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MEMORANDUM
TO Sara Letton, Sustainability Coordinator, City of South Lake Tahoe FROM Amber Gschwend and Garrett Cole, GDS Associates; Ryan Baron, Best Best & Krieger LLP DATE March 7, 2025
RE City of South Lake Tahoe CCA Feasibility
INTRODUCTION
This memo updates the previous analysis completed for the City of South Lake Tahoe (City) to determine the financial feasibility of implementing a Community Choice Aggregation (CCA) program for the City. This update incorporates changes since the draft feasibility assessment was prepared in May 2024. Specific updates include:
1. Liberty Utilities Energy Cost Adjustment Request (updated October 24, 2024)
2. Liberty Utilities 2025 General Rate Case (GRC)Application
3. Current market conditions and scenario projections for power supply costs Based on the updates it was determined that a standalone, fully staffed South Lake Tahoe CCA would not likely be financially feasible unless power supply costs remain at current levels and interest only payments on debt service could be made in the first 3 years of operation.
CCA FORMATION AUTHORITY
An initial question is whether the City can form a CCA under California law given that investor-owned utility (IOU) service territory the CCA would provide retail electricity in is within Liberty Utilities (Liberty), which is outside the California Independent System Operator (CAISO) Balancing Authority (BA) but within the BA of Nevada Energy. Assembly Bill (AB) 117, enacted in 2002, allows for CCA throughout the State of California with no limitation on the formation of a CCA except within the territory of a local publicly owned electric utility.1 Essentially, state law allows any city, county, or group of cities and/or counties through a joint powers authority to aggregate the electrical load of interested electricity consumers within its boundaries except in the territory of another public agency (e.g., Truckee Donner Public Utility District).2
SOUTH LAKE TAHOE LOAD CHARACTERISTICS
Liberty provided the City with customer usage data and service account numbers for calendar year 2023.
The retail sales to end-customers are aggregated based on load shapes available through several sources including data provided by Liberty, Liberty’s General Rate Case filings, Marginal Cost of Service analysis, and load characteristics from neighboring utilities. Figure 1 summarizes the breakdown of the load within each customer class.
1 Pub. Util. Code § 366.2(c)(1).
2 See also Pub. Util. Code § 331.1.
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FIGURE 1. ANNUAL RETAIL SALES, 158 GWH
Figure 2 shows the number of service accounts.
FIGURE 2. 2023 SERVICE ACCOUNTS
Notably, the City has a large share of homes that are occupied during parts of the year as seasonal homes.
Liberty estimates that 55% of the City’s residential service accounts are seasonal (non-permanent). The breakdown of service accounts and usage is estimated based on the figures provided by Liberty. Nonpermanent accounts are associated with a higher cost of service due in part to their lower consumption and also in part by their load profiles that partly peak during summer months (Figure 3). For purposes of this study, permanent and seasonal residential customers are modeled separately.
Permanent
Residents
28%
Seasonal
Residents
16%
Small Commercial
24%
Medium
Commercial
14%
Large Commercial
18%
Lights
0%
6,014
7,351
1,843
5,132
15 69
0 1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
Permanent
Residents
Seasonal
Residents
Small
Commercial
Medium
Commercial
Large
Commercial
Lights
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FIGURE 3. RESIDENTIAL MONTHLY LOAD SHAPES
Participation Rates
CCA program participation can vary. Most recent CCAs have observed low program opt-out rates ranging from 2-5% (95-98% participation). These assumptions are reasonable for modeling potential CCA loads.
Liberty has confirmed that there are no direct access customers within its service territory. Direct Access customers are those that purchase power supply directly from a third-party supplier rather than through the utility. It is common practice for a CCA to exclude direct access customers from automatic enrollment.
CCA Load Forecast
After applying participation rates and line losses,3 the CCA load is forecasted at 149,000 MWh for the full 2027 calendar year. This assumes load is served beginning January 1, 2027. The system peaks in January at approximately 37 MW. Electric loads are forecast to grow at approximately 0.3% annually based on the 0.5% growth in residential and 0.25% annual growth in small and medium commercial classes. Growth rates were informed by the City of South Lake Tahoe 2022-2027 Housing Element Report.4 Figure 4 illustrates the estimated monthly load shape for calendar year 2026. 3 Distribution system losses are 4% secondary and 2% primary based on Liberty’s GRC documents. 4 Placeworks, City of South Lake Tahoe 2022-2027 Housing Element, Public Draft (Dec. 2021). 0 1,000,000
2,000,000
3,000,000
4,000,000
5,000,000
6,000,000
1 2 3 4 5 6 7 8 9 10 11 12
kWh
Month
Permanent Residents Seasonal Residents
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FIGURE 4. CCA SYSTEM MONTHLY LOAD FORECAST: 2026
CCA OVERHEAD
If the City were to implement its own CCA program, the program would need to hire staff and consultants to carry out day-to-day operations and meet all regulatory requirements. The overhead costs include services for the following:
TABLE 1. CCA OVERHEAD
Service Performed By: General Functions
Portfolio Management Third
Party/Consultant
Resource Planning, power contract procurement,
load forecasting
Schedule Coordinator Third
Party/Consultant
Hourly management of load and resources
Data Management and
Customer Service Call
Center
Third
Party/Consultant
Validates meter reads, staff customer service call
center, manages usage data
Billing IOU Calculates, prints, and mails utility bills for all customers
CCA Program Management CCA Staff Can include many roles but at a minimum: CEO, CFO, Power Supply Director
Energy Program
Management
Mix of CCA staff and
Consultant
Develop energy-related customer programs such
as energy efficiency
Financial Services Third
Party/Consultant
Accounting, banking services
Program management staff is assumed to include 3.5 FTE once fully operational. Depending on CCA organization and program goals, this level of staffing can be increased over time. For the purposes of the feasibility assessment, it is assumed that the minimum staffing level is 3.5 FTE. Operating CCAs of similar 0 2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000
20,000
1 2 3 4 5 6 7 8 9 10 11 12
M
Wh
Month
Permanent Residents Seasonal Residents Small Commercial Medium Commercial Large Commercial Lighting
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size typically employ 3-15 FTE. Annual operating costs, including all the necessary functions, are estimated at $3.3 million in 2027.
