HomeMy WebLinkAbout9 c EDS TDPUD Electric COSA Report 11 17 21 attch 3Electric Cost of Service Study
Final Draft
Truckee-Donner Public
Utility District
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PREPARED BY EES CONSULTING
November 17, 2021
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570 Kirkland Way Suite 100 Kirkland, WA 98033 425-889-2700 Fax 866-611-3791 www.eesconsulting.com
Georgia Texas Alabama New Hampshire Wisconsin Florida Maine Washington California
Amber Gschwend, Managing Director
amber.gschwend@gdsassociates.com
direct 425-655-1042
November 17, 2021
Mr. Michael Salmon
Truckee-Donner PUD
11570 Donner Pass Rd
Truckee, CA 96161
SUBJECT: Electric Cost of Service Study
Dear Mr. Salmon:
It is with pleasure that EES Consulting (EES), a GDS Associates Company, submits this Cost of Service
Analysis Report for Truckee-Donner Public Utility District (District).
We appreciate all of the help you and your staff have provided in conjunction with this study. Please feel
free to contact me directly with any questions or comments.
Very truly yours,
Amber Gschwend
Managing Director, EES Consulting
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Contents
1 EXECUTIVE SUMMARY ............................................................................................... 1
1.1 Revenue Requirement ....................................................................................................................................... 1
1.2 Cost of Service Study ......................................................................................................................................... 4
1.3 Recommendations .............................................................................................................................................. 5
2 OVERVIEW OF RATE SETTING PRINCIPLES ............................................................... 6
2.1 Overview and Organization of Report ......................................................................................................... 6
2.2 Overview of the Analyses ................................................................................................................................. 7
2.3 Types of Utilities................................................................................................................................................... 7
2.4 Overview of Revenue Requirement Methodologies .............................................................................. 7
2.5 Overview of Cost Allocation Procedures .................................................................................................... 8
3 DEVELOPMENT OF THE REVENUE REQUIREMENT ................................................. 10
3.1 Overview of the District’s Revenue Requirement Methodology .................................................... 10
3.2 Development of the Projected Load Forecast and Forecast Revenues ....................................... 10
3.3 Development of Power Supply Costs ....................................................................................................... 11
3.4 Other Operations and Maintenance Expenses ...................................................................................... 11
3.5 Interest and Debt Service .............................................................................................................................. 12
3.6 Rate Funded Capital Expenses .................................................................................................................... 12
3.7 Contributions ..................................................................................................................................................... 12
3.8 Other Revenues ................................................................................................................................................. 12
3.9 Summary of Revenue Requirement........................................................................................................... 13
3.10 Recommendation........................................................................................................................................... 13
4 COST OF SERVICE ANALYSIS .................................................................................... 14
4.1 COSA Definition and General Principles .................................................................................................. 14
4.2 General Ratemaking Principles.................................................................................................................... 15
4.3 Functionalization of Costs ............................................................................................................................. 15
4.3.1 Standard Functionalization ..........................................................................................................15
4.3.2 Functionalization Method .............................................................................................................16
4.4 Classification of Costs ..................................................................................................................................... 16
4.4.1 Standard Classification .................................................................................................................17
4.4.2 Classification Method ....................................................................................................................18
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4.5 Allocation of Costs ........................................................................................................................................... 20
4.5.1 Allocation ........................................................................................................................................20
4.6 Review of Customer Classes of Service .................................................................................................... 21
4.7 Major Assumptions of the Cost of Service Study ................................................................................. 22
4.8 Cost of Service Results ................................................................................................................................... 23
5 PRESENT RATES AND COSA UNIT COSTS ............................................................... 25
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1 Executive Summary
Truckee-Donner Public Utility District (District) retained EES Consulting (EES) to update its most recent
Cost of Service study as part of its ongoing efforts to maintain fiscally prudent and fair rates for its electric
customers. The purpose of this report is to discuss the data inputs, assumptions and results that were part
of developing the rate study.
A comprehensive rate study generally consists of three separate, yet interrelated, analyses. These three
analyses are revenue requirement, cost of service and rate design. This report details the revenue
requirement and cost of service studies.
