For CAM and MCAM resources in DCE's portfolio, DCE assumes SCE will report on transmission upgrade status as it is the LSE that procured those resources originally. 34 • Existing local wind: DCE has modeled a new contract with an existing local wind resource to meet emissions requirements in 2035. As an existing resource, DCE does not anticipate the resource would require transmission upgrades.
• Existing natural gas generation: DCE does not have a location preference for resources that support its RA only contracts with existing natural gas generation.

DCE's preference for local generation resources is consistent with its past IRPs and one of the reasons its planned resource locations do not align one-to-one with the PSP or TPP portfolios.

However, DCE's preference is only a preference. DCE is willing to execute contracts for resources outside of its local area if the resource meets its least-cost best-fit criteria, as demonstrated by its recent contract with a geothermal resource in Utah.
9 Transmission availability will be one of the
factors considered for all future contracts DCE executes.

IV. Action Plan
Potential barriers for resource procurement which include weather, regulatory uncertainty, market risks, load changes, and resource development risks. Development risk refers to the risk that a project may not reach commercial operation due to site control failure, permitting failure, financing failure, construction failure, or other failure on the path from a project’s conception to its commercial operation date. To reduce this risk, DCE has chosen projects that had clear paths forward for each of these potential obstacles (e.g., completed site control) and that had strong development teams with a history of bringing new renewable projects to commercial operation in California.

A narrative description of risks and barriers to each of the resource types included in DCE’s portfolio is discussed in more detail below.
a. Proposed Procurement Activities and Potential Barriers A detailed action plan for each resource type in DCE’s conforming portfolios is described in the sections below.
i. Resources to meet D.19-11-016 procurement requirements DCE was not assigned a procurement obligation in D.19-11-016. As such, SCE was responsible for procurement to meet these requirements on its behalf. Pursuant to D.22-05- 015, DCE has elected to purchase its share of resource adequacy from ten battery storage facilities that SCE contracted with to meet D.19-11-016 requirements. This purchase contract will ensure DCE customers receive the RA benefits of this procurement. Based on data from SCE, seven of the ten resources are online and supplying reliability benefits to the grid. DCE will monitor the development of the remaining three, which are scheduled to come online by August of next year.
9 DCE's least-cost best-fit criteria are discussed In the Cost and Rate Analysis section of the IRP. 35 ii. Resources to meet D.21-06-035 procurement requirements, including:

Since its launch in April 2020, DCE has issued two RFOs: an RFO for Long Term Renewable Energy projects issued in May 2020 (“2020 RFO”), which resulted in four Power Purchase Agreements (“PPAs”) and an all-source solicitation for projects to support its Mid-Term Reliability procurement requirement (“MTR RFO”). The 2020 RFO was developed to meet both DCE’s RPS compliance requirements and the DCE Board’s own internally set renewable and clean energy goals. Two of the PPAs executed pursuant to this RFO resulted in contracts eligible for MTR compliance. The MTR RFO was issued in conjunction with two other CCAs with the primary goal of procuring projects to meet the state’s reliability requirements and a secondary goal of potentially bringing additional long-term renewable power into DCE’s portfolios. DCE executed two contracts subsequent to this RFO.

The MTR RFO has occurred in a market significantly different from the one experienced in the 2020 RFO, with a large number of buyers in search of specific project characteristics and a limited number of viable projects offered by developers to meet these buyers’ needs, in part due to the global supply chain issue and other macro factors, as well as other hindrances, such as delays in project interconnection and lack of transmission. Therefore, DCE expects to issue another RFO to complete its procurement to meet MTR requirements in the coming months.
a. 1,000 MW of firm zero-emitting resource requirements DCE recently executed a contract with Cape Generating Station 1 LLC, a subsidiary of Fervo Energy (Fervo), for a geothermal project located in Beaver County, Utah. DCE’s pro rata share of the project is 3 megawatts (MW) of the 20 MW average net capacity over a 15-year period, with an expected commercial operation date (COD) of June 1, 2026. Development risk was evaluated during the shortlisting process of the Fervo Energy project. Fervo’s development team members have delivered more than 2 GW of power generation combined over the last decade, including a 49.9 MW Hudson Ranch geothermal power plant, which came online in 2012. Fervo is well funded and has a track record of raising corporate equity. Fervo has full site control of the project area, which has been achieved through geothermal resource leases signed with surface and mineral owners; which will allow Fervo to develop, construct, own and operate the project.

To ensure the project is on track to reaching commercial operation, Fervo is contractually obligated to provide a progress report to DCE every three months until the construction start date. After the construction start date, DCE will be provided a monthly progress report until the COD, and agrees to regularly scheduled meetings between representatives of DCE and Fervo to review such monthly reports and discuss Fervo’s construction progress.
36 Fervo is also obligated to meet development milestones, and report on the progress towards achieving these milestones. Progress reports will include whether Fervo has met or is on target to meet the milestones, identification of any missed milestones, including the cause of delay, and a detailed description of Fervo’s corrective actions to achieve the missed milestones and all subsequent milestones by the COD. These milestones include: evidence of site control, CEC Pre-Certification obtained, receipt of Phase I and Phase II Interconnection study results for Fervo’s Interconnection Facilities, executed interconnection agreement, expected construction start date, initial synchronization, network upgrades completed, and COD.
b. 1,000 MW of long-duration storage resource requirements DCE has not yet completed its long-duration storage procurement. It expects this will be part of its upcoming solicitation for more MTR compliant resources later this year or early next year. DCE received limited responses for long-duration storage projects in the Request for Proposals that launched in January 2022. Of these responses, the projects were either unviable or ineligible. This is similar to what has been observed with other CCAs that have solicited for this product type. DCE will continue to explore all options available to meet its long-duration storage procurement mandate for MTR compliance, and look at pursuing another joint solicitation effort, partnering with other CCAs that have over-procured capacity, and reaching out to developers that may have the ability to increase capacity on projects that are currently in development. c. 2,500 MW of zero-emissions generation, generation paired with storage, or demand response resource requirements
In response to its 2020 RFO, DCE signed one PPA for Vesper Energy’s Deer Creek Solar I project, which is a 50 MW solar + 50 MW/200MWh storage project expected to reach commercial operation and enter DCE’s portfolio in mid-2024. This project is expected to be able to meet MTR compliance needs as a zero-emissions resource. d. All other procurement requirements
DCE executed a contract with a new wind resource (Coachella Hills Wind II) In response to its 2020 RFO that is eligible to supply some MTR compliance benefit for the 2023 procurement tranche and is already online. This resource, along with DCE’s contract with Resi Station LLC for aggregated demand response is expected to supply enough capacity to meet the 2023 tranche obligation. Meeting the 2024 and 2025 obligation is expected to be achieved with a mix of Deer Creek and/or another contract to be executed pursuant to the aforementioned future RFO for MTR procurement. iii. Offshore wind
DCE does not include offshore wind in its conforming portfolios but does include offshore wind as a resource for the additional procurement needed in a high electrification scenario. 37 Currently, DCE does not preclude purchases of offshore wind but has a preference for development of local wind resources. In a high electrification scenario, DCE anticipates the increased competition for resources will make it more likely DCE will need to procure resources from outside the local area in addition to local resources. It may also be required to procure offshore wind in response to state policy. In a high electrification scenario, DCE will issue solicitations for green energy resources that will include consideration of offshore wind among other resource options. Any procurement in response to state policy will be targeted to meet the requirements of the policy, and DCE will provide more information about this procurement in future IRPs once more about state policy requirements is known.

