Resolution No. 2023-019RESOLUTION NO. 2023-19
A RESOLUTION OF THE CITY COUNCIL OF THE CITY OF VERNON TO
UPDATE AND IMPLEMENT AN ENERGY COST ADJUSTMENT BILLING
FACTOR PROCEDURE AND COMPUTATION METHOD WHICH
ESTABLISHES AN ENERGY COST ADJUSTMENT TO BE BILLED
UNDER ALL ELECTRICAL RATE SCHEDULES FOR ENERGY
TRANSMITTED, DISTRIBUTED, AND SUPPLIED TO CITY OF VERNON
ELECTRIC CUSTOMERS
SECTION 1. Recitals.
A. The City of Vernon (City) is a chartered municipal corporation of the State of
California that owns and operates a system for the generation, purchase, transmission,
distribution and sale of electric capacity and energy.
B. Pursuant to Vernon Municipal Code Section 13.36.040, existing rates charged for
the distribution of energy supplied by the Vernon electric system may include an energy
cost adjustment billing factor (ECABF) to be determined by the City Council and which
may be adjusted from time to time by resolution when, in the City Council’s opinion, such
changes are necessary for the sound financial operation of the Public Utilities Electric
Fund.
C. On April 2, 2019, the City Council of the City of Vernon adopted Resolution 2019-
06 establishing an ECABF procedure and computation method to ensure that electric
customers are billed for the true cost of service, and to allow Vernon Public Utilities (VPU)
to adjust the ECABF when fluctuations in the energy market impact the cost of service.
D. Based on the results of the 2023 Electric Cost of Service Analysis and Rate Design
Study (Study), including forecasted power supply expenses, the General Manager of VPU
has recommended an ECABF of $0.02 effective July 1, 2023, $0.02 effective July 1, 2024,
and $0.01 effective July 1, 2025. The recommended ECABF is subject to adjustment to
the extent that actual power supply expenses differ from those included in the Study’s
underlying assumptions to ensure the proper recovery of power supply expenses,
consistent with the Procedures for Calculating the ECABF attached hereto as Exhibit A.
E. During Fiscal Year 2025-2026, if not earlier depending on current financial and
economic conditions as well as any changes to the underlying assumptions of the Study,
VPU plans to update the Study to include factors such as electric load projections,
operating and maintenance expenses, Malburg Generating Station (MGS) expenses,
power supply expenses, multi-year capital plan, and related assumptions, including
financial reserves, to determine the appropriate base rates and ECABF to ensure the
costs to deliver electric service to customers are properly recovered.
F. The City Council of the City of Vernon desires to approve and implement these
adjustments to the ECABF.
G. The City Council of the City of Vernon finds such adjustment is necessary for the
sound financial management of the Public Utilities Electric Fund.
H. The City Council of the City of Vernon has heard and considered all evidence, both
written and oral, presented in consideration of the proposed ECABF.
NOW, THEREFORE, BE IT RESOLVED BY THE CITY COUNCIL OF THE CITY
OF VERNON AS FOLLOWS:
SECTION 2. The City Council of the City of Vernon finds and determines that the
above recitals are true and correct.
SECTION 3. The City Council of the City of Vernon hereby approves and adopts
the updated Energy Cost Adjustment Billing Factor Calculation, attached hereto as
Exhibit A.
SECTION 4. The effective date of the implementation of the ECABF shall be as
follows: ECABF of $0.02 effective July 1, 2023, $0.02 effective July 1, 2024, and $0.01
effective July 1, 2025, subject to adjustment in accordance with the Procedures for
Calculating the ECABF (Exhibit A), or as may be rescinded or amended by resolution of
the City Council of the City of Vernon.
SECTION 5. All resolutions or parts of resolutions, specifically Resolution No.
2019-06, not consistent with or in conflict with this resolution are hereby repealed.
SECTION 6. The City Clerk shall certify the passage and adoption of this
resolution and enter it into the book of original resolutions.
APPROVED AND ADOPTED August 15, 2023.