In addition, non-operating costs will also be incurred. These costs include the following:
Financial Security Requirements – Deposit paid in the event the CCA program is closed and customers need to be returned to IOU service
Debt-Service – Start-up costs and working capital. The CCA will require capital for costs it incurs prior to collecting revenues from customers. On average it requires 2.5 months to collect the total revenue billed in any given month.
CCA start-up costs are highly predictable based on previous experience in reviewing detailed expenses for more than 20 California CCAs. Cost estimates are updated to current 2025 dollars and included in the proforma.
CCA POWER COSTS
Power supply costs are calculated based on the load characteristics and projected market conditions.
Once formed, a CCA can decide the power supply mix preferences; however, for this initial analysis, it is assumed that a South Lake Tahoe CCA would only meet the California Renewables Portfolio Standard (RPS) requirements and would not “opt-up” customers into higher renewable product tiers. The requirement is 49% renewable energy by 2026 increasing to 60% renewable by 2030 and 100% carbon free by 2045. Additional requirements are also met including:
Resource Adequacy requirements (RAR)
65% of renewable energy requirements must be purchased through long-term contracts (10 or more years)
Requirement for meeting loads with 0.1% energy storage resources Block Energy Purchases
A South Lake Tahoe CCA could meet its energy requirements through block energy purchases. These purchases could be short-term (months to a year) or long-term power contracts (multiple year contracts).
Additionally, the pricing construct of potential contracts could vary. For example, pricing could be based on time of day usage, flat price for all years, include an escalation factor, or other constructs. For the purposes of this study, energy purchases are priced based on forward market prices, which vary by time of day and escalate year to year. This pricing construct best captures the cost to serve the estimated South Lake Tahoe load shape.
The South Lake Tahoe area would have access to NP15 market exchanges, and NP15 is one of the closest trading hubs for wholesale electricity. The forward pricing for NP15 is adjusted for the South Lake Tahoe area based on historical congestion differentials. Figure 5 shows the NP15 data and the adjusted pricing for South Lake Tahoe region (SLT) as of December 2024.
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FIGURE 5. FORWARD MARKET PRICES
Renewable Energy
As mentioned above, the CCA would be subject to CA RPS which includes provisions for the share of energy purchased from renewable resources as well as the contract length. Given the City’s Climate Goals of 24/7 greenhouse gas free electricity, this study evaluated meeting RPS requirements with only Portfolio Content Category (PCC) 1 and 2 renewable energy credits (RECs). These are bundled RECs deliverable to California. The CCA could purchase PCC3 RECs and realize cost savings in meeting RPS requirements. This option is not evaluated in this analysis.
PCC1 and PCC2 RECS in December 2024-January 2025 were trading in the range of $50-$70/MWh. These prices are additive to the market price of electricity. Since that time, the price for renewable energy has declined significantly and is now trading in the $15-$25/MWh range (March 2025). This lower cost range is more typical for renewable energy costs observed prior to the COVID-19 pandemic and subsequent supply chain issues. Both power cost scenarios are modeled in to assess feasibility.
For long-term renewable energy contracts, it is assumed that the CCA would be able to procure approximately 17 MW from a solar facility at the beginning of the study period and incrementally procure more solar throughout the 10-year term to meet the 65% long-term contract requirement as the RPS grows through 2035. This results in the CCA participating in a total of 26 MW by the end of the study period at an estimated cost of $50/MWh. This is slightly higher than the Q4 2023 price from Edison Electric that averages long-term contracts. The higher price reflects that the cost is considered inclusive of the long-duration storage requirement of 0.1% of the system peak demand.
