1 The January 15, 2026,
Regular Meeting of the
Board of Directors
will Begin Shortly
[email protected]
2 Board of Directors
Regular Meeting
January 15, 2026
3 Welcome and Call to Order
4 Roll Call
55 6
Land Acknowledgement
7 Special Presentations and Introductions
8 Aida Castañeda
Recognition of Outgoing
Community Advisory Committee Member
9 Kaily Wakefield
Paralegal
Welcome to New Community Power Staff
Paige Spounias-Flynn
Procurement Analyst
10 Items to be Withdrawn or
Reordered on the Agenda
11 Public Comment on non-Agenda Items
12 Consent
Calendar
1. Approve December 11, 2025, Meeting Minutes
2. Receive and File Update on Programs
3. Receive and File Update on Power Services
4. Receive and File Update on Customer Operations
5. Receive and File Update on IT and Data Analytics
6. Receive and File Update on Human Resources
7. Receive and File Update on Marketing, Public Relations, and Local Government Affairs
8. Receive and File Treasurer’s Report for Period Ending October 31, 2025
9. Receive and File Update on Regulatory and Legislative Affairs
10. Approve Marketing Community Initiative Partnership with TEGNA through December 31, 2026, in an amount not to exceed $175,044, and authorize the Chief Executive Officer to execute the agreement
11. Approve Request for Board Members Travel to CalCCA Annual Conference May 12- 14, 2026, in Sacramento, CA
12. Approve Amendment No. 1 to the Professional Services Agreement with Financial Credit Network to remove the Not-To-Exceed Amount for Debt Collection Services for San Diego Community Power
13 Public Comment on Consent Calendar
14 Regular
Agenda
13. Election of Officers for Community Power for Calendar Year 2026
14. Review and approve 2026 Community Power rates, to be retroactively effective as of January 1, 2026
15. Approve Professional Services Agreement with PS Hummingbird for Enterprise Resource Planning Implementation and Other As-Needed Services for a Total Not-To-Exceed Contract Amount of $1,000,000
16. Approve Professional Services Agreement with Tenaska Power Services for Scheduling Coordinator Services
15 Item No. 13
Election of Officers
for Community Power
for Calendar Year
2026
Presenter:
Chair Lawson-Remer
Recommendation: Receive and file
Community Power’s revisions to the existing
Net Energy Metering Tariff/Program (NEM)
and to the existing Net Billing Tariff (NBT) and
Community Power’s establishment of the new
Net Billing Tariff Virtual (NBT-V) and a Net
Billing Tariff Aggregation (NBT-A) for all new
customers who elect this and who have
installed onsite generation on or after
February 15, 2024 that qualifies for the tariff
and for existing customers transitioning out of
the Virtual Net Energy Metering Tariff (VNEM)
or the Net Energy Metering Aggregation Tariff
(NEMA) following the conclusion and/or
termination of their NEMA legacy period.
Recommendation:
Elect a Chair and Vice Chair for Calendar Year
2026.
16 Public Comment on
Item No. 13
17 Item No. 13
Board Members
Comments or
Questions
Election of Officers for Community
Power for Calendar Year 2026
Recommendation:
Elect a Chair and Vice Chair for Calendar Year
2026.
18 Item No. 14
Review and Approve
2026 Community
Power Rates, to be
Retroactively
Effective as of January
1, 2026.
Presenters:
Karin Burns, Chief Executive Officer
Lucas Utouh, Senior Director of Data Analytics and Cust. Ops Tim Manglicmot, Director of Finance
Recommendation: Receive and file
Community Power’s revisions to the existing
Net Energy Metering Tariff/Program (NEM)
and to the existing Net Billing Tariff (NBT) and
Community Power’s establishment of the new
Net Billing Tariff and a Net Billing Tariff
Aggregation (NA) for all new customers who
elect this and who have installed onsite
generation on or after February 15, 2024 that
qualifies for the tariff and for existing
customers transitioning out of the Virtual Net
Energy Metering Tariff (VNEM) or the Net
Energy Metering Aggregation Tariff (NEMA)
following the conclusion and/or termination of
their NEMA legacy period.