________________________
ATTEST: CRYSTAL LARIOS, Mayor
LISA POPE, City Clerk
(seal)
APPROVED AS TO FORM:
ZAYNAH N. MOUSSA, City Attorney
Resolution No. 2023-19
Page 2 of 6
___________________
I CERTIFY THAT RESOLUTION NO. 2023-19 was passed and adopted by the City
Council of the City of Vernon at the Regular Meeting on August 15, 2023, by the following
vote:
AYES: 5 Council Members: Lopez, Rivera, Ybarra, Merlo, Larios
NOES: 0
ABSENT: 0
ABSTAIN: 0
________________________________
LISA POPE, City Clerk
(seal)
Resolution No. 2023-19
Page 3 of 6
___________________
City of Vernon
Procedures for Calculating the
Energy Cost Adjustment Billing Factor
The Energy Cost Adjustment Billing Factor (ECABF) will be applied based on kilowatt-hour
(kWh) billed under all schedules to reflect changes in the cost of energy, fuel, and extraordinary
expenses. The ECABF shall be calculated monthly and applied to customer bills for the
following service month.
The ECABF, expressed to the nearest $ 0.0001 per kilowatt- hour (kWh), is to be calculated
pursuant to the following equation:
ECABF = ((ECa - ECb) + (FCa - FCb) + C)
Se
Where,
ECABF= Energy Cost Adjustment Billing Factor per kilowatt-hour sold
ECa = Actual cost of Energy (other than cost of renewable energy) for the current month
ECb = Energy costs (other than cost of renewable energy) in base rates for the current month
FCa = Actual Natural Gas Fuel costs for the current month
FCb = Natural Gas Fuel costs in base rates for the current month
C = Extra ordinary expenses
Se = Estimated Kilowatt- hour sales in the following service month
Resolution No. 2023-19
Page 4 of 6
___________________
ECABF Calculation Sheet
Exhibit A is attached to provide the calculation sheet for all months.
Energy Costs (EC)
Items 1 through 6 represent the actual cost of energy (ECa) to be used in calculating the ECABF.
It is comprised of the cost of capacity, energy (other than the cost of renewable energy),
transmission service and grid management charge for the current month.
Items 7 through 12 represent the cost of energy in the base rates (ECb) to be used in calculating
the ECABF. It is comprised of the cost of capacity, energy (other than the cost of renewable
energy), transmission service and grid management charge in the base rates for the current
month.
Fuel Cost (FC)
Items 14 through 19 represent the actual cost of fuel (FCa) to be used in calculating the ECABF.
It is comprised of the cost of fuel and natural gas transportation for the current month.
Items 20 through 25 represent the cost of fuel in base rates (FCb) to be used in calculating the
ECABF. It is comprised of the cost of fuel and natural gas transportation for the current month.
Extraordinary Expenses (C)
Items 27 represents extraordinary expenses incurred in the current month.
Estimated Kilowatt Hours (Se)
Item 29 represents the estimated kilowatt hour sales in the next service month.
Adjustment for Interruptible Service Under Recovery
Represents the revenue shortfall from providing the bill credit to Interruptible Service for 2.5 %
of the prevailing average billing rate.
Energy Cost Adjustment Billing Factor (ECABF)
Item 36 represents the Energy Cost Adjustment Billing factor for the current month. Applies to
all services except for Interruptible Service.
Interruptible Service ECABF
Item 37 represents the Energy Cost Adjustment Billing factor to be charged to Interruptible
Service for the current month.
ECABF Over/(Under) Collection
The ECABF Over/(Under) Collection will be tracked monthly. There shall be a true-up of the
ECABF Over/(Under) collection amount on a quarterly basis, if not earlier, subject to the extent
that actual power supply expenses differ from those included in the 2023 Electric Cost of Service
Analysis and Rate Design Study’s underlying assumptions to ensure the proper recovery of
power supply expenses. The ECABF over/(under) collection amount, or portion thereof, may be
included in the calculation of the ECABF for that month.