1.1 REVENUE REQUIREMENT
A revenue requirement analysis compares the overall revenues of the utility to its expenses and helps
determine the overall adjustment to rate levels that is required. For this analysis, a “cash basis” method
was used for determining the District’s revenue requirement. Projected calendar year (CY) 2022 operating
expenses used to determine the revenue requirement in the COSA were provided by the District.
A base case was defined to develop the COSA. This base case assumed the following:
Historic year is CY 2020 (January – December 2020).
Test year/allocation year is CY 2022.
The customer classes included in the COSA are: Permanent Residents, Non-Permanent Residents,
Small Commercial, Medium Commercial, Large Commercial, Temporary Power, and Security Lights.
Public Authority and the water utility accounts, while billed under commercial tariffs, have been
separated into their own rate classes to ensure appropriate cost recovery.
The CY 2021 load forecast included growth rates based on year-to-date actual consumption. The CY
2022 load forecast includes projected load growth of 0.5% across all classes.
FIGURE 1-1: RETAIL SALES PROJECTIONS BY CUSTOMER CLASS
0
20,000,000
40,000,000
60,000,000
80,000,000
100,000,000
120,000,000
140,000,000
160,000,000
180,000,000
2022 2023 2024 2025kWh
Permanent Residents Non-Permanent Residents Small Commercial
Medium Commercial Large Commercial Public Authority
Pumping/Water Dept Temp Power Sec Lights
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Projected retail revenues for CY 2022 were calculated based on projected loads and the District’s
current retail rates.
Projected non-power costs were provided by the District for 2022 through 2023. Expenses were
escalated at 3% annually for forecast year 2024 and 2025.
Projected power supply costs are based on a power supply cost forecast provided by the District for
the period 2022 through 2023. On a dollar per megawatt-hour basis power supply costs are projected
to be $78/MWh in CY 2022. Table 1-1 below shows the projected power supply costs included in the
COSA.
TABLE 1-1: PROJECTED POWER SUPPLY COSTS ($THOUSANDS)
2022 2023 2024 2025
Power Purchases
Truckee-Carson Irrigation District -Lahanton $286 $296 $304 $314
Stampede $211 $219 $225 $232
UAMPs $1,652 $1,569 $1,616 $1,665
TJ Landfill Gas $2,556 $2,645 $2,724 $2,806
Market Purchases (Sales)-$174 -$180 -$186 -$191
Wind $3,853 $3,988 $4,108 $4,231
Other1 $4,680 $4,843 $4,989 $5,138
Total Power Purchases $13,063 $13,380 $13,781 $14,195
Transmission and Ancillary $909 $940 $969 $998
Regulatory -$176 -$182 -$188 -$194
Total $13,795 $14,138 $14,562 $14,999
Total, $/MWh $78.38 $79.93 $81.51 $83.13
1.Resources include NEBO, VEYO, Truckee-Fallon Exchange and EIM.
As shown below, power supply costs are 36 percent of projected CY 2022 total expenses. Figure 1-2 below
shows a breakdown of the projected $32.7 million in CY 2022 total expenses.
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FIGURE 1-2: PROJECTED CY 2022 EXPENSES
Total CY 2022 revenues, including other revenue (non-retail rate revenue) of $1.9 million, are projected
to be $30.3 million, or nearly $2.4 million less than projected expenses. As such, an increase in retail rate
revenue is required in CY 2022. Other revenues include AB32 allowances, customer deposits,
miscellaneous service revenues, pole rental fees, dividends and interest, revenues from wholesale
electricity sales, and line extension revenues.
A summary of the CY 2022 revenue requirement is shown below in Table 1-2.
TABLE 1-2: SUMMARY OF THE REVENUE REQUIREMENT1
CY2022
Revenues
Revenues at Present Rates $28,369,157
Other Income 1,919,840
Total Revenues $30,288,997
Expenses
Power Supply & Transmission $13,795,364
Distribution 6,755,674
Customer Accounts and Services 2,706,357
Administration and General 3,857,227
Rate Funded Capital Projects 10,397,910
Interest & Debt Service 632,394
Reserve fund (Transfers) or Contributions -5,480,990
Total Expenses $32,663,936
Surplus/(Deficiency) in Funds ($2,374,939)
Required Retail Rate Increase/(Decrease)8.5%
Power Supply
37%
Distribution
18%
Customer Accounts
and Services
7%
Administration
and General
10%
Rate Funded Capital
28%
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Given the assumptions detailed above, the results show that, under current retail rates, the District is not
collecting sufficient revenue to meet projected expenses. Rate increases of 8.5% would result in projected
CY 2022 revenues that recover projected CY 2022 expenses.