Offshore wind does face development barriers and risks, as there is little development experience with offshore wind in North America and little development of floating platforms worldwide. There are also transmission limitations in Humboldt County, one of the areas under consideration for new offshore wind. DCE expects a broad statewide effort will be necessary to overcome these barriers and facilitate large offshore wind developments. DCE will work with state policymakers and regulators to effectuate any future offshore wind policies.
iv. Out-of-state wind
As with offshore wind, DCE does not include out-of-state wind in its conforming portfolios, but does include out-ot-state wind as a resource for the additional procurement needed in a high electrification scenario. Currently, DCE does not preclude purchases of out-of-state wind but has a preference for development of local wind resources. In a high electrification scenario, DCE anticipates the increased competition for resources will make it more likely DCE will need to procure resources from outside the local area in addition to local resources. In a high electrification scenario, DCE will issue solicitations for green energy resources that will include consideration of out-of-state wind among other resource options.

The largest barrier to out-of-state wind development is securing long-distance transmission to deliver these resources. DCE will monitor any efforts by state policymakers, regulators, and the CAISO to facilitate new transmission paths to bring more out-of-state wind to California.
v. Other renewable energy not described above
As part of its forecasting and procurement processes, DCE considers the overall diversity and reliability of its renewable portfolio, including such characteristics as a resource’s dispatchability and available capacity. DCE also reviews the respective risks – including development and generation risk – associated with short and long-term purchases as part of its forecasting and procurement processes. These efforts will lead to a more diverse resource mix, address grid integration issues, and provide value to the local community. 38 Presently, DCE is focused on managing its existing portfolio of utility-scale renewable and storage resources to meet the clean and renewable energy targets for the City of Palm Springs and completing its procurement to meet all MTR requirements.

DCE expects to meet the RPS compliance obligations during the coming 10-year timeframe through a mixture of planned long-term contracts with renewable resources resulting from DCE’s 2020 RFO, election to receive its long-term allocation through SCE’s Voluntary Allocation, future RFOs, local renewable programs, and some amount of short-term renewable procurement. The exact portfolio selected to meet DCE’s Board-adopted clean energy goals as well as its mandated RPS compliance may vary depending on legislative and policy changes, technological innovation and the dynamic California and WECC energy landscape. The preferences of the DCE Board and the community it represents will also be considered, as well as other key local developments, such as the potential launch of Palm Desert.

DCE is directly accountable to the community that it serves. DCE strongly supports and is committed to meeting the state’s GHG reduction and renewable procurement goals. As a member of CalCCA, DCE supported the passage of SB 100 and has fully incorporated the procurement requirements of the state’s RPS program into its overall procurement strategy.

Within the multi-year compliance period structure of the RPS, DCE is well-positioned to meet the procurement quantity requirements, portfolio balance requirements, and long-term procurement requirements of the RPS program. To meet its community green energy goals DCE plans an additional Voluntary Margin of Over-Procurement (VMOP) which exceeds DCE’s risk assessment-derived minimum margin of procurement.

Beyond the state’s minimum renewable procurement requirements, DCE’s governing Board has established additional green and renewable energy goals. Specifically, the DCE Board has directed that DCE acquire a portfolio comprised of 100 percent carbon-free generation for its Carbon Free product; all current customers served by DCE in the City of Palm Springs were opted into this Carbon Free product as the default, and the vast majority of DCE’s customers have chosen to remain with this premium product, rather than opting down into the Desert Saver product which provides cost-savings to customers while still meeting RPS compliance requirements. The DCE Board has approved a schedule for issuing renewable solicitations, executing contracts with existing resources, and bringing new projects online in time to meet the applicable RPS targets. This timeline is supported by DCE’s procurement team and the collective procurement experience of the CCA community and is shorter and more flexible than the investor-owned utilities’ procurement cycles.