Resolution No. 2023-19
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___________________
Exhibit A
City of Vernon
Energy Cost Adjustment Billing Factor (ECABF)
Calculation Sheet
For the Month________________
To be applied to _____ monthly Billables billed in __________
Energy Cost
Actual Energy Cost (ECa):
1 Energy and Capacity $0
2 Transmission (TAC, SCE, LADWP) $0
3 CAISO Grid Management and A/S Charge $0
4 Less: Wholesale sales revenue (RA, AS) $0
5 Less: Transmission Revenue Requirement Revenue $0
6 Actual Energy Cost (ECa) Total: [1+2+3-4-5]$0.0000
Energy Cost in base rate (ECb):
7 Energy and Capacity $0
8 Transmission (TAC, SCE, LADWP) $0
9 CAISO Grid Management and A/S Charge $0
10 Less: Wholesale sales revenue (RA, AS) $0
11 Less: Transmission Revenue Requirement Revenue $0
12 Energy Cost in base Rate Cost (ECb) Total: [7+8+9-10-11]$0.0000
13 Energy Cost difference [6-12]$0.0000
Fuel Cost
Actual Natural Gas Fuel Cost (FCa):
14 Fuel (L&P and Gas) $0
15 Transportation (L&P and Gas) $0
16 Less:Wholesale Sales (Prepay and Retail) $0
17 Less: Retail Sales $0
18 Less: Retail service transportation Charge $0
19 Actual Natural Gas Fuel Cost Total( FCa): [14+15-16-17-18]$0.0000
Natural Gas Fuel Cost in base rates (FCb):
20 Fuel (L&P and Gas) $0
21 Transportation (L&P and Gas) $0
22 Less:Wholesale Sales (Prepay and Retail) $0
23 Less: Retail Sales $0
24 Less: Retail service transportation Charge $0
25 Natural Gas Fuel Cost in base rates (FCb): [20+21-22-23-24]$0.0000
26 Natural Gas Fuel Cost difference [19-25]$0.0000
Extraordinary Expense
27 Extraordinary Expense $0.0000
Adjustment for Interruptible Service Under Recovery
28 Cost difference [13+26+27+39]$0.0000
29 Estimated Kilowatt-hours sales for the next service month (Se)ΨϬ͘ϬϬϬϬ
30 Prevailing Billing Rate (Interruptible), per KWh $0.0000
31 Interruptible Service Kilowatt Hours Sold $0.0000
32 Interruptible Service Charges, ([28/29] - 0.025*[ 30])*[31]$0.0000
Calculation of ECABF
33 Cost Difference , [13+26+27+39]$0.0000
34 Interruptible Service Charges, [32]$0.0000
35 Kilowatt Hours Sold (Se), [29]$0.0000
36 Energy Cost Adjustment Billing Factor, ([33] - [ 32])/[35-31] $0.0000
Interruptible Service ECABF
37 Interruptible Service ECABF, ([28/29] - 0.025*[30]) $0.0000
ECABF Over/(Under) Collection
38 ECABF Monthly Over/(Under) Collection $0.0000
39 ECABF Cumulative Over/(Under) Collection $0.0000
Resolution No. 2023-19
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___________________
City Council Agenda Report
Meeting Date:August 15, 2023
From:Todd Dusenberry, General Manager of Public Utilities
Department:Public Utilities
Submitted by:Adriana Ramos, Administrative Analyst
Subject
Vernon Public Utilities Electric Cost of Service Analysis and Updated Energy Cost Adjustment
Billing Factor
Recommendation
Adopt Resolution No. 2023-19 to update and implement an Energy Cost Adjustment Billing
Factor procedure and computation method which establishes an Energy Cost Adjustment to be
billed under all electrical rate schedules for energy transmitted, distributed, and supplied to the
City of Vernon electric customers.
Background
The last Electric Cost of Service Analysis and Rate Design Study (Study) for Vernon Public
Utilities (VPU) was completed in 2019 and included a multi-year financial plan. On April 2, 2019,
the City Council adopted Resolution No. 2019-07 approving and adopting a four-step rate
adjustment for Fiscal Years 2020 through 2023 as follows: (i) a 0.8% electric rate increase
effective July 1, 2019, (ii) a 1.9% electric rate increase effective July 1, 2020, (iii) a 4% electric
rate increase effective July 1, 2021, and (iv) a 4% rate increase effective July 1, 2022.
On April 4, 2023, the City Council approved an agreement with NewGen Strategies & Solutions,
LLC (NewGen) to conduct a new Study and to provide rate adjustment and rate design
recommendations. This analysis offers the best strategic approach to determine the appropriate
rates to address stakeholder needs and ensure that only the costs to operate the utility are built
into VPU’s rates. The approach for this Study involves the incorporation of VPU’s data, market
information, and community input to provide an integrated view designed to allow VPU to make
long-term financial, operational, and capital planning decisions.
Furthermore, because of this Study, VPU will have the financial model necessary to respond to
market changes that impact customers. One of the objectives of this Study is to ensure VPU
continues to provide competitive and stable rates to its customers. The Study with NewGen
consisted of the following:
1) System Level Load Forecast
2) Electric Cost of Service Analysis
3) Rate Design
4) Financial Forecast Model
5) Financial Reserves Policy
The overall financial and operational goals of the Study were to confirm that:
1) VPU continues to meet its bond covenant requirement to maintain a 1.1 Debt Service
Coverage Ratio (DSCR) and a target of 1.2 DSCR was established for setting rates in the
forecast period.