1.2 COST OF SERVICE STUDY
A cost of service study is concerned with the equitable allocation of the revenue requirement to the
various customer classes of service. As is standard procedure for cost of service analyses, the revenue
requirement for the District was functionalized, classified and allocated.
A COSA can be performed using embedded costs or marginal costs. Embedded costs generally reflect the
actual costs incurred by the utility and closely track the costs kept in its accounting records. Marginal
costs reflect the cost associated with adding a new customer and are based on costs of facilities and
services if incurred at the present time. This study uses an embedded COSA as its standard methodology.
Generally, there are two methodologies that can be used to classify distribution costs: 100 percent
demand and minimum system. The 100 percent demand methodology assumes that the distribution
system is built to meet the non-coincident peak. Therefore, distribution costs using this method are
classified as 100 percent demand-related.
Specific distribution costs are sometimes split between demand and customer according to a minimum
system approach. This approach reflects the philosophy that the system is in place in part because there
are customers to serve throughout the service territory, and that a minimally sized distribution system is
needed to serve these customers even if they only use 1 kilowatt-hour (kWh) of energy per year. The
concept follows that any costs associated with a system larger than this minimal size are due to the fact
that customers “demand” a delivery quantity greater than the minimum unit of electricity and that
therefore, those costs should be treated as demand-related.
Because the residential class usually has a higher share of the number of customers compared to its share
of non-coincident peaks, the minimum system methodology tends to allocate more costs to the
residential customer class and customer charges tend to be higher than with the 100 percent demand
methodology. Demand and customer allocation factors were derived for the minimum system case using
data from the District and other California public utilities.
These results are summarized in Table 1-3 for minimum system and in Table 1-4 for 100 percent demand.
TABLE 1-3: SUMMARY OF COST OF SERVICE ANALYSIS – MINIMUM SYSTEM (CY 2022)
Present Rate
Revenues
Net Revenue
Requirement
Surplus/(Deficiency)
in Present Rates
Rate Increase
(Decrease)
Permanent Residents $7,509,871 $8,348,729 ($838,859)11.2%
Non-Permanent Residents 8,608,730 10,469,475 (1,860,746)21.6%
Small Commercial 4,121,566 3,812,307 309,259 -7.5%
Medium Commercial 1,935,414 1,763,137 172,277 -8.9%
Large Commercial 1,327,805 1,622,814 (295,009)22.2%
Public Authority 3,504,023 3,226,124 277,900 -7.9%
Pumping/Water Dept 1,294,848 1,412,278 (117,430)9.1%
Temporary Power 36,443 50,569 (14,126)38.8%
Security Lights 30,456 38,662 (8,206)26.9%
TOTAL $28,369,157 $30,744,096 ($2,374,939)8.5%
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TABLE 1-4: SUMMARY OF COST OF SERVICE ANALYSIS – 100% DEMAND (CY 2022)
Present Rate
Revenues
Net Revenue
Requirement
Surplus/(Deficiency)
in Present Rates
Rate Increase
(Decrease)
Permanent Residents $7,509,871 $8,006,336 ($496,466)6.6%
Non-Permanent Residents 8,608,730 9,875,617 (1,266,887)14.7%
Small Commercial 4,121,566 3,924,345 197,221 -4.8%
Medium Commercial 1,935,414 1,939,322 (3,908)0.2%
Large Commercial 1,327,805 1,868,902 (541,097)40.8%
Public Authority 3,504,023 3,452,795 51,228 -1.5%
Pumping/Water Dept 1,294,848 1,587,488 (292,640)22.6%
Temporary Power 36,443 50,459 (14,016)38.5%
Security Lights 30,456 38,831 (8,375)27.5%
TOTAL $28,369,157 $30,744,096 ($2,374,939)8.5%
When examining the results shown above in Tables 1-3 and 1-4, it is important to note that the inter-class
cost allocations are based on load data estimates and usage pattern assumptions. Therefore, utilities
often elect not to make rate modifications when deviations are within 10 percent.