Recommendation:
Review and Approve 2026 Community Power
Rates, to be Retroactively Effective as of
January 1, 2026.
19 Rate Development
Policy Objectives Competitiveness
Equity
Simplicity Reserves
Stability
Cost
Recovery
Cost of
Service
Avoid Cost-Shifting
Transparency
20 Rate Development Timeline
Board adopted
2025 rates,
effective
retroactively on
February 1, 2025.
February 7, 2025
SDG&E filed the
Application for
Approval of the
2026 Energy
Resources
Recovery Account
(ERRA) Forecast.
May 15, 2025
Commission
adopted SDG&E’s
General Rate Case
(GRC) Phase 2.
September 18,
2025
SDG&E filed
Update to the
2026 ERRA
Forecast.
October 14, 2024
SDG&E filed its
advice letter for
Preliminary
Consolidated
Filing to
Implement
January 1, 2026
Electric Rates.
November 17,
2025
Staff briefed
committees and
the Board on 2026
rate projections
and schedule.
December 2025
SDG&E filed its
advice letter for
Final Consolidated
Filing to
Implement
January 1, 2026
Electric Rates.
December 31,
2025
SDG&E’s
implemented 2026
generation,
delivery, and the
Power Charge
Indifference
Adjustment (PCIA)
rates.
January 1, 2026
Community
Power Board
adopts 2026
rates, effective
retroactively on
January 1, 2026.
January 15, 2026
SDG&E is expected
to file an advice
letter on its GRC
Phase 2 rate design
changes.
March 1, 2026
Community
Power Board
adopts GRC Phase
2 rate design
changes, effective
on April 1, 2026.
March 26, 2026
SDG&E and
Community Power
implement GRC
Phase 2 rate design
changes.
April 1, 2026
21 Community Power Rate Components
Community
Power
Rates
SDG&E
Generation Rates
PCIA Franchise
Fee
January 2026 SDG&E
~14% average increase
January 2026 SDG&E
Varies by Customer & Vintage
Customer Classes:
Residential
Small Commercial
Medium & Large C&I
Agriculture
Lighting
Vintage Year
Vintage 2020 – Phase 1 & 2
Vintage 2021 – Phase 3
Vintage 2022 – Phase 4
Unchanged 2026 SDG&E
1.1% x SDG&E’s Gen rates
January 2026
Community Power Gen rates
22 Rate Trifurcation
• Community Power's Phase 1 and 2 customers
(vintage 2020), Phase 3 customers (vintage 2021),
and Phase 4 customers (vintage 2022) are all
charged a different PCIA by SDG&E because they
are assigned different vintage years.
• Due to the substantial deltas expected between
PCIA vintages 2020, 2021, and 2022, staff
continues to recommend trifurcation of three sets
of rates to the Board to ensure customer equity.
• This trifurcation of Community Power rates by
vintage maintains a fair, equitable, and balanced
rate structure for all customers.
Illustrative Trifurcation Example
Competitive Factor (Discount) 4% 4% 4%
Rates ($/kWh) Vintage 2020 Vintage 2021 Vintage 2022
SDG&E Commodity Rate 0.1800 0.1800 0.1800
PCIA 0.0100 0.0280 0.0540
Franchise Fees (FF) 0.0020 0.0020 0.0020
Resulting Illustrative Community Power Rate 0.1590 0.1410 0.1150 Community Power Rate + PCIA + FF 0.1710 0.1710 0.1710
23 Scenarios Evaluated
Scenario 1: Conservative Scenario 2: Balanced
Staff Recommended Scenario 3: Uncertain
PowerOn Premium/Discount
Compared to SDG&E 3% Discount 4% Discount 5% Discount
PowerBase Premium/Discount
Compared to SDG&E 10% Discount 10% Discount 10% Discount CY2026 Net Revenue $1,026 million $1,014 million $1,002 million CY2026 Operating Expenses
Energy1 $911 million
Nonenergy2 $78 million
CY2026 Net Operating Margin
(Potential Reserve Contribution) 3 $37 million $25 million $13 million Focuses on
Customer Affordability?