2) A minimum level of cash reserves is established at approximately 180 days and a target of
300 days cash on hand is maintained with rates.
3) Reasonable electric load growth estimates are included in the multi-year financial plan.
4) VPU provides competitive base rates and a stable Energy Cost Adjustment (ECA) to
customers.
5) A long-term VPU Financial Reserves Policy is established.
6) VPU continues to maintain the highest reliability standards and customer service to customers.
VPU has met the above goals while continuing to respond to inflation and supply chain issues,
including higher costs for energy, natural gas, materials and supplies, chemicals, and
construction costs, and continues to provide exceptionally reliable service.
The following points represent changes to VPU’s Electric Cost of Service Analysis since the last
Study and are the key drivers of higher costs, and place upward pressure on electric rates:
1) California Independent System Operator (CAISO) energy prices are higher and natural gas
costs are significantly higher when compared to historical prices.
2) Electric load reductions are seen in the 2024 load forecast when compared to the 2019 load
forecast; however, beginning in Fiscal Year (FY) 2025-26, VPU is forecasting higher new electric
load growth.
3) The Malburg Generating Station (MGS) acquisition and debt service requirements are now
included in the DSCR calculation.
4) The FY 2023-24 VPU Electric Fund Forecast when compared to the approved budget includes
higher wholesale revenues, adjustments for Economic Development Rates, and higher insurance
costs.
As part of the FY 2023-24 budget process, VPU engaged in multiple outreach meetings regarding
VPU’s financial and operating plans, which included communication about the Utility’s Study, as
well as solicitation of customer feedback regarding the state of the Utility. Furthermore,
information regarding the Utility's financial and operating plans was shared by VPU staff during
a Joint Special Business and Industry Commission/Green Vernon Commission meeting and a
Business Breakfast on April 25, 2023 and May 3, 2023, respectively.
On August 10, 2023, VPU presented the results of the Study to the Vernon Business and Industry
Commission. Following staff’s presentation, the Commission discussed the results of the Electric
Cost of Service and Rate Design Study. The information was received favorably by the
Commission.
As part of the proposed budget for Fiscal Year (FY) 2023-24, the Utility included a proposed five
percent (5%) electric rate increase to address factors beyond the Department’s control, including
rising energy and natural gas costs, supply chain issues, and regulatory and legislative
mandates, as well as the departure of key business customers. On June 6, 2023, City Council
adopted Resolution No. 2023-13, amending the electric rates for FY 2023-24 as recommended
with a five percent (5%) rate adjustment effective July 1, 2023. Following the results of the Study,
Staff weighed several options focusing on the impact of any future base rate and ECA
adjustments on customers and recommends the following:
1) VPU’s strategy is to meet its revenue requirements and minimize rate adjustments to
customers by implementing an ECA of $0.02 in both FY 2023-24 and FY 2024-25 and an ECA
of $0.01 in FY 2025-26.
2) Staff is recommending no additional Base Rate adjustments after FY 2023-24 and no future
ECA adjustments after FY 2025-26. However, the ECA is subject to change to the extent that
actual power supply expenses differ from those included in the Study’s underlying assumptions
to ensure the proper recovery of power supply expenses.
3) VPU shall reconcile the ECA monthly, including the tracking of any ECA under collection or
over collection amount. If necessary, VPU, at a minimum, shall have quarterly ECA adjustments
of the baseline ECA (amounts noted in paragraph one above), including any under collection or
over collection amount. VPU will strive not to exceed an ECA of $0.04.
4) VPU currently plans to utilize $18 million from the Utility’s Expense Stabilization Fund to meet
its revenue requirements in FY 2023-24.
5) Establish a VPU Financial Reserves Policy, which is expected to be presented to the City
Council in September 2023.
6) VPU plans to update the Study within three years, if not sooner, depending on customer,
financial, and economic conditions as well as responding to changes in the underlying
assumptions included in the Study.