In order to enter into a long-term contracting arrangement, sellers typically require credit ratings or up front capital to secure the agreement. As a new entity, the CCA would not have a credit rating. Therefore, the CCA will need a credit facility that addresses the collateral requirements to enter into power purchase agreements with a seller. The cost of this credit is included in the financial feasibility assessment. $-
$20.00
$40.00
$60.00
$80.00
$100.00
$120.00
Jan-26 Feb-26 Mar-26 Apr-26 May-26 Jun-26 Jul-26 Aug-26 Sep-26 Oct-26 Nov-26 Dec-26 $/M
Wh
SLT On-Peak SLT Off-Peak
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Resource Adequacy
The California Public Utilities Commission (CPUC) requires that all Load Serving Entities (LSEs) comply with certain Resource Adequacy requirements (RAR).5 These requirements ensure enough capacity to meet electrical demand across the system. LSEs can meet the RAR with different types of RA: local, system, and flexible. There are some minimum amounts from each type of RA required depending on the LSE’s location. If an LSE fails to meet the requirements, certain penalties will apply including fines.
Flexible and local RAR are calculated based on CAISO system information. Because South Lake Tahoe is located outside of the CAISO system, it is assumed that it would have only a system RAR.6 Also, since the South Lake Tahoe system is not connected to the CAISO, the CCA would not need to purchase capacity (resource adequacy) from the CAISO area where prices have increased significantly in the past 5 years.
Current CAISO system RA prices are in the $13-14/kW-mo.
The CCA could purchase capacity resources from sellers in the NV Energy balancing area to meet their RA requirement. The feasibility assessment assumes that a CCA would receive the same treatment that Liberty currently receives from NV Energy regarding power supply contracting. NV Energy provides Liberty with all of its RA requirements. The cost of the RA is based on a contract demand (kW peak demand that is fixed in each month of the year) and the capacity charge of $8.20/kW-mo through December 2025. NV Energy would give the CCA capacity credits for local solar resources as it has done for Liberty in the 2021 Energy Services Agreement (ESA).7 The capacity credits would be negotiated values; however, the proforma assumes capacity credits consistent with the CAISO’s RA program.
Transmission
Transmission services would continue to be provided by Liberty and billed through the delivery rate.
Ancillary services including scheduling, system control, dispatch service, reactive supply, voltage control, and regulation and frequency response costs are the responsibility of the CCA. The costs for these services included are estimated at $1.13/MWh.
Power Cost Summary
Figure 6 shows the resulting annual power costs in $/MWh units for each year of the study. As the RPS requirement increases, renewable purchases become a larger share of total power costs. Power costs increase approximately 3% annually over the study period. Figure 6 shows the Scenario 1 power supply costs which assume the higher renewable energy costs observed in December 2024 and January 2025. 5 CPUC Rulemakings (R.) 16-02-007, R.15-02-020, R.17-09-020, and R.19-11-009. 6 According to comments filed by Liberty through its trade association the California Association of Small and MultiJurisdictional Utilities (CASMU), Liberty is not subject to CAISO RA Requirements. “As described above, Liberty and PacifiCorp operate outside of the CAISO balancing authority area. Accordingly, Liberty and PacifiCorp are not subject to CAISO resource adequacy (“RA”) requirements. Additionally, none of the CASMU members are subject to Commission RA requirements. It should also be noted that because the Commission does not exercise supervisory authority over certain contracting undertaken by the CASMU members, none of the CASMU members participate in a Procurement Review Group. Further, neither BVES nor Liberty utilizes an Independent Evaluator.” CPUC Rulemaking (R.) 20-11-003, Exhibit CASMU-1, pg. 6 (Sept. 1, 2021). https://www.cpuc.ca.gov/-/media/cpucwebsite/divisions/energy-division/documents/summer-2021-reliability/opening-testimony/smju-openingtestimony-phase-2.pdf. 7 Liberty Utilities Advice Letter 153-E (U-933-E). Liberty Utilities (CalPeco Electric) LLC – Request of 2021 Energy Services Agreement with Sierra Pacific Power Company, dba NV Energy (Sept. 4, 2020). 55868.00001\42219788.8
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FIGURE 6. CCA POWER COST ESTIMATES: SCENARIO 1, $/MWH
Figure 7 shows the power supply costs when assuming more current renewable energy costs (March 2025).
FIGURE 7. CCA POWER COST ESTIMATES: SCENARIO 2, $/MWH
$85 $82 $82 $84 $86 $88 $91 $93 $96
$-
$20
$40
$60
$80
$100
$120
2027 2028 2029 2030 2031 2032 2033 2034 2035
$/M
Wh
Market Energy Long-Term Renewable Resource Adequacy
Other Renewable Total Cost of Ancillary Service
$76
$82 $82 $84 $86 $88 $91 $93 $96
$-
$20
$40
$60
$80
$100
$120
2027 2028 2029 2030 2031 2032 2033 2034 2035
$/M
Wh
Market Energy Long-Term Renewable Resource Adequacy
Other Renewable Total Cost of Ancillary Service
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EXIT FEE
Traditionally California IOUs calculate a Power Charge Indifference Adjustment (PCIA) for departing loads, such as regions where CCAs have been established. The PCIA is the stranded generation cost a departing load customer must pay in order to hold remaining customers indifferent to the load departure. The three large 3 IOUs (PG&E, SCE, SDG&E) manage large portfolios of power supply resources, which include a combination of long-term and short-term contracts and resources that are directly owned and operated by the utility. In the case of Liberty, power supply is provided by NV Energy via a 5-year contract that includes all energy requirements. Liberty’s own resources are included in the contract as a credit to its power costs.