Maintains Reserves?
Meets Credit Rating Metrics?
1Energy costs are projections based on contracts, forward energy curves, and projected load as of December 31, 2025. 2Nonenergy includes nonenergy cost projections as of December 31, 2025, and includes capital investment plan contributions. 3Net Operating Margin is Net Revenue minus Operating Expenses and excludes debt service and finance and investment income. 24 Risk Factors to Community Power
Category Risk Estimate of Adverse
Outcome
Market Price Benchmark Volatility* PCIA & Generation Rate “SNAPBACK” $420 million Energy Costs* Wholesale, Load and Open Position Volatility $245 million Load* Participation Rate Drops to 86% $51 million
Uncollectibles* Increase in uncollectibles to 5% $36 million Prepay Savings Loss Prepay savings loss to unforeseen event $12 million Operations Legal Loss $5 million
Operations Force Majeure or Cybersecurity Event $2 million Total $771 million
(Approx. 278 DCOH)
* Risk categories may fluctuate marginally due to changes in market conditions; risk factors and estimates are projected based for a single year and not cumulatively across all years 25 PCIA is Largest Risk to Community Power
Category Risk Estimate of Adverse
Outcome
Market Price Benchmark Volatility* PCIA & Generation Rate “SNAPBACK” $420 million Energy Costs* Wholesale, Load and Open Position Volatility $245 million Load* Participation Rate Drops to 86% $51 million
Uncollectibles* Increase in uncollectibles to 5% $36 million Prepay Savings Loss Prepay savings loss to unforeseen event $12 million Operations Legal Loss $5 million
Operations Force Majeure or Cybersecurity Event $2 million Total $771 million
(Approx. 278 DCOH)
PCIA and Generation Rates
comprise Community
Power’s biggest risk
* Risk categories may fluctuate marginally due to changes in market conditions; risk factors and estimates are projected based for a single year and not cumulatively across all years 26 Stress Test – PG&E PCIA/Rates, Uncollectibles, Participation $.0M
$100.0M
$200.0M
$300.0M
$400.0M
$500.0M
$600.0M
$700.0M
$800.0M
3/1/2021
6/1/20219/1/2021
12/1/2021
3/1/2022
6/1/20229/1/2022
12/1/2022
3/1/2023
6/1/20239/1/2023
12/1/2023
3/1/2024
6/1/20249/1/2024
12/1/2024
3/1/2025
6/1/20259/1/2025
12/1/2025
3/1/2026
6/1/20269/1/2026
12/1/2026
3/1/2027
6/1/20279/1/2027
12/1/2027
Base Case (Reserves)
Stress Test (Reserves)
Reserves drop to $238 million or
99-DCOH with: 2026 PG&E PCIA,
increase in uncollectibles, and
decrease in participation.
Note: This was an Illustrative example based on the stress test presented to the Board in December 2026. 27 Additional Volatility From 2026 Rate Structural Changes • Reduces seasonal volatility in commodity rates.
• Increase winter revenue and decrease summer revenue.
• Overall revenue decrease for Community Power.
Seasonality Adjustment
for Residential Rates
(effective 1/1)
• Extends existing weekday Super Off-Peak (10am - 2pm), currently applied to March and April, to the full year. • Reduces prices to encourage load-shifting to the mid-day period.
• Overall revenue decrease for Community Power.
Time-of-Use (TOU)
Super Off-Peak
Extension (effective 4/1)
• Creates a new Medium Commercial customer class for
customers with demand between 20-200 kW.
• Impacts pending SDG&E 3/1 filing.