As a result of this strategy, rates for the larger commercial and industrial classes, such as the
TOU‐V and TOU‐Vt, are still extremely competitive, including comparisons with the Los Angeles
Department of Water and Power (LADWP) and Southern California Edison (SCE). In addition,
surrounding public utilities are in the process of completing similar Cost of Service and Rate
Design studies. The rate trends for neighboring publicly-owned utilities reflect the following:
1) Burbank Water and Power just passed rate increases for two years (FY 2024 and 2025) of
8.5% and 8% per year.
2) Recent CAISO market prices have put upward pressure on all utilities, increasing energy cost
adjustment rates throughout the state.
3) Riverside is also currently considering but has not yet approved rate increases of 7%, 7%, 7%,
2% and 2% for the next five years. The rate increases are targeted more at residential than
commercial and industrial customers, but industrial is potentially looking at 6% increases.
Pursuant to Vernon Municipal Code Section 13.36.040, any changes in the ECA shall be made
from time to time by resolution of the City Council when, in the City Council’s opinion, such
changes are necessary for the sound financial operation of the Public Utilities Electric Fund.
The proposed resolution has been reviewed and approved as to form by the City Attorney’s
Office.
Fiscal Impact
The utilization of $18 million from VPU’s Expense Stabilization Fund in FY 2023-24 and an
Energy Cost Adjustment of $0.02 FY 2023-24 and FY 2024-25 for each fiscal year and an Energy
Cost Adjustment of $0.01 in FY 2025-26 are expected to meet VPU’s forecasted revenue
requirements.
Attachments
1. Resolution No. 2023-19
2. Cost of Service Analysis and Rate Design Study Report
Economics | Strategy | Stakeholders | Sustainability
www.newgenstrategies.net
225 Union Boulevard
Suite 450
Lakewood, CO 80228
Phone: (720) 633-9514
July 27, 2023
via email
Richard Corbi
Planning and Analysis Manager
City of Vernon | Vernon Public Utilities
4305 Santa Fe Avenue
Vernon, CA 90058
Subject: Electric Utility Cost of Service Study and Financial Forecast Recommendations
Dear Mr. Corbi:
NewGen Strategies and Solutions, LLC (NewGen) was retained by Vernon Public Utilities (VPU) to perform
an Electric Utility Cost of Service (COS) and provide a financial forecast of operating results over a seven‐
year period. The critical part of this study was identifying necessary rate changes to ensure the financial
sustainability of the utility over the forecast period. The primary goal of the COS was to identify system
average and the energy cost adjustment (ECA) rate changes required to maintain the key financial metrics
which support the financial sustainability of the utility.
Summary of Electric Utility System
VPU is a municipal electric, water, fiber, and natural gas utility. This study focused on the electric utility,
which provides electric service to roughly 1,900 customers in the City of Vernon, California. The majority
of VPU's customers are commercial and/or industrial electric customers. VPU sold roughly 1.1 million
MWh of electricity in fiscal year 2022 and had a peak demand of just over 190 MWs. VPU provides power
through a combination of VPU‐owned generation, purchase power contracts, and market purchases.
VPU, like many other California utilities, are facing increasing demands for renewable energy as mandated
by the State in addition to volatile electric and gas market prices.
VPU recently issued a significant amount of debt over an eight‐year period to re‐purchase the Malburg
Generating Station (MGS), eliminating the existing purchase power agreement and bringing operations
and expenses directly in‐house. VPU’s debt associated with MGS will end in 2029 which provides the
utility significant flexibility in funding, identifying additional power supply options, and setting retail rates.
Cost of Service and Rate Design Overview
The COS and rate making process typically includes five steps as follows:
1. Financial Forecast and Determination of the Revenue Requirement – The first step examines the
utility’s financial needs and determines the amount of revenue that must be generated from rates.
For municipal utilities, the revenue requirement is determined on a “cash basis.” A “cash basis”
analysis examines the cash obligations of the utility such as operations and maintenance (O&M)
expenses, debt service, cash funded capital projects, and city transfers. The key component to this
step for VPU was to develop a financial forecast to project revenues and expenses under a series of
scenarios and options. In our analysis of the electric rates and the development of the revenue
requirement, NewGen relied upon VPU's Fiscal Year (FY) 2024 Budget and forecasts revenues and
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Richard Corbi
July 27, 2023
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VPU Financial Forecast Letter Report 072723
expenses through 2030. The focus of the rate recommendations and revenue requirements was the
forecast period of FY 2024 through FY 2026.
2. Functionalization of Costs – The revenue requirement is then assigned to the particular function or
sub‐function of the utility. Electric utilities like VPU typically have power supply, transmission,
distribution, and customer service functions.