VAMO Resources
DCE has entered into a voluntary allocation agreement with SCE for purchase of energy and RECs through the VAMO process. This represents a cost-effective way for DCE to secure access to resources to meet RPS requirements at low risk, since these resources are already online.
39 Other Existing Local Wind
DCE includes additional local wind resources in its portfolio to meet GHG reduction and RPS requirements in 2035. There has already been significant development of wind resources in Riverside County, especially near North Palm Springs and in the San Gorgonio pass. (Refer to map in Figure 4, above.) Many of the turbines in the San Gorgonio pass are older and in need of repowering. The repowering could increase the total wind produced from the region. DCE is considering issuing an RFI to explore options for purchasing existing wind resources as contracts for these resources expire. If local wind is not available, DCE will consider purchasing wind in other locations, including out-of-state or offshore wind or additional solar and storage, carbon-free geothermal, or small hydro. vi. Other energy storage not described above
All energy storage in DCE’s portfolios is used for meeting MTR requirements and is discussed above.
vii. Other demand response not described above
At the direction of its Board, DCE began partnering with OhmConnect in late 2021 on its demand response project, which encourages residential customers to save money on their energy bill. OhmConnect pays residential customers to conserve power during times of peak demand, sells the collective energy savings back to the grid, and then passes their earnings onto their users in the form of cash and prizes. On December 6, 2021, the CVAG Executive Committee authorized the Executive Director to enter into a similar partnership agreement with OhmConnect for the CVAG areas within the SCE service territory, including the City of Palm Desert. The energy savings generated during the early September 2022 heat wave by OhmConnect customers including shared customers with DCE helped maintain grid stability and prevent statewide rolling outages. viii.Other energy efficiency not described above
DCE is exploring the potential for an application to the CPUC for a CCA Energy Efficiency program. More on this topic will be provided in future IRPs as more is known about the program.
ix. Other distributed generation not described above
DCE is working with TerraVerde Energy (“TerraVerde”) on a new distributed generation pilot program. TerraVerde has developed a PPA program that enables CCAs to partner with customers in deploying distributed solar plus battery energy storage systems—with no up-front cost. Under this program framework, the CCA engages target customers with a cost savings and energy resiliency offering in the form of a solar plus battery PPA. Upon securing Letters of Interest from a cohort of customers, the CCA then procures a 40 Distributed Solar + Battery PPA from developers for projects sited at these customer locations. Based on the pricing received from the market, the CCA then offers the electricity generated from the deployed solar PV systems to their cohort of customers at a rate that is higher than the Distributed PPA rate but lower than the customer's standard (or otherwise applicable) rate. Thus, the CCA charges the customer a PPA rate that is lower than the customer’s gross bill savings, but at a rate higher than what the CCA is paying to the vendor, thus generating both customer net savings, and CCA net revenue.

The pilot program focuses on large non-residential customers whose energy use profiles and rates structures indicate a high probability of both the customer and DCE benefiting from DERs at their locations. DCE staff is working with its consultants to confirm the interest of the target customers, prepare a robust financial analysis together and develop program documents that minimize risks to DCE. If these efforts are successful, and DCE can procure favorable terms for a PPA with developers following an RFP, the DER program could be operational by the second half of 2024.

Should DCE choose to proceed with the pilot program, procurement through the RFP process and contract negotiations would occur over a three-month period, followed by project design and permitting over another three-month period. The vendor’s completion of the projects would be expected to occur within 24 months of signature of the agreement with TerraVerde. Any procurement in this pilot program will be discussed in future RPS Procurement Plans and IRPs. While this procurement may come at an above-market cost, it would support the DCE Board’s stated interest in pursuing local renewable energy projects within the DCE community.
x. Transportation electrification, including any investments above and beyond what is included in Integrated Energy Policy Report (IEPR) DCE is developing load curves that reflect expected increases in load due to both transportation electrification and building electrification for use in developing its load forecasts. Transportation electrification planning for DCE’s service area considers personal light duty vehicles and electrification of fleets. DCE is also encouraging expanded vehicle charging stations, which are powered by DCE’s carbon free electricity. xi. Building electrification, including any investments above and beyond what is included in Integrated Energy Policy Report (IEPR)
As stated above, DCE is developing load curves that reflect expected increases in load due to both transportation electrification and building electrification for use in developing its load forecasts. More will be discussed on this topic in future IRPs if the Board adopts a new building electrification program.
41 xii. Other
DCE will continue its procurement efforts to meet MTR requirements. If Palm Desert or any other city commit to joining DCE’s CCA load service area, then it is anticipated that DCE will issue another RFO at that time. Barring any addition to DCE’s load service territory, the timing of DCE’s next RFO will depend on the outcome of DCE’s MTR procurement and the timing of when Deer Creek achieves commercial operation. It will also depend on load growth due to electrification and state policy changes such as dedicated procurement to meet offshore wind goals and to support the possible closure of the Aliso Canyon natural gas storage field. DCE will provide an updated procurement timeline as part of its next IRP.

DCE’s communities have been and will continue to be active participants in local environmental planning, including electric service improvements. The City of Palm Springs has been a regional leader in sustainability efforts. Energy Action Plans and Climate Action Plans adopted in 2013, and its 2016 Sustainability Plan confirm Palm Springs’s commitment to using renewable energy to reduce greenhouse gas emissions and addressing climate change at the local level. Establishment of a Community Choice Aggregation program was identified in Palm Springs 2016 Sustainability Plan. Encouraging renewable energy is an essential component of the City’s path towards sustainable development, carbon neutrality, and a resilient community. In February 2022, the Palm Springs City Council adopted its FY 2021/22 Strategic Plan, which includes achieving reductions in greenhouse gas (GHG) emissions and maintaining and expanding outreach of DCE’s 100% carbon-free model. A May 2021 inventory determined that the participation in DCE’s carbon free energy by the City of Palm Springs and its residents and businesses helped the city meet its state-mandated goal of reducing 2020 GHG emissions levels below those of 1990. Without the reductions achieved by DCE, Palm Springs’ projected 2020 GHG emissions would have been approximately 4.4% above 2010 levels.

As part of the FY 2021/22 Strategic Plan, the Palm Springs Office of Sustainability is currently working on two energy-related ordinances, with technical assistance from DCE staff. The first ordinance would require single-family buildings and dwelling units in multifamily buildings built before 2011 undergoing additions, alterations or remodels to make certain targeted energy efficiency upgrades, where applicable and feasible, to bring them closer to 2022 California Energy Code provisions, including the 2022 Energy Code’s electric-ready requirements for new residential buildings. The second ordinance would establish requirements for the use of renewable and carbon free energy by new and existing nonresidential buildings and indoor and greenhouse cannabis cultivation sites in Palm Springs. This ordinance would also add energy and water efficiency standards for indoor and greenhouse cannabis cultivation sites. The Office of Sustainability expects to bring these ordinances before City Council in late 2022 or early 2023.