New Medium
Commercial Customer
Class (effective 4/1)
28 Projected Residential Bill Impact for Rate Scenarios Change by Billing Component (TOU-DR-1) SDG&E PowerBase PowerOn Renewable Portfolio Content* (%) 41% RPS* 45% RPS* 53% RPS + 2% Carbon Free* Discount (%) N/A 10% 5% 4% 3%
Change in Generation ($) $(13.17) $(16.04) $(14.45) $(13.92) $(13.40) Change in PCIA ($) $16.25 $16.78 $16.78 $16.78 $16.78
Change in Franchise Fees ($) ($0.08) ($0.08) ($0.08) ($0.08) ($0.08) Change in Delivery ($) $8.27 $8.27 $8.27 $8.27 $8.27
Change in Total Monthly Generation, PCIA, Franchise Fees ($) $3.00 $0.66 $2.25 $2.78 $3.30 Change in Total Monthly Delivery ($) $8.27 $8.27 $8.27 $8.27 $8.27 Change in Total Monthly Bill ($) $11.27 $8.93 $10.52 $11.05 $11.57 Assumptions
Comparing January 1, 2026 rates for SDG&E and Community Power (prospective) to October 1, 2025 rates per SDG&E’s Schedule EECC and TOU-DR-1 tariff.
The TOU Super Off-Peak expansion, expected to be effective April 1st, is modeled structurally, with a shift of 30% of off-peak consumption to super off-peak consumption due to the new TOU periods.
Average monthly usage of 341 kWh on TOU-DR-1 residential rate. 2021 PCIA vintage.
*Renewable Portfolio Standards (RPS) Content based on most recent 2024 Power Content Label. 29 PowerBase Customer Load Reservation
• PowerBase is Community Power most affordable service offering that will be 10% less expensive compared to SDG&E’s effective January 1, 2026 generation/commodity rates. • Since its inception in 2024, PowerBase service is capped at 15% of Community Power customer load.
• When PowerBase reaches 10% participation by load, staff will return to the Board in a public meeting with a report regarding observations, customer feedback, and any potential recommended changes at that time.
• Staff recommends reducing that trigger to 5% participation by load. • Staff will also conduct a targeted marketing campaign towards high-need and low-income customers to increase awareness and/or participation.
30 Projected Residential Bill Impact for Staff Recommended Scenario TOU-DR-1
SDG&E
(41% RPS)*
Community Power Service Options
PowerBase to
SDG&E Delta
PowerOn to
SDG&E Delta
Power100 to
SDG&E Delta Residential PowerBase
(45% RPS)*
PowerOn
(53% RPS +
2% Carbon Free)*
Power100
(100% RPS)*
Generation ($) $41.80 $41.09 $44.55 $47.96
PCIA ($) $16.97 $12.13 $12.13 $12.13
Franchise Fees ($) $1.20 $1.20 $1.20 $1.20
Total Generation ($) $59.97 $54.42 $57.88 $61.29 -9.25% -3.48% 2.20% Delivery ($) $104.72 $104.71 $104.71 $104.71
Average Monthly Bill ($) $164.69 $159.13 $162.59 $166.00 -3.38% -1.28% 0.80% Assumptions
Rates as of January 1, 2026.
Average monthly usage of 341 kWh.
2021 PCIA vintage.
The TOU Super Off-Peak expansion, expected to be effective April 1st, is excluded in this analysis. *Renewable Portfolio Standards (RPS) Content based on most recent 2024 Power Content Label. 31 Projected Small Commercial Bill Impact for Staff Recommended Scenario TOU-A (Secondary Voltage)
SDG&E
(41% RPS)*
Community Power Service Options
PowerBase to
SDG&E Delta
PowerOn to
SDG&E Delta
Power100 to
SDG&E Delta Commercial PowerBase
(45% RPS)*
PowerOn
(53% RPS +
2% Carbon Free)*
Power100
(100% RPS)*
Generation ($) $128.16 $123.71 $134.32 $145.99
PCIA ($) $46.54 $33.33 $33.33 $33.33
Franchise Fees ($) $5.34 $5.34 $5.34 $5.34
Total Generation ($) $180.04 $162.38 $172.99 $184.66 -9.81% -3.92% 2.57% Delivery ($) $310.30 $310.26 $310.26 $310.26
Average Monthly Bill ($) $490.34 $472.64 $483.25 $494.92 -3.61% -1.45% 0.93% Assumptions
Rates as of January 1, 2026.