The current contract expires December 2025. Liberty is likely negotiating an updated contract for the term beginning directly after expiration. It is expected that the new contract will be similar to the current version in term and exceptions. This is an important factor in determining whether or not Liberty’s generation costs are stranded. Key components of the contract include the following:
1. Liberty is billed based on contract demand (Appendix C). This contract demand may be modified with written notice8 for certain instances including:
a. Up to 20,000 kWac of new renewable facilities procured through Liberty’s competitive bid process and connected to Liberty’s distribution system. b. Adjustment for new Qualifying Facilities (for PURPA compliance).9 c. Procurement of energy or capacity in the case NV Energy fails to deliver the full requirement.
d. Mutual agreement between NV Energy and Liberty to modify Liberty’s contract demand for changes that more accurately reflect Liberty’s load.
2. Contract demand is billed at $8.20/kW-month.
3. NV Energy provides transmission services through its Network Integrated Transmission Service (NITS).
Based on the above contract provisions, there appears to be flexibility in Liberty’s purchased power contract. Both the short term of the contract (5 years with optional termination at 3 years) and the allowance to modify contract demand based on accurate load estimates suggest that the stranded generation costs would be minimal.
There is also support for a $0 PCIA rate from both Liberty’s resource plans and its current Direct Access rates. First, Liberty is seeking to increase its renewable energy share, and if a portion of its load departed to form a CCA, there could be cost savings to the remaining Liberty customers. These cost savings would be from Liberty avoiding the need to procure additional renewable energy as it could rely on its current generating resources to meet a larger share of the remaining load.
Second, the Direct Access tariff does not include an exit fee. Liberty does not currently provide distribution services to direct access customers. If a customer wanted to move to direct access, however, the customer would not have to pay for generation cost stranding. This is informative because in the CPUC’s initial decisions implementing Assembly Bill 117 that enacted the CCAs laws, the CPUC instructed the three large IOUs at that time to use their Direct Access tariffs as the basis for formulating new CCA tariffs. Although 8 Section 4.6.
9 Public Utilities Regulatory Policies Act of 1978.
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the three large IOUs eventually drafted tariffs that included stranded cost methodologies, which was later reformed by the CPUC in a broader CPUC PCIA proceeding, there is initial precedent that suggests that Liberty use its current Direct Access tariff as the basis for a newly forming CCA in its territory (i.e., no stranded cost).
LIBERTY GENERATION RATE
Liberty’s current rate structure is unbundled. Therefore, the generation rate for each class is clearly separated from other costs, such as distribution and rate riders. Between rate cases, Liberty adjusts generation rates using the Energy Cost Adjustment Clause (ECAC). Liberty must file for ECAC adjustments for new fuel and purchased power costs (termed Offset Rate) and when there is an anticipated under or over-collection of revenues by at least 5% (Balancing Account). The most recent ECAC request10 would increase generation rates by approximately 30% above their current level. The Advice letter was filed April 2024 and is currently pending.
We reviewed recent rate filings and advice letters filed by Liberty and summarized the expense data provided in Liberty’s FERC Form 1 filings (2019-2023). Table 2 shows the trend identified from the aforementioned source documents. Based on these figures, Liberty’s generation rate has increased approximately 28% per year since 2019.
TABLE 2. LIBERTY GENERATION COSTS
2019 2020 2021 2022 2023
Total Power Supply Expenses $21,436,540 $22,354,003 $25,424,004 $28,846,921 $30,888,492 MWh Sales 568,415 559,781 553,504 558,269 543,980
Generation Rate, $/kWh $0.0377 $0.0399 $0.0459 $0.0517 $0.0568 Incremental Adjustment 5.9% 15.0% 12.5% 9.9%
Table 2 shows purchased power and production expenses for each year reported. However, these costs are not the direct generation rate charged to consumers. Due to the lag between rate adjustment requests and approvals, Liberty records shortfalls and overages in a balancing account. The most recent request for the energy cost adjustment includes $0.05765/kWh for purchased power and fuel costs and an additional $0.03892/kWh for the balancing account recovery. Liberty has requested that the current under-collection be amortized over 2 years beginning January 1, 2025. If a CCA is established, and there is an under-collection balance for energy costs, CCA customers would need to pay their share even after leaving Liberty bundled service.
Looking forward, the study assumes Liberty’s current generation rate will increase by 28.9% in 2025 and then 10% annually after. Based on Liberty’s FERC Form 1 filings, the total retail rate (revenues divided by retail sales) has increased by an average of 10.8% per year since 2019. 10 Advice Letter 233-E Customer First Rate Change and ECAC. https://california.libertyutilities.com/uploads/CalPeco%20ALs/Liberty%20CalPeco's%20AL%20233- E%20Customer%20First%20Rate%20Change%20and%20ECAC.pdf.
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LIBERTY 2025 GENERAL RATE CASE FILING
Liberty filed its 2025 GRC application earlier this year requesting significant increases to its delivery rate.
The average system increase is approximately 40% over current rates. This increase translates to a 19% increase in the total Liberty rate (generation plus delivery). Much of this increase is due to wildfire mitigation costs, capital spending, increased operating costs, and the utility’s approved rate of return.