Palm Desert has also been a long-time regional leader in energy efficiency and sustainability. Though the city has not yet launched as part of the DCE CCA program, DCE’s policies are consistent with Palm Desert’s Plan adopted by its City Council in 42 August 2022. The Environmental Initiatives Plan tracks the city’s ongoing projects in energy conservation, green buildings, and green transportation, including a proposal to replace or solarize carport structures at City Hall and two other city facilities. The total project is estimated to be 979 KW. Two additional sites are being considered. Success of the Environmental Initiatives Plan should lead to decreased utility usage, utility costs, and GHG emissions.

The Coachella Valley Association of Governments (CVAG) is currently working with its partner agencies, Western Riverside Council of Governments and San Bernardino Associated Governments, in the implementation of the Inland Regional Energy Network (I-REN), whose business plan the CPUC approved in November 2021. I-REN will provide opportunities for energy efficiency and energy-related workforce development in our region, as well as opportunities for collaborative efforts with DCE, which shares staff with I-REN through CVAG.

The Board also intends to consider new programs, which could include electric vehicle incentives, building electrification, grid resiliency, and energy efficiency.

In addition, DCE offers its customers Net Energy Metering (NEM) service with grid exports compensated at a rate that matches the rate offered by SCE. This will allow customers to pair cleaner grid electricity with renewable energy generated on their premises and potentially support solar-related jobs in the region. The DCE Board plans to explore ways to incentivize rooftop solar, community solar, and other renewable electric generation systems in the future. In February 2022, the DCE Board adopted a resolution that supports protecting and expanding rooftop solar via a strong succeeding Net Energy Metering tariff and expanding clean energy access by making it easier, not harder, for people to adopt rooftop solar and energy storage in order to meet California's ambitious clean energy targets and deploy solar in all communities and households, particularly those struggling to pay for electricity.

Finally, customers will continue to have access to important electric rate discounts under programs such as Medical Baseline and CARE/FERA, as well as potential new programs specific to DCE customers.
b. Disadvantaged Communities
As noted in Section III.d.ii, excerpt for the Tribal lands, there are no census tracts within DCE’s service area that CalEPA has designated as disadvantaged communities under SB 535. However, there are 12 census tracts that at least partially overlap with areas considered low income under AB 1550. In order to increase its outreach to residents of those low-income communities, DCE’s Board recently named to DCE’s Community Advisory Committee (CAC) two members from those communities in Palm Springs, one of whom is Hispanic. The CAC members are regularly kept informed of DCE’s efforts to procure renewable resources and reduce GHG emissions in its service area through DCE’s Carbon Free product, and they have an opportunity to provide their feedback at meetings of DCE’s Board and the CAC. DCE’s Board considers input from the CAC and other 43 community members in its decision-making. Because DCE’s direct procurement efforts since its launch in 2020 has been for renewable resources, DCE does not have specific metrics to prioritize the minimization of criteria air pollution in disadvantaged communities.

DCE has an active social media presence in both English and Spanish to promote energy conservation and GHG emissions reductions. In addition, DCE has recently resumed participation in community events. Events at which DCE intends to have an information booth include the Desert AIDS Walk Health and Wellness Village in late October 2022 and the Black History Month Parade and Town Fair in February 2023.
c. Commission Direction of Actions
DCE does not seek any direction from the Commission at this time.

Though DCE supports efforts to create a programmatic approach to IRP procurement, the number of options of new procurement programs provided in the recent Staff Options Paper make it difficult to speculate as to how the programmatic approach would impact DCE’s planning at this time. DCE is an active member of CalCCA, which is providing more feedback to the Commission on the Staff Options Paper in formal comments to the Commission.

V. Lessons Learned
Through the first three IRP cycles, DCE has learned how critical the role of regulatory uncertainty plays in DCE’s planning. For instance, there were significant changes between the previous IRP plan and this IRP due to the creation of MTR requirements and the introduction of the VAMO process. DCE urges the Commission to reduce this uncertainty to the maximum extent possible prior to setting IRP requirements to avoid a situation where IRPs become out-of-date as soon as they are printed. DCE hopes the creation of the programmatic approach to IRP will be a significant improvement in this regard. 44 Glossary of Terms
Alternative Portfolio: LSEs are permitted to submit “Alternative Portfolios” developed from scenarios using different assumptions from those used in the Preferred System Plan with updates. Any deviations from the “Conforming Portfolio” must be explained and justified.

Approve (Plan): the CPUC’s obligation to approve an LSE’s integrated resource plan derives from Public Utilities Code Section 454.52(b)(2) and the procurement planning process described in Public Utilities Code Section 454.5, in addition to the CPUC obligation to ensure safe and reliable service at just and reasonable rates under Public Utilities Code Section 451.

Balancing Authority Area (CAISO): the collection of generation, transmission, and loads within the metered boundaries of the Balancing Authority. The Balancing Authority maintains load-resource balance within this area.

Baseline resources: Those resources assumed to be fixed as a capacity expansion model input, as opposed to Candidate resources, which are selected by the model and are incremental to the Baseline.

Baseline resources are existing (already online) or owned or contracted to come online within the planning horizon. Existing resources with announced retirements are excluded from the Baseline for the applicable years. Being “contracted” refers to a resource holding signed contract/s with an LSE/s for much of its energy and capacity, as applicable, for a significant portion of its useful life. The contracts refer to those approved by the CPUC and/or the LSE’s governing board, as applicable. These criteria indicate the resource is relatively certain to come online. Baseline resources that are not online at the time of modeling may have a failure rate applied to their nameplate capacity to allow for the risk of them failing to come online.

Candidate resource: those resources, such as renewables, energy storage, natural gas generation, and demand response, available for selection in IRP capacity expansion modeling, incremental to the Baseline resources.