Average monthly usage of 1,167 kWh.
Average monthly demand of 5.4 kW.
2020 PCIA vintage.
The TOU Super Off-Peak expansion, expected to be effective April 1st, is excluded in this analysis. *Renewable Portfolio Standards (RPS) Content based on most recent 2024 Power Content Label. 32 Projected M&L Commercial Bill Impact for Staff Recommended Scenario AL-TOU (Secondary Voltage)
SDG&E
(41% RPS)*
Community Power Service Options
PowerBase to
SDG&E Delta
PowerOn to
SDG&E Delta
Power100 to
SDG&E Delta Commercial PowerBase
(45% RPS)*
PowerOn
(53% RPS +
2% Carbon Free)*
Power100
(100% RPS)*
Generation ($) $3,717.43 $3,528.62 $3,822.45 $4,069.37
PCIA ($) $1,124.46 $823.71 $823.71 $823.71
Franchise Fees ($) $115.79 $115.79 $115.79 $115.79
Total Generation ($) $4,957.69 $4,468.12 $4,761.95 $5,008.87 -9.87% -3.95% 1.03% Delivery ($) $5,684.82 $5,684.09 $5,684.09 $5,684.09
Average Monthly Bill ($) $10,642.51 $10,152.22 $10,446.04 $10,692.96 -4.61% -1.85% 0.47% Assumptions
Rates as of January 1, 2026.
Average monthly usage of 24,692 kWh.
Average monthly demand of 67.6 kW.
2020 PCIA vintage.
The TOU Super Off-Peak expansion, expected to be effective April 1st, is excluded in this analysis. *Renewable Portfolio Standards (RPS) Content based on most recent 2024 Power Content Label. 33 Staff Recommendation
• Adopt Community Power’s deepest discount since enrolling customers: PowerOn electricity generation rates with a 4% value proposition compared to SDG&E and PowerBase electricity generation rates with a 10% value proposition compared to SDG&E, to be retroactively effective on January 1, 2026.
• Renewable content of all Community Power products being higher than SDG&E’s, with the most recent 2024 Power Content Label.
• Maintains current reserve levels and work toward a 225- to 270-days cash on hand reserve target, to account for volatility from market uncertainty and potential 2027 PCIA snapback. • Satisfies credit obligations with lenders and power purchase agreements. • Prepares for market fluctuations and cost shifts.
• Return to the Board with PowerBase adoption data and recommendations after 5% of the total customer load is reached through participation in the product. 34 Public Comment on
Item No. 14
35 Item No. 14
Board Members
Comments or
Questions
Review and Approve
2026 Community
Power Rates, to be
Retroactively Effective
as of January 1, 2026.
Recommendation:
Review and approve 2026 Community
Power Rates, to be Retroactively Effective
as of January 1, 2026.
36 Item No. 15
Approve Professional Services
Agreement with PS
Hummingbird for Enterprise
Resource Planning
Implementation and Other
As-Needed Services for a Total
Not-To-Exceed Contract
Amount of $1,000,000
Presenter:
Tim Manglicmot, Director of Finance
Chris Do, Senior Financial Analyst
Recommendation: Receive and file
Community Power’s revisions to the existing
Net Energy Metering Tariff/Program (NEM)
and to the existing Net Billing Tariff (NBT) and
Community Power’s establishment of the new
Net Billing Tariff Virtual (NBT-V) and a Net
Billing Tariff Aggregation (NBT-A) for all new
customers who elect this and who have
installed onsite generation on or after
February 15, 2024 that qualifies for the tariff
and for existing customers transitioning out of
the Virtual Net Energy Metering Tariff (VNEM)
or the Net Energy Metering Aggregation Tariff
(NEMA) following the conclusion and/or
termination of their NEMA legacy period.