3. Classification of Costs – Once costs are functionalized, costs are then classified based on the
underlying nature of the costs. Of particular importance is the determination of fixed versus variable
costs. Fixed costs remain a financial obligation of the utility regardless of the amount of energy
produced whereas variable costs fluctuate based on system energy requirements. Further, fixed and
variable costs are associated with utility requirements to meet customer demand, energy, and
customer service needs.
4. Allocation of Costs – Once costs are classified, costs are then allocated to the various customer
classes. Allocation factors align with cost classification. Demand‐related costs are allocated on
measures of class demand such as class contribution to the system coincident peak (CP). Energy
allocation factors are based on energy consumed by customers. Customer allocation factors are
based on the number of customers.
5. Rate Design – The fifth, and final, step is rate design, which translates COS results into rates for each
customer class. In this case, the final recommendations for VPU were system level base rate increases
which then determined the required ECA rates. The effort to date did not set rates for each individual
class as no rate increases were recommended other than small adjustments to the ECA as explained
later in this letter.
Financial Forecast
NewGen developed a financial forecast to support the eventual development of the annual and Test Year
Revenue Requirements. This financial forecast was the focus of the overall Study, as FY 2024 system‐wide
rate increases were adopted during this Study. Thus, the financial forecast focused on identifying
additional base rate or subsequent ECA changes required to maintain key financial metrics in FY 2025 and
FY 2026. The financial forecast was based on VPU’s FY 2024 budget, load projections, a power supply cost
projection from Ascend Analytics (Ascend), a five‐year capital plan, and related assumptions and cost
escalation factors. The following were the key inputs and assumptions in the forecast:
Ascend Power Supply Forecast: Ascend provided forecasts costs based on providing power and
capacity to serve the retail loads. The power supply forecast included natural gas costs, purchased
power costs, sales revenues to the CAISO market, purchases in CAISO market to serve load, Renewable
Energy Credit (REC) expenses, and carbon emission costs.
Debt Service: Debt service projections were provided by VPU based on existing outstanding debt.
There are no additional or future debt issuances included in the forecast.
Capital Plan: VPU includes a cash‐funded capital plan of approximately $16 million per year during
the Study period.
Inflation and Escalation Factors: Several different escalation factors were used to project VPU’s
individual chart of accounts and expenses through 2029. These included basic inflation factors linked
to the U.S. general inflation indicators, labor expenses inflation, construction cost inflation, and
transmission access charge forecasts.
Load Forecast: The VPU load forecast includes current base load projections, new customer cited
distributed energy, energy efficiency, growth in electric vehicle load, and specific customer growth in
certain market segments. The overall load forecast shows growth in load across the Study period.
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VPU Financial Forecast Letter Report 072723
In addition to the key inputs and assumptions used to project revenues and expenses, NewGen calculated
key financial metrics commonly used to maintain and measure financial sustainability. There were two
key metrics that were monitored and maintained:
Debt Service Coverage Ratio (DSCR): Net revenues available after subtracting operating expenses
that are available to pay debt service. VPU has a bond covenant requirement to maintain a 1.1 DSCR
and set a target of 1.2 DSCR for setting rates in the forecast period.
Cash Balances / Days Cash on Hand: Number of days of operating expenses available in unrestricted
cash reserves. VPU set a minimum level of cash reserves at approximately 180 days and a target of
300 days cash on hand to maintain with rates.
NewGen used these metrics as the primary driver in developing the forecast and evaluating alternative
rate recommendations. The summary level financial forecast results are shown in Table 1 with the existing
base rate increases. Based on the projected power supply cost recovered in the base rate revenues, the
resulting ECA rates must be $0.02 per kWh for FY 2024 FY 2025 and $0.01 per kWh for FY 2026.