Capacity Expansion Model: a capacity expansion model is a computer model that simulates generation and transmission investment to meet forecast electric load over many years, usually with the objective of minimizing the total cost of owning and operating the electrical system. Capacity expansion models can also be configured to only allow solutions that meet specific requirements, such as providing a minimum amount of capacity to ensure the reliability of the system or maintaining greenhouse gas emissions below an established level.

Certify (a Community Choice Aggregator Plan): Public Utilities Code 454.52(b)(3) requires the CPUC to certify the integrated resource plans of CCAs. “Certify” requires a formal act of the Commission to determine that the CCA’s Plan complies with the requirements of the statute and the process established via Public Utilities Code 454.51(a). In addition, the Commission must review the CCA Plans to determine any potential impacts on public utility bundled customers under Public Utilities Code Sections 451 and 454, among others.

Clean System Power (CSP) methodology: the methodology used to estimate GHG and criteria pollutant emissions associated with an LSE’s Portfolio based on how the LSE will expect to rely on system power on an hourly basis.
45 Community Choice Aggregator: a governmental entity formed by a city or county to procure electricity for its residents, businesses, and municipal facilities.

Conforming Portfolio: the LSE portfolio that conforms to IRP Planning Standards, the 2030 LSE-specific GHG Emissions Benchmark, use of the LSE’s assigned load forecast, use of inputs and assumptions matching those used in developing the Reference System Portfolio, as well as other IRP requirements including the filing of a complete Narrative Template, a Resource Data Template and Clean System Power Calculator.

Effective Load Carrying Capacity: a percentage that expresses how well a resource is able avoid loss-of-load events (considering availability and use limitations). The percentage is relative to a reference resource, for example a resource that is always available with no use limitations. It is calculated via probabilistic reliability modeling, and yields a single percentage value for a given resource or grouping of resources.

Effective Megawatts (MW): perfect capacity equivalent MW, such as the MW calculated by applying an ELCC % multiplier to nameplate MW.

Electric Service Provider: an entity that offers electric service to a retail or end-use customer, but which does not fall within the definition of an electrical corporation under Public Utilities Code Section 218.

Filing Entity: an entity required by statute to file an integrated resource plan with CPUC.

Future: a set of assumptions about future conditions, such as load or gas prices.

GHG Benchmark (or LSE-specific 2030 GHG Benchmark): the mass-based GHG emission planning targets calculated by staff for each LSE based on the methodology established by the California Air Resources Board and required for use in LSE Portfolio development in IRP.

GHG Planning Price: the systemwide marginal GHG abatement cost associated with achieving a specific electric sector 2030 GHG planning target.

Integrated Resources Planning Standards (Planning Standards): the set of CPUC IRP rules, guidelines, formulas and metrics that LSEs must include in their LSE Plans.

Integrated Resource Planning (IRP) process: integrated resource planning process; the repeating cycle through which integrated resource plans are prepared, submitted, and reviewed by the CPUC Long term: more than 5 years unless otherwise specified.

Load Serving Entity: an electrical corporation, electric service provider, community choice aggregator, or electric cooperative.

Load Serving Entity (LSE) Plan: an LSE’s integrated resource plan; the full set of documents and information submitted by an LSE to the CPUC as part of the IRP process.

Load Serving Entity (LSE) Portfolio: a set of supply- and/or demand-side resources with certain attributes that together serve the LSE’s assigned load over the IRP planning horizon. 46 Loss of Load Expectation (LOLE): a metric that quantifies the expected frequency of loss-of-load events per year. Loss-of-load is any instance where available generating capacity is insufficient to serve electric demand. If one or more instances of loss-of-load occurring within the same day regardless of duration are counted as one loss-of-load event, then the LOLE metric can be compared to a reference point such as the industry probabilistic reliability standard of “one expected day in 10 years,” i.e. an LOLE of 0.1.

Maximum Import Capability: a California ISO metric that represents a quantity in MWs of imports determined by the CAISO to be simultaneously deliverable to the aggregate of load in the ISO’s Balancing Authority (BAA) Area and thus eligible for use in the Resource Adequacy process. The California ISO assess a MIC MW value for each intertie into the ISO’s BAA and allocated yearly to the LSEs. A LSE’s RA import showings are limited to its share of the MIC at each intertie.

Net Qualifying Capacity (NQC): Qualifying Capacity reduced, as applicable, based on: (1) testing and verification; (2) application of performance criteria; and (3) deliverability restrictions. The Net Qualifying Capacity determination shall be made by the California ISO pursuant to the provisions of this California ISO Tariff and the applicable Business Practice Manual.

Non-modeled costs: embedded fixed costs in today’s energy system (e.g., existing distribution revenue requirement, existing transmission revenue requirement, and energy efficiency program cost).

Nonstandard LSE Plan: type of integrated resource plan that an LSE may be eligible to file if it serves load outside the CAISO balancing authority area.

Optimization: an exercise undertaken in the CPUC’s Integrated Resource Planning (IRP) process using a capacity expansion model to identify a least-cost portfolio of electricity resources for meeting specific policy constraints, such as GHG reduction or RPS targets, while maintaining reliability given a set of assumptions about the future. Optimization in IRP considers resources assumed to be online over the planning horizon (baseline resources), some of which the model may choose not to retain, and additional resources (candidate resources) that the model is able to select to meet future grid needs.

Planned resource: any resource included in an LSE portfolio, whether already online or not, that is yet to be procured. Relating this to capacity expansion modeling terms, planned resources can be baseline resources (needing contract renewal, or currently owned/contracted by another LSE), candidate resources, or possibly resources that were not considered by the modeling, e.g., due to the passage of time between the modeling taking place and LSEs developing their plans. Planned resources can be specific (e.g., with a CAISO ID) or generic, with only the type, size and some geographic information identified.

Qualifying capacity: the maximum amount of Resource Adequacy Benefits a generating facility could provide before an assessment of its net qualifying capacity.

Preferred Conforming Portfolio: the conforming portfolio preferred by an LSE as the most suitable to its own needs; submitted to CPUC for review as one element of the LSE’s overall IRP plan.