Recommendation:
Approve Professional Services Agreement
with PS Hummingbird regarding Enterprise
Resource Planning (ERP) Implementation and
other as-needed services for a total not-to-exceed contract amount of $1,000,000, and authorize the Chief Executive Officer to
execute the contract.
37 Enterprise Resource
Planning (ERP)
Data
HR
Budget Accounting
CIP
Procurement
IT
Payroll
Grants
38 Enterprise Resource Planning
What will it do?
• Standardized Controls
• Grant Management
• Automation
Why we need it?
• Operational Inefficiency
• Compliance Risk
• Growth Constraints
How will it benefit us?
• System vs People
• Mitigate Risk
• Regulatory Compliance
39 Request for Proposal (RFP) Timeline
Board Adopted Capital
Budget and CIP for Fiscal Year
2025-2026.
June 26, 2025
Request for Proposal (RFP) was
posted.
August 20, 2025
RFP submission window
closed.
September 17, 2025
Review of Competitive
Proposals.
Q4, 2025
Board Approval of PSA.
January 15, 2026
ERP Implementation Kickoff.
Jan-Feb, 2026
40 We are a modern digital transformation partner, helping to better serve our clients and their customers and colleagues
Our scale
Our clients (Energy & Commodities)
30 Years of Digital Pioneering
and Customer Innovation
24,000+
Passionate People
60+
Offices Globally
Connected
Energy & Commodities, Financial
Services, Consumer Products,, Health,
Public Sector, Retail, Transportation &
Mobility,
Travel & Hospitality
We are the Digital Business
Transformation hub of
Publicis Groupe
PS Hummingbird and Publicis Sapient at-a-glance
41 42
Fiscal Impact
$657K Fixed-Fee Contract
The contract value is substantially below the $1,000,000 CIP Budget approved June 26, 2025.
The remaining would serve as a contingency reserve for:
• Change work orders during implementation.
• As-needed technical services.
• Module expansion needs.
Conservative Financial Management
43 Public Comment on
Item No. 15
44 Item No. 15
Board Members
Comments or
Questions
Approve Professional Services
Agreement with PS Hummingbird
for Enterprise Resource Planning
Implementation and Other
As-Needed Services for a Total Not-To-Exceed Contract Amount of $1,000,000
Recommendation:
Approve Professional Services Agreement
with PS Hummingbird regarding Enterprise
Resource Planning (ERP) Implementation
and other as-needed services for a total
not-to-exceed contract amount of
$1,000,000, and authorize the Chief
Executive Officer to execute the contract.
45 Item No. 16
Approve Professional
Services Agreement with
Tenaska Power Services
for Scheduling
Coordinator Services
Presenter:
Jennine Camara, Director of Portfolio Management
Recommendation: Receive and file
Community Power’s revisions to the existing
Net Energy Metering Tariff/Program (NEM)
and to the existing Net Billing Tariff (NBT) and
Community Power’s establishment of the new
Net Billing Tariff and a Net Billing Tariff
Aggregation (NA) for all new customers who
elect this and who have installed onsite
generation on or after February 15, 2024 that
qualifies for the tariff and for existing
customers transitioning out of the Virtual Net
Energy Metering Tariff (VNEM) or the Net
Energy Metering Aggregation Tariff (NEMA)
following the conclusion and/or termination of
their NEMA legacy period.