Even as a CCA, South Lake Tahoe residents would be required to pay the delivery charge to Liberty.
FEASIBILITY ANALYSIS
The feasibility analysis compares the CCA operating costs with estimated revenue to determine if the net revenue is sufficient to cover the takeout financing required for working capital and/or lockbox arrangements with creditors. Figure 8 illustrates the potential revenue compared with operating costs for the CCA under the higher power cost scenario (Scenario1). A relatively large working capital amount is needed since net operating income in the first 3 years is negative. The longer-term outlook is more positive, however this result relies on continued Liberty generation rate increases and market prices that don’t increase significantly. Figure 9 illustrates more favorable feasibility under Scenario 2 power supply costs (lower renewable energy costs). Only the first year (2027) of net operating income is negative. It’s reasonable that the CCA program could make interest-only payments on debt service until year 2 (2028). 55868.00001\42219788.8
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FIGURE 8. FEASIBILITY RESULTS: CITY OPERATED PROGRAM: SCENARIO 1 FIGURE 9. FEASIBILITY RESULTS: CITY OPERATED PROGRAM: SCENARIO 2 The above analysis assumes some minimal level of City staffing for the CCA program in addition to the team of consultants needed to operate the program. If the City considers a turnkey approach, the 55868.00001\42219788.8
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overhead costs could be reduced. The turnkey option is analyzed assuming 1 part time City employee manages the program with support from a full turnkey solution. Figure 10 shows that feasibility is achieved even when renewable power supply costs are high. Figure 11 indicates that lower power supply prices improve the turnkey feasibility.
FIGURE 10. FEASIBILITY RESULTS: TURNKEY OPERATED PROGRAM: SCENARIO 1 FIGURE 11. FEASIBILITY RESULTS: TURNKEY OPERATED PROGRAM: SCENARIO 2 55868.00001\42219788.8
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Findings
The feasibility analysis revealed the following:
Based on Liberty’s power supply contracts, the PCIA will likely be very low or zero. A low PCIA is advantageous to new CCA programs.
If an under-collection exists at the time of load departure, CCA customers will still need to pay Liberty for their fair share of the under-collection.
South Lake Tahoe is located outside of CAISO and would likely be able to meet its RAR at a lower cost through bilateral contracts.
Feasibility was evaluated for two power supply cost scenarios. Scenario 1 represents the pricing trends during December 2024-January 2025 which ranged from $50-$80/MWh. Scenario 2 analyzed current (March 2025) renewable pricing trends at $15-$25/MWh. The feasibility results are sensitive to the power supply cost forecast and indicate that lower renewable prices could result in CCA program feasibility for the City.
The study analyzed CCA program feasibility under a turnkey approach. Feasibility is obtainable under the turnkey option for either Scenario 1 or Scenario 2 power supply costs. The study assumes substantial generation rate increases of 11% per year on average. These rates are adjusted by over 20% in the first year.
Liberty’s current ESA with Nevada Energy expires at the end of the 2025 calendar year. A new, updated contract with Nevada Energy is expected to put upward pressure on Liberty’s generation rates which could help improve the feasibility of CCA in the initial years. A new contract term may also introduce cost stranding for the length of the contract. Even with over 20,000 service accounts, total usage in South Lake Tahoe is only about 150 GWh annually. This relatively low total usage that makes it challenging to recover non-power operating costs. A Turnkey approach can help lower overhead costs for the program. New CCA programs will need significant capital to enter into long-term renewable energy contracts. These long-term contracts are required by state RPS; however, in absence of credit ratings, a new CCA would need to provide some type of collateral in order for the terms to be accepted by a supplier. This reserve requirement adds to the debt service payment and results in less favorable feasibility results.
Liberty does not offer a 100% green rate to its customers, however, the CCA could offer this, or similar options, and recover the costs through retail rates that are above the rates for the standard product offered by Liberty.