Preferred System Plan: the Commission’s integrated resource plan composed of both the aggregation of LSE portfolios (i.e., Preferred System Portfolio) and the set of actions necessary to implement that portfolio (i.e., Preferred System Action Plan).
47 Preferred System Portfolio: the combined portfolios of individual LSEs within the CAISO, aggregated, reviewed and possibly modified by Commission staff as a proposal to the Commission, and adopted by the Commission as most responsive to statutory requirements per Pub. Util. Code 454.51; part of the Preferred System Plan.

Short term: 1 to 3 years (unless otherwise specified).

Staff: CPUC Energy Division staff (unless otherwise specified).

Standard LSE Plan: type of integrated resource plan that an LSE is required to file if it serves load within the CAISO balancing authority area (unless the LSE demonstrates exemption from the IRP process).

Transmission Planning Process (TPP): annual process conducted by the California Independent System Operator (CAISO) to identify potential transmission system limitations and areas that need reinforcements over a 10-year horizon.

Item 7C

STAFF REPORT
Subject: October 2022 Rate Adjustment Summary
Contact: Don Dame, DCE Energy Consultant
Recommendation: Information
Background: On November 16, 2020, the Desert Community Energy (DCE) Board adopted a Rate Stabilization Schedule (RSS). The RSS authorizes staff to revise DCE retail rates in response to changes in Southern California Edison (SCE) rates and the Power Charge Indifference Adjustment (PCIA), or exit fee, to maintain DCE Board-approved rate policy guidelines.

The RSS became effective on December 1, 2020. The Board’s currently applied rate policies include designing Desert Saver rates within a 0-1% average total bill discount versus SCE's comparable bundled base product and designing DCE’s 100% Carbon Free rates such that DCE’s primary residential rate class, “Domestic,” is at a 14% total bill premium versus SCE’s comparable bundled base product.

Effective October 1, 2022, SCE implemented a generation rate increase averaging approximately

3.4%. SCE’s average bundled residential customer bill is estimated to increase approximately $2.16 monthly, based on average consumption of 564 kWh / month. SCE’s average bundled CARE/FERA residential customer bills increase by the same dollar amount while maintaining an approximately 32% average total bill discount.

Working within DCE Board-approved financial policies and procedures, DCE has implemented a corresponding rate adjustment effective October 1, 2022. Other Community Choice Aggregators (CCAs) in SCE territory and throughout California are implementing similar changes to maintain targeted rate levels. These DCE rate adjustments are required to meet increasing supply costs and build adequate reserves, while remaining within Board rate guidelines.

The RSS requires DCE staff to prepare a summary report describing RSS-related rate adjustments and provide this information at the next scheduled Board meeting after such adjustments are implemented. This staff report provides that summary.

October 2022 Rate Adjustment Details:
• Rate Adjustment Effective Date: October 1, 2022
• Desert Saver average total bill discount compared to SCE's bundled base power product estimated to be within 0 – 1%.
• 100% Carbon Free total bill premium for residential customers is 14% compared with SCE's bundled base power product.
• The rate comparison forecast period utilized is October 1, 2022 – September 30, 2023. • Calculations and estimates are based on known and forecast costs and revenues throughout the rate comparison period.

Staff continues to work with the California Community Choice Association (CalCCA) and other California CCAs to collectively address costs, legislative items and California Public Utilities Commission (CPUC) actions impacting CCAs. In addition, DCE will continue to highlight the product choices that customers have as part of continued community engagement efforts. DCE’s Desert Saver product continues to be the lowest cost choice for electricity in Palm Springs, and the Carbon Free rate is comparable to similar products offered by many CCAs across California.

Fiscal Analysis: DCE's October 2022 rate adjustment is designed to fully recover all power supply and operating costs, build financial reserves, address cash flow requirements, and ensure that DCE maintains fiscal health.

Both SCE and DCE customer generation rates have increased. The average monthly bill of SCE bundled residential customers will increase about $1.27 per $100 bill, DCE Desert Saver residential customer bills will increase about $1.25 per $100 bill, and DCE Carbon Free residential customer bills will increase about $1.55 per $100 bill.

ITEM 8A DESERT COMMUNITY ENERGY BOARD
FY2022-2023 ATTENDANCE RECORD

FEB MAR APR MAY JUNE
City of Palm Desert ✓ * ✓
City of Palm Springs ✓ * ✓
Absent
No Meeting *
Voting Members JUL* AUG SEP OCT NOV DEC JAN
* July was a special meeting. The regular July meeting was cancelled.

DESERT COMMUNITY ENERGY

UNAUDITED FINANCIAL STATEMENTS

STATEMENT OF NET POSITION
AS OF AUGUST 31, 2022
ASSETS
Unrestricted Funds
Operating Account - 200,000.00 200,000.00
Money Market Account 69,321.22 - 69,321.22
DDM Marketplace Sweep Account 2,519,901.44 - 2,519,901.44 Lockbox Account 983,993.59 265,015.81 1,249,009.40
Total Unrestricted Funds 3,573,216.25 465,015.81 4,038,232.06 Restricted Funds
Restricted Cash (PPA Collateral) - 1,680,000.00 1,680,000.00 SCE FSR Letter of Credit Collateral 147,000.00 - 147,000.00 Total Restricted Funds 147,000.00 1,680,000.00 1,827,000.00 Total Cash 3,720,216.25 2,145,015.81 5,865,232.06
Accounts Receivable
Southern California Edison - 9,692,648.39 9,692,648.39
Southern California Edison (Escrow Account) - 2,623,647.39 2,623,647.39 Total Accounts Receivable - 12,316,295.78 12,316,295.78 Accrued Accounts Receivable - 4,876,083.53 4,876,083.53 Allowance for Doubtful Accounts - (2,353,138.98) (2,353,138.98) TOTAL ASSETS 3,720,216.25 16,984,256.14 20,704,472.39