Recommendation:
Approve a Professional Services Agreement
with Tenaska Power Services for Scheduling
Coordinator Services for an initial three-year
term, with one-year auto renewal terms, and
authorize the Chief Executive Officer to
execute the agreement for a not-to-exceed
amount of $2,000,000 over the initial term
and a not-to-exceed amount of $1,500,000
for each auto renewal term.
46 Background
• 24 x 7 x 365 schedule coordination of Community Power’s hourly load and energy resources is required for day-to-day operations
• Community Power first contracted with Tenaska Power
Services for scheduling and settlement services in June 2020
• The current agreement includes daily load forecasting and energy storage optimization services, which will terminate April 1, 2026
• As part of a competitive bidding process, staff evaluated load forecasting, energy storage optimization, and
scheduling-coordinator services proposals
47 California Independent System Operator
• The California Independent System Operator (“CAISO”)
o Manages the flow of electricity across high-voltage power lines o Operates wholesale energy market
o Oversees transmission planning
• A CAISO certified scheduling-coordinator (“SC”)
o Submits bids to buy energy and offers to supply energy on behalf of entities
o Coordinates 24 x 7 x 365 scheduling and dispatch operations 48 Dispatch of energy supply relies on 24x7 schedule coordination Scheduling-coordinators:
• Coordinate new energy resource requirements and testing through CAISO’s new resource implementation ("NRI") process prior to projects declaring commercial operations
• Submit daily and hourly energy schedules, submit economic bids, and manage any planned or unplanned project outages
• Ensure compliance with resource adequacy requirements and monitor dispatch operating instructions
• Manage congestion revenue rights (“CRR”) requirements and auction participation
• Fulfil the 24x7 obligation related to participating in CAISO’s wholesale energy markets
Scheduling agreement supports the strategic plan goal:
o Prudently manage the power portfolio to minimize risk and customer costs
49 Competitive process provides an experienced partner
• Community Power staff recommends approval of the three-year agreement with Tenaska Power Services (“TPS”)
• Tenaska Power Services has served as a registered scheduling-coordinator in the CAISO market since 2012, brings broad experience with all generation technologies operating on the California grid, including the various configurations of energy storage resources, and actively supports other CCAs in California of similar size to Community Power
• The new scheduling services agreement narrows the scope of services provided by Tenaska Power Services, and includes optional termination provisions if Power Services elects to bring certain job functions in house
• Resource scheduling charges accommodate the flexibility needs of an expanding energy resource portfolio to ensure Community Power does not pay for services if projects are delayed reaching commercial operations
50 Financial Impact
• The agreement will not exceed $2,000,000 over the initial three-year term, and not exceed $1,500,000 for renewal
terms
• Pricing includes fixed monthly fees for scheduling
Community Power’s daily load and providing Power Services support services, and monthly variable fees based on the number of Community Power’s generating and storage
resources that have reached commercial operations
• Ongoing costs associated with scheduling services will be between $1,000,000 - $1,500,000 annually
• Costs associated with the agreement are included in the approved Fiscal Year 2025-2026 operating budget
51 Public Comment on
Item No. 16
52 Item No. 16
Board Members
Comments or
Questions
Approve Professional Services
Agreement with Tenaska
Power Services
for Scheduling Coordinator
Services
Recommendation:
Approve a Professional Services Agreement
with Tenaska Power Services for Scheduling
Coordinator Services for an initial three-year
term, with one-year auto renewal term, and
authorize the Chief Executive Officer to
execute the agreement for a not-to-exceed
amount of $2,000,000 over the initial term
and a not-to-exceed amount of $1,500,000
for each auto renewal term.
53 Chief Executive Officer Report
54 Holiday Outreach
Holiday Tree Lighting A Kimball Holiday
at Pier Plaza
Light Up Logan Chula Vista Starlight
Parade
December Nights
55 Recent Events
Teltra Park Beautification National Electrical Contractors Association Gala 56 Board Member Announcements
57 Adjournment
58 Next Regular Community
Power Board Meeting
February 26, 2026
[email protected]