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TABLE 3. CITY-STAFFED CCA FEASIBILITY 10-YEAR PROFORMA, SCENARIO 1 POWER COSTS, $MILLIONS 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036
Revenues
Retail Rate Revenues $0.00 $12.33 $15.80 $17.45 $19.27 $21.29 $23.51 $25.97 $28.68 $31.68 $34.99 Uncollectible $0.00 -$0.01 -$0.02 -$0.02 -$0.02 -$0.02 -$0.02 -$0.03 -$0.03 -$0.03 -$0.04 Total Rate Revenue $0.00 $12.32 $15.78 $17.43 $19.25 $21.26 $23.49 $25.94 $28.65 $31.65 $34.96 Expenses
Power Supply
Block Energy Purchases $0.00 $5.41 $6.38 $6.52 $6.30 $6.21 $6.26 $6.32 $6.38 $6.43 $6.48 Renewable Energy $0.00 $3.36 $3.86 $3.80 $4.01 $4.28 $4.56 $4.85 $5.14 $5.45 $5.77 Capacity/Resource Adequacy $0.00 $3.06 $3.46 $3.54 $3.62 $3.70 $3.78 $3.87 $3.96 $4.05 $4.14 Ancillary Services $0.00 $0.24 $0.26 $0.27 $0.27 $0.27 $0.27 $0.27 $0.27 $0.27 $0.27 Total Power Supply $0.00 $12.07 $13.95 $14.12 $14.20 $14.46 $14.87 $15.30 $15.75 $16.20 $16.66 Operating and Administrative
Data Management and Customer Service Call Center $0.10 $0.32 $0.33 $0.34 $0.35 $0.36 $0.37 $0.39 $0.40 $0.41 $0.43 Power Management Consultant $0.17 $0.52 $0.54 $0.56 $0.57 $0.59 $0.61 $0.62 $0.64 $0.66 $0.68 Schedule Coordinator/Dispatch $0.08 $0.26 $0.27 $0.28 $0.29 $0.29 $0.30 $0.31 $0.32 $0.33 $0.34 Financial (Audit, Accounting) $0.06 $0.19 $0.19 $0.20 $0.20 $0.21 $0.21 $0.22 $0.23 $0.23 $0.24 Technical Consultants $0.04 $0.11 $0.11 $0.12 $0.12 $0.12 $0.13 $0.13 $0.13 $0.14 $0.14 Marketing & Outreach $0.05 $0.16 $0.17 $0.17 $0.18 $0.18 $0.19 $0.20 $0.20 $0.21 $0.21 Legal/Regulatory $0.07 $0.22 $0.22 $0.23 $0.24 $0.25 $0.25 $0.26 $0.27 $0.28 $0.28 Liberty Fees, Billing $0.03 $0.10 $0.10 $0.11 $0.11 $0.11 $0.12 $0.12 $0.13 $0.13 $0.13 General & Administrative expenses $1.04 $1.47 $1.43 $1.47 $1.52 $1.56 $1.61 $1.66 $1.71 $1.76 $1.81 Total O&M and A&G $1.64 $3.34 $3.36 $3.47 $3.57 $3.68 $3.79 $3.91 $4.03 $4.15 $4.28 Debt Service Payment on Financing $0.00 $2.42 $2.64 $2.64 $2.64 $0.22 $0.00 $0.00 $0.00 $0.00 $0.00 Total Expenses $1.64 $17.83 $19.95 $20.22 $20.41 $18.36 $18.66 $19.21 $19.78 $20.35 $20.94 Net Income -$1.64 -$5.51 -$4.17 -$2.79 -$1.15 $2.91 $4.83 $6.73 $8.88 $11.30 $14.02 Net Income Allocation
Reserve Fund Contribution $9.21 -$5.51 -$4.17 -$2.79 -$1.15 $2.91 $4.83 $1.42 $0.14 $0.14 $0.15 Start-up Funding Payments + Collateral -$10.85 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 Discretionary Programs/Additional Rate Discounts $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $5.31 $8.74 $11.15 $13.87 Total Cash Outlays -$1.64 -$5.51 -$4.17 -$2.79 -$1.15 $2.91 $4.83 $6.73 $8.88 $11.30 $14.02 Rate Stabilization Reserve Balance $9.21 $3.71 -$0.47 -$3.26 -$4.41 -$1.50 $3.32 $4.74 $4.88 $5.02 $5.16 Reserve Balance Target $3.80 $3.80 $4.27 $4.34 $4.38 $4.47 $4.60 $4.74 $4.88 $5.02 $5.16 55868.00001\42219788.8
M E M O R A N D U M
City of South Lake Tahoe CCA Feasibility
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TABLE 4. CITY-STAFFED CCA FEASIBILITY 10-YEAR PROFORMA, SCENARIO 2 POWER COSTS, $MILLIONS 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036
Revenues
Retail Rate Revenues $0.00 $12.33 $15.80 $17.45 $19.27 $21.29 $23.51 $25.97 $28.68 $31.68 $34.99 Uncollectible $0.00 -$0.01 -$0.02 -$0.02 -$0.02 -$0.02 -$0.02 -$0.03 -$0.03 -$0.03 -$0.04 Total Rate Revenue $0.00 $12.32 $15.78 $17.43 $19.25 $21.26 $23.49 $25.94 $28.65 $31.65 $34.96 Expenses
Power Supply