LIABILITIES
Accounts Payable
Ace Printing 4,448.61 4,448.61 8,897.21
Best, Best & Krieger LLP 1,891.50 5,674.50 7,566.00
Burke Rix Communications - 8,239.89 8,239.89
Calpine Energy Solutions LLC - 44,263.50 44,263.50
Coachella Hills Wind LLC - (271,914.96) (271,914.96)
Donald D. Dame 270.81 812.44 1,083.25
Davis Farr LLP 375.00 1,125.00 1,500.00
MRW & Associates, LLC 906.56 2,719.69 3,626.25
River City Bank 8,234.50 - 8,234.50
SOCAL Edison - 86,522.92 86,522.92
The Energy Authority - 7,748,934.14 7,748,934.14
Total Accounts Payable 16,126.98 7,630,825.72 7,646,952.70 Due to Other Governments
Coachella Valley Assoc. of Governments 2,174.92 6,524.75 8,699.66 Total Due to Other Governments 2,174.92 6,524.75 8,699.66 Taxes Payable
Utility Users Tax - 675,622.17 675,622.17
Electric Energy Surcharge - 39,778.86 39,778.86
Total Taxes Payable - 715,401.03 715,401.03
Vendor Security Deposits
Terra-Gen - 1,680,000.00 1,680,000.00
OhmConnect - 180,000.00 180,000.00
Total Vendor Security Deposits - 1,860,000.00 1,860,000.00 Total Current Liabilities 18,301.90 10,212,751.50 10,231,053.39 Non Current Liabilities
Loans Payable (long term)
River City Bank Line of Credit (expires 02.01.2025) - 2,200,000.00 2,200,000.00 Total Loans Payable - 2,200,000.00 2,200,000.00
Total Non Current Liabilities - 2,200,000.00 2,200,000.00 TOTAL LIABILITIES 18,301.90 12,412,751.50 12,431,053.39

NET POSITION
Restricted Net Position 147,000.00 - 147,000.00
Unrestricted Net Postion 3,554,914.36 4,571,504.64 8,126,419.00 Net Position 3,701,914.36 4,571,504.64 8,273,419.00
TOTAL LIABILITIES AND NET POSITION 3,720,216.25 16,984,256.14 20,704,472.39

GENERAL PALM SPRINGS TOTAL

DESERT COMMUNITY ENERGY

UNAUDITED FINANCIAL STATEMENTS

REVENUES, EXPENSES, AND CHANGES IN NET POSITION
FOR THE PERIOD FROM JULY 1, 2022 TO AUGUST 31, 2022

REVENUES
Electricity Sales - 18,389,900.60 18,389,900.60
Energy Market Settlements - 448,349.29 448,349.29
Other Revenue - - -
Investment Income 2,092.30 - 2,092.30
TOTAL REVENUES 2,092.30 18,838,249.89 18,840,342.19

EXPENSES
Cost of Electricity
Electricity Purchase - 10,644,787.44 10,644,787.44
Resource Adequacy - 2,778,650.00 2,778,650.00
Low Carbon Settlement - - -
Renewable Energy Credit Settlement - 134,106.10 134,106.10 Market Charges - 869,939.47 869,939.47
Total Cost of Electricity - 14,427,483.01 14,427,483.01 Accounting / Bank Services 11,418.73 11,418.73 22,837.45 Office Supplies 300.00 900.00 1,200.00
Legal Services 3,675.13 11,025.38 14,700.50
Professional Services
AJ Gallagher & Co Insurance 234.75 234.75 469.50
Davis Farr LLP 375.00 1,125.00 1,500.00
SOCAL Edison - 18,318.87 18,318.87
Total Professional Services 609.75 19,678.62 20,288.37
Insurance
- Directors & Officers 4,120.00 4,120.00 8,240.00
- General Liability 300.00 300.00 600.00
Total Insurance 4,420.00 4,420.00 8,840.00
Consultants
Calpine Energy Solutions 22,119.96 66,359.89 88,479.85
Don Dame - 2,166.50 2,166.50
MRW & Associates, LLC 1,813.13 1,813.13 3,626.25
The Energy Authority - 240,740.04 240,740.04
White Rabbit Group - - -
Total Consultants 23,933.09 311,079.55 335,012.64
Outreach
Burke Rix Communications - 10,340.00 10,340.00
Total Outreach - 10,340.00 10,340.00
Postage
Ace Printing 2,698.07 2,698.07 5,396.14
Total Printing 2,698.07 2,698.07 5,396.14
Printing
Ace Printing 2,812.20 2,812.20 5,624.39
Total Printing 2,812.20 2,812.20 5,624.39
Customer Programs - - -
Sponsorships 206.25 618.75 825.00
Technology Costs 299.00 299.00 598.00
Registrations/Memberships
- 21,124.00 21,124.00
CA Community Choice Association - - -
Total Registration/Memberships - 21,124.00 21,124.00
Bad Debt - 551,697.02 551,697.02
Interest Expense - 12,345.78 12,345.78
TOTAL EXPENSES 50,372.20 15,387,940.10 15,438,312.30
Excess of Revenues over Expenses (48,279.90) 3,450,309.79 3,402,029.89 Net Position - Beginning of the Period 3,750,194.26 1,121,194.85 4,871,389.11 Net Position - End of the Period 3,701,914.36 4,571,504.64 8,273,419.00

GENERAL PALM SPRINGS TOTAL
WREGIS Western Renewable Energy Generation Information System Desert Community Energy
Unaudited Statement of Net Position Prev Year Comparison As of August 31, 2022
Aug 31, 22 Aug 31, 21 $ Change % Change
ASSETS
Current Assets
Checking/Savings
1100 · Unrestricted Funds
1105 · Operating Account -8099 200,000 2,635,063 (2,435,063) 1 (92%) 1107 · ICS Account -0995 0 668,747 (668,747) (100%)
1109 · DDM Marketplace Sweep - 0991 2,519,901 0 2,519,901 100% 1115 · Lockbox -4446 1,249,009 36,581 1,212,428 3,314%
Total 1100 · Unrestricted Funds 3,968,910 3,340,391 628,519 19% 1199 · Restricted Funds
1110 · Money Market -5470 1,749,321 1,745,910 3,411 0%
1120 · FSR Letter of Credit Collateral 147,000 147,000 0 0% 1125 · Debt Service Reserve Account - 200,000 (200,000) (100%) Total 1199 · Restricted Funds 1,896,321 2,092,910 (196,589) (9%) Total Checking/Savings 5,865,231 5,433,301 431,930 8%
Accounts Receivable
1221 · Accounts Receivable 12,316,296 9,581,982 2,734,314 29% 1223 · Accrued Accounts Receivable 4,876,084 3,801,562 1,074,522 28% Total Accounts Receivable 17,192,380 13,383,544 3,808,836 28% Other Current Assets
1225 · Allowance for Doubtful Accounts (2,353,139) (1,452,065) (901,074) 2 (62%) Total Other Current Assets (2,353,139) (1,452,065) (901,074) (62%) Total Current Assets 20,704,472 17,364,780 3,339,692 19% TOTAL ASSETS 20,704,472 17,364,780 3,339,692 19%