Table 1
Financial Forecast Results
Item 2024 2025 2026 2027 2028 2029
Load (MWh) 1,120,945 1,269,826 1,473,633 1,638,096 1,703,063 1,820,282
Base Rate Increases 5.0% 0.0% 0.0% 0.0% 0.0% 0.0%
ECA ($/kWh) $0.0200 $0.0200 $0.0100 $0.0000 $0.0000 $0.0000
Operating Revenues $210,048,404 $236,225,700 $257,203,864 $267,686,939 $277,873,635 $295,950,566
Operating Expenses
Power Supply $110,730,043 $119,064,978 $134,374,258 $144,129,192 $151,117,129 $158,434,705
Transmission $17,552,410 $18,037,380 $18,537,189 $19,064,248 $19,607,671 $20,168,011
Customer $966,565 $999,024 $1,032,651 $1,067,831 $1,104,283 $1,142,055
A&G $15,208,484 $15,668,479 $16,148,060 $16,658,880 $17,192,270 $17,749,668
Total Operating Expenses $144,457,502 $153,769,860 $170,092,158 $180,920,150 $189,021,353 $197,494,439
Contributions From
Reserves $18,000,000 $0 $0 $0 $0 $0
Available for Debt Service $83,590,902 $82,455,840 $87,111,706 $86,766,789 $88,852,282 $98,456,127
Debt Service $69,710,206 $69,706,538 $69,703,002 $64,704,689 $64,703,340 $9,215,355
DSCR 1.20 1.18 1.25 1.34 1.37 10.68
Other Expenses
(Revenues) $(24,654,814) $(8,280,635) $(8,110,235) $(8,337,916) $(8,773,589) $(10,051,479)
Capital Expenses $20,038,000 $15,750,000 $15,900,000 $14,700,000 $14,800,000 $16,237,600
Over (Under Recovery) $18,497,511 $5,279,937 $9,618,939 $15,700,016 $18,122,532 $83,054,651
Cash Balance $91,329,532 $96,609,469 $106,228,408 $121,928,425 $140,050,956 $223,105,607
Days Cash on Hand 231 229 228 246 270 412
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Richard Corbi
July 27, 2023
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VPU Financial Forecast Letter Report 072723
Based on the previously approved 5% rate increase in 2024 and the use of the ECA at $0.02 per kWh in
2024 and 2025, and $0.01 per kWh in 2026, VPU meets its target DSCR each year and moves towards the
targeted level of cash reserves over time. During 2024, there is the need to contribute $18 million from
cash reserves to meet the target DSCR; however, no future contributions from reserves are necessary to
maintain the target DSCR.
Overall, power supply expenses increase each year; however, this is also influenced by the increasing load
VPU must serve each year. Thus, as the load increases, VPU must purchase more power to serve that
load. Other operating expenses are stable year to year in the forecast period. The increased debt service
associated with MGS ends in 2029, and as seen in Table 1, it leads to a substantial increase in contributions
to the cash reserves from $18.1 million in 2028 to $83.0 million in 2029. This elimination of the MGS debt
service in 2029 places VPU in a very flexible rate position and healthy financial position to prepare for
future power supply contracts or reinvestments in owned generation / MGS.
Please note, the ECA rates included in Table 1 are based on the projected power supply costs provided by
Ascend. These actual costs incurred by VPU each year will change from the projections included in the
table. Thus, as load, power supply costs, market prices, and other variables affecting power supply costs
change, the ECA will also need to change to ensure proper cost recovery. To the extent power supply
prices and costs decline from those projected in the table, the ECA would also go down.
Recommendations
Based on the financial forecast and results shown in Table 1, NewGen recommends VPU continue its
utilization of the ECA to ensure proper recovery of power supply costs and maintain an expected
$0.02 per kWh charge in 2024 and 2025, declining to $0.01 per kWh in 2026. At the ECA rates, projected
power supply costs, and other projected operating costs, VPU will not require any additional base rate
increases in 2025 and 2026. During 2026, VPU should consider an update of the COS and eventual update
of rates across the customer classes, if the COS results identify any potential shifting in the cost recover
from classes it could be implemented at the start of FY 2027.
As no additional rate increases are recommended in the 2024 to 2026 period other than those already
approved, the remaining portions of the COS study such as final allocation of costs to the customer classes
remains in draft format awaiting a COS update in subsequent years. Our recommendation results in no
material changes to each customer class’ rates other than the application of the ECA rates. The
recommendations maintain VPU’s financial performance and support stability in customer’s rates and bills
during a very volatile time in California’s energy markets.
The resulting rates for the larger commercial and industrial classes for VPU, such as the TOU‐V and TOU‐Vt,
after the 2024 base rate increase and ECA recommendations maintains VPU’s competitive position in the
Southern California electric market with Los Angeles Department of Water and Power (LADWP) and
Southern California Edison (SCE).
Sincerely,
NewGen Strategies and Solutions, LLC
Tony Georgis
Managing Partner – Energy Practice
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