Block Energy Purchases $0.00 $5.41 $6.38 $6.52 $6.30 $6.21 $6.26 $6.32 $6.38 $6.43 $6.48 Renewable Energy $0.00 $2.80 $3.22 $3.96 $4.31 $4.60 $4.90 $5.22 $5.54 $5.88 $6.23 Capacity/Resource Adequacy $0.00 $1.95 $2.29 $2.33 $2.38 $2.42 $2.47 $2.51 $2.56 $2.60 $2.65 Ancillary Services $0.00 $0.16 $0.18 $0.18 $0.18 $0.18 $0.18 $0.18 $0.18 $0.18 $0.18 Total Power Supply $0.00 $10.32 $12.06 $12.99 $13.17 $13.42 $13.81 $14.23 $14.66 $15.09 $15.54 Operating and Administrative
Data Management and Customer Service Call Center $0.10 $0.32 $0.33 $0.34 $0.35 $0.36 $0.37 $0.39 $0.40 $0.41 $0.43 Power Management Consultant $0.17 $0.52 $0.54 $0.56 $0.57 $0.59 $0.61 $0.62 $0.64 $0.66 $0.68 Schedule Coordinator/Dispatch $0.08 $0.26 $0.27 $0.28 $0.29 $0.29 $0.30 $0.31 $0.32 $0.33 $0.34 Financial (Audit, Accounting) $0.06 $0.19 $0.19 $0.20 $0.20 $0.21 $0.21 $0.22 $0.23 $0.23 $0.24 Technical Consultants $0.04 $0.11 $0.11 $0.12 $0.12 $0.12 $0.13 $0.13 $0.13 $0.14 $0.14 Marketing & Outreach $0.05 $0.16 $0.17 $0.17 $0.18 $0.18 $0.19 $0.20 $0.20 $0.21 $0.21 Legal/Regulatory $0.07 $0.22 $0.22 $0.23 $0.24 $0.25 $0.25 $0.26 $0.27 $0.28 $0.28 Liberty Fees, Billing $0.03 $0.10 $0.10 $0.11 $0.11 $0.11 $0.12 $0.12 $0.13 $0.13 $0.13 General & Administrative expenses $1.04 $1.47 $1.43 $1.47 $1.52 $1.56 $1.61 $1.66 $1.71 $1.76 $1.81 Total O&M and A&G $1.64 $3.34 $3.36 $3.47 $3.57 $3.68 $3.79 $3.91 $4.03 $4.15 $4.28 Debt Service Payment on Financing $0.00 $2.42 $2.64 $2.64 $2.64 $0.22 $0.00 $0.00 $0.00 $0.00 $0.00 Total Expenses $1.64 $16.08 $18.07 $19.09 $19.38 $17.32 $17.60 $18.14 $18.69 $19.25 $19.82 Net Income -$1.64 -$3.76 -$2.28 -$1.66 -$0.13 $3.95 $5.88 $7.80 $9.97 $12.40 $15.14 Net Income Allocation
Reserve Fund Contribution $9.21 -$3.76 -$2.28 -$1.66 -$0.13 $2.84 $0.12 $0.13 $0.13 $0.14 $0.14 Start-up Funding Payments + Collateral -$10.85 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 Discretionary Programs/Additional Rate Discounts $0.00 $0.00 $0.00 $0.00 $0.00 $1.11 $5.76 $7.67 $9.83 $12.27 $15.00 Total Cash Outlays -$1.64 -$3.76 -$2.28 -$1.66 -$0.13 $3.95 $5.88 $7.80 $9.97 $12.40 $15.14 Rate Stabilization Reserve Balance $9.21 $5.45 $3.17 $1.51 $1.38 $4.22 $4.34 $4.47 $4.61 $4.75 $4.89 Reserve Balance Target $3.37 $3.37 $3.80 $4.06 $4.13 $4.22 $4.34 $4.47 $4.61 $4.75 $4.89 55868.00001\42219788.8
M E M O R A N D U M
City of South Lake Tahoe CCA Feasibility
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TABLE 5. TURNKEY CCA FEASIBILITY 10-YEAR PROFORMA, SCENARIO 1 POWER COSTS, $MILLIONS 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036
Revenues
Retail Rate Revenues $0.00 $12.33 $15.80 $17.45 $19.27 $21.29 $23.51 $25.97 $28.68 $31.68 $34.99 Uncollectible $0.00 -$0.01 -$0.02 -$0.02 -$0.02 -$0.02 -$0.02 -$0.03 -$0.03 -$0.03 -$0.04 Total Rate Revenue $0.00 $12.32 $15.78 $17.43 $19.25 $21.26 $23.49 $25.94 $28.65 $31.65 $34.96 Expenses
Power Supply
Block Energy Purchases $0.00 $5.41 $6.38 $6.52 $6.30 $6.21 $6.26 $6.32 $6.38 $6.43 $6.48 Renewable Energy $0.00 $3.36 $3.86 $3.80 $4.01 $4.28 $4.56 $4.85 $5.14 $5.45 $5.77 Capacity/Resource Adequacy $0.00 $1.95 $2.29 $2.33 $2.38 $2.42 $2.47 $2.51 $2.56 $2.60 $2.65 Ancillary Services $0.00 $0.16 $0.18 $0.18 $0.18 $0.18 $0.18 $0.18 $0.18 $0.18 $0.18 Total Power Supply $0.00 $10.88 $12.70 $12.83 $12.87 $13.09 $13.46 $13.86 $14.26 $14.67 $15.09 Operating and Administrative