LIABILITIES & NET POSITION
Liabilities
Current Liabilities
Accounts Payable
2110 · Accounts Payable 7,646,953 8,834,242 (1,187,289) (13%) 2112 · Accrued Accounts Payable - 27,637 (27,637) (100%) 2120 · Due to Other Governments 8,700 563,921 (555,221) (98%) Total Accounts Payable 7,655,653 9,425,800 (1,770,147) (19%) Other Current Liabilities
2230 · Taxes payable
2231 · Utility Users Tax (UUT) 675,622 773,446 (97,824) (13%) 2232 · Electric Energy Surcharge 39,779 45,181 (5,402) (12%) Total 2230 · Taxes payable 715,401 818,627 (103,226) (13%) 2250 · Loans Payable Short-Term - 375,000 (375,000) (100%) 2260 · Vendor Security Deposits
2262 · PPA Development Security 1,680,000 1,680,000 - 0% 2263 · Contract Development Deposit 180,000 - 180,000 3 100% Total 2260 · Vendor Security Deposits 1,860,000 1,680,000 180,000 11% Total Other Current Liabilities 2,575,401 2,873,627 (298,226) (10%) Total Current Liabilities 10,231,054 12,299,427 (2,068,373) (17%) Long Term Liabilities
2300 · Non-current Liability
2350 · Loans Payable - Long Term 2,200,000 - 2,200,000 100% Total 2300 · Non-current Liability 2,200,000 - 2,200,000 100% Total Long Term Liabilities 2,200,000 - 2,200,000 100%
Total Liabilities 12,431,054 12,299,427 131,627 1%

Page 1 of 2 ends

Desert Community Energy
Unaudited Statement of Net Position Prev Year Comparison As of August 31, 2022
Aug 31, 22 Aug 31, 21 $ Change % Change
Net Position
31000 · Restricted Net Position 147,000 347,000 (200,000) (58%) 32000 · Unrestricted Net Position 4,724,389 4,927,861 (203,472) (4%) Net Position 3,402,030 (209,508) 3,611,538 1,724%
Total Net Position 8,273,419 5,065,353 3,208,066 63%
TOTAL LIABILITIES & NET POSITION 20,704,473 17,364,780 3,339,693 19% 1 2
3 Bank accounts were realigned to earn interest on operating funds in excess of $200k with an automatic sweep to the DDM account.

The application for approximately $466k CAPP 2.0 COVID-19 relief funding for utility customers is in process.

OhmConnect contract development security deposit.

Page 2 of 2 ends

Desert Community Energy
Unaudited Changes to Net Position Prev Year Comparison
July through August 2022
Jul - Aug 22 Jul - Aug 21 $ Change % Change
Revenue
5010 · Electricity Sales
5011 · Carbon Free 15,116,714 12,004,908 3,111,806 26%
5012 · Carbon Free- CARE / FERA 265 1,233,851 (1,233,586) 1 (100%) 5013 · Desert Saver 3,272,922 766,193 2,506,729 327%
Total 5010 · Electricity Sales 18,389,901 14,004,952 4,384,949 31% 5100 · Other Revenue
5120 · Energy Market Settlements 448,349 310,265 138,084 45% Total 5100 · Other Revenue 448,349 310,265 138,084 45%
5900 · Investment Income 2,092 828 1,264 153%
Total Revenue 18,840,342 14,316,045 4,524,297 32%
Expense
4100 · Cost of Electricity
4105 · Electricity Purchase 10,644,787 9,984,561 660,226 7% 4110 · Resource Adequacy Settlement 2,778,650 2,268,000 510,650 23% 4115 · Low Carbon Settlement - 424,085 (424,085) (100%) 4120 · Renewable Energy Cr. Settlement 134,106 254,445 (120,339) (47%) 4125 · Market Charges 869,939 789,399 80,540 10%
Total 4100 · Cost of Electricity 14,427,482 13,720,490 706,992 5% 4200 · Accounting / Bank Services 22,837 101 22,736 2 22,511% 4353 · Insurance 8,840 7,690 1,150 15%
4423 · Office Supplies 1,200 - 1,200 100%
4425 · Legal Services 14,701 - 14,701 100%
4431 · Professional Services 20,288 13,103 7,185 55%
4432 · Consultants 335,013 339,826 (4,813) (1%)
4433 · Outreach Services 10,340 7,258 3,082 42%
4435 · Technology Costs (IT) 598 - 598 100%
4440 · Postage 5,396 1,010 4,386 434%
4441 · Printing 5,624 3,406 2,218 65%
4450 · Sponsorships 825 - 825 100%
4455 · Customer Programs - 20,615 (20,615) (100%)
4500 · Registrations/Memberships 21,124 20,142 982 5%
4610 · Interest Expense 12,346 25,155 (12,809) (51%)
4750 · Bad Debt Expense 551,697 366,758 184,939 50%
Total Expense 15,438,311 14,525,554 912,757 6%
Excess of Revenue over Expenses 3,402,031 (209,509) 3,611,540 1,724% 1 2
CARE/FERA was discontinued and converted to Desert Saver River City Bank fees for RLOC

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Desert Community Energy Board of DirectorsOctober 17, 2022

Desert Community Energy Board of Directors
October 17, 2022