Turnkey Operating Costs $0.56 $1.73 $1.79 $1.84 $1.90 $1.95 $2.01 $2.08 $2.14 $2.21 $2.27 Liberty Fees, Billing $0.03 $0.10 $0.10 $0.11 $0.11 $0.11 $0.12 $0.12 $0.13 $0.13 $0.13 General & Administrative expenses $0.31 $0.51 $0.44 $0.46 $0.47 $0.49 $0.50 $0.51 $0.53 $0.55 $0.56 Total O&M and A&G $1.37 $3.80 $3.84 $3.95 $4.07 $4.20 $4.33 $4.46 $4.59 $4.73 $4.88 Debt Service Payment on Financing $0.00 $2.42 $2.64 $2.64 $2.64 $0.22 $0.00 $0.00 $0.00 $0.00 $0.00 Total Expenses $0.89 $15.63 $17.67 $17.87 $17.99 $15.87 $16.09 $16.57 $17.05 $17.55 $18.06 Net Income -$0.89 -$3.32 -$1.89 -$0.44 $1.27 $5.40 $7.39 $9.37 $11.60 $14.10 $16.90 Net Income Allocation
Reserve Fund Contribution $9.96 -$3.32 -$2.93 -$0.44 $0.52 $0.07 $0.11 $0.12 $0.12 $0.12 $0.12 Start- up Funding Payments + Collateral -$10.85 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 Discretionary Programs/Additional Rate Discounts $0.00 $0.00 $1.04 $0.00 $0.75 $5.32 $7.28 $9.26 $11.48 $13.98 $16.78 Total Cash Outlays -$0.89 -$3.32 -$1.89 -$0.44 $1.27 $5.40 $7.39 $9.37 $11.60 $14.10 $16.90 Rate Stabilization Reserve Balance $9.96 $6.64 $3.71 $3.27 $3.78 $3.86 $3.97 $4.09 $4.21 $4.33 $4.45 Reserve Balance Target $3.26 $3.26 $3.71 $3.76 $3.78 $3.86 $3.97 $4.09 $4.21 $4.33 $4.45 55868.00001\42219788.8
M E M O R A N D U M
City of South Lake Tahoe CCA Feasibility
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TABLE 6. TURNKEY CCA FEASIBILITY 10-YEAR PROFORMA, SCENARIO 2 POWER COSTS, $MILLIONS 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036
Revenues
Retail Rate Revenues $0.00 $12.33 $15.80 $17.45 $19.27 $21.29 $23.51 $25.97 $28.68 $31.68 $34.99 Uncollectible $0.00 -$0.01 -$0.02 -$0.02 -$0.02 -$0.02 -$0.02 -$0.03 -$0.03 -$0.03 -$0.04 Total Rate Revenue $0.00 $12.32 $15.78 $17.43 $19.25 $21.26 $23.49 $25.94 $28.65 $31.65 $34.96 Expenses
Power Supply
Block Energy Purchases $0.00 $5.41 $6.38 $6.52 $6.30 $6.21 $6.26 $6.32 $6.38 $6.43 $6.48 Renewable Energy $0.00 $2.80 $3.22 $3.96 $4.31 $4.60 $4.90 $5.22 $5.54 $5.88 $6.23 Capacity/Resource Adequacy $0.00 $1.95 $2.29 $2.33 $2.38 $2.42 $2.47 $2.51 $2.56 $2.60 $2.65 Ancillary Services $0.00 $0.16 $0.18 $0.18 $0.18 $0.18 $0.18 $0.18 $0.18 $0.18 $0.18 Total Power Supply $0.00 $10.32 $12.06 $12.99 $13.17 $13.42 $13.81 $14.23 $14.66 $15.09 $15.54 Operating and Administrative
Turnkey Operating Costs $0.56 $1.73 $1.79 $1.84 $1.90 $1.95 $2.01 $2.08 $2.14 $2.21 $2.27 Liberty Fees, Billing $0.03 $0.10 $0.10 $0.11 $0.11 $0.11 $0.12 $0.12 $0.13 $0.13 $0.13 General & Administrative expenses $0.31 $0.51 $0.44 $0.46 $0.47 $0.49 $0.50 $0.51 $0.53 $0.55 $0.56 Total O&M and A&G $1.37 $3.80 $3.84 $3.95 $4.07 $4.20 $4.33 $4.46 $4.59 $4.73 $4.88 Debt Service Payment on Financing $0.00 $2.42 $2.64 $2.64 $2.64 $0.22 $0.00 $0.00 $0.00 $0.00 $0.00 Total Expenses $0.89 $15.08 $17.03 $18.03 $18.29 $16.19 $16.44 $16.94 $17.45 $17.97 $18.51 Net Income -$0.89 -$2.76 -$1.25 -$0.60 $0.97 $5.07 $7.05 $9.00 $11.20 $13.67 $16.45 Net Income Allocation
Reserve Fund Contribution $9.96 -$2.76 -$3.65 -$0.60 $0.91 $0.08 $0.12 $0.12 $0.13 $0.13 $0.13 Start- up Funding Payments + Collateral -$10.85 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 Discretionary Programs/Additional Rate Discounts $0.00 $0.00 $2.40 $0.00 $0.06 $5.00 $6.93 $8.88 $11.08 $13.55 $16.32 Total Cash Outlays -$0.89 -$2.76 -$1.25 -$0.60 $0.97 $5.07 $7.05 $9.00 $11.20 $13.67 $16.45 Rate Stabilization Reserve Balance $9.96 $7.20 $3.55 $2.95 $3.86 $3.94 $4.05 $4.18 $4.30 $4.43 $4.56 Reserve Balance Target $3.12 $3.12 $3.55 $3.80 $3.86 $3.94 $4.05 $4.18 $4.30 $4.43 $4.56