1.3 RECOMMENDATIONS
Based on the projected revenue requirement and COSA analysis, the following recommendations are
made:
Using current rates, the District is not collecting sufficient revenues compared to the projected CY
2022 revenue requirement and, as such, an increase in total retail revenue is required.
This report is primarily focused on the allocation of costs in CY 2022. Additional rate increases will be
needed in 2023 and 2024 in order for costs to be fully recovered. A gradual rate increase is
recommended to mitigate any rate shock that might occur if rate increases are delayed.
Some customer class revenue recovery is outside of the 10% band of uncertainty from their cost of
service. The rate adjustments developed should bring those classes closer to their cost of service while
mitigating rate shock to any one class.
The COSA was conducted using two methodologies for allocating distribution system costs. Previous
COSA studies completed for the District utilized the Minimum System approach. It’s recommended
that the District continue with the minimum system approach for cost allocation.
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2 Overview of Rate Setting Principles
EES was retained by the District to perform a comprehensive electric cost of service and rate study.
Performing an electric rate study is necessary to assure that the District’s rates continue to recover the
cost of operations and are structured to be fair, equitable and competitive.
In conducting this study, three inter-related analyses were performed. The first analysis performed was
a revenue requirement analysis. This analysis examines the various sources and applications of funds for
the utility and determines the overall revenue (retail rate) adjustment required of the utility. The next
analysis developed is a cost of service analysis. The cost of service analysis is used to determine the fair
and equitable allocation of the total revenue requirement to the various customer classes of service. The
report concludes with a discussion of the rate design options available to the District and a comparison of
the District’s current and COSA-derived rates.
2.1 OVERVIEW AND ORGANIZATION OF REPORT
In developing electric rates for the District, a major goal of the study is to develop cost-based rates that
meet the District’s revenue requirement needs. It is important to understand that revenue requirement
consists of both operational expenses and capital costs. Failure to collect the full revenue requirement
may lead to a system that is more expensive to operate in the long run, and more susceptible to periodic
outages and failures.
This report is organized such that it follows the steps taken in analyzing and developing the District’s cost
of service. Contained in this section is a generic discussion of the theory and financial principles behind
setting rates. This is followed by a section discussing the development of the revenue requirement
analysis for the District. The next section discusses the cost of service study and the results of that process.
The report concludes with a discussion of the rate design options available to the District.
A technical appendix is attached at the end of this report that details the various analyses using the
minimum system approach to classify distribution costs. The schedules contained in the technical
appendix are referenced throughout the report.
The setting of electric utility rates that are “fair and equitable” is a complex process. This process is
directed, however, by “generally accepted methodologies” that can be used as a guide in developing the
District’s electric rates. At the same time, there are often a number of financial principles or guidelines
that must be taken into consideration during this process. Therefore, the setting of electric rates that are
“fair and equitable” is an integration of these generally accepted methodologies and any related financial
policies or specific considerations from the District.
The purpose of this section of the report is to provide a brief overview of the basic fundamentals of cost
identification and allocation for purposes of developing electric rates. From this base-level of knowledge,
more insight and understanding can be obtained from the following sections of the report that discuss
the specifics of the review of the District’s allocated costs.
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2.2 OVERVIEW OF THE ANALYSES
As discussed previously, there are a number of “generally accepted methodologies” for allocating costs
for ratemaking purposes. However, all of these methodologies share the same basic framework. That is,
in allocating electric costs two separate yet interrelated analyses are generally performed. It is within
these two separate analyses that different methodologies exist. The two analyses contained within the
basic framework for allocating electric costs are revenue requirement analysis and cost of service analysis.
The revenue requirement analysis reviews the various sources of funds and applications of funds for the
utility.
Within the next step of the study, the cost of service analysis takes the results of the revenue requirement
analysis and attempts to equitably allocate those costs to the various customer classes of service (e.g.,
residential, commercial, etc.). This analysis provides a determination of the level of revenue responsibility
of each class of service and the adjustments required to meet the cost of service.
2.3 TYPES OF UTILITIES
As noted above, there are different methodologies that exist for setting electric rates. The first distinction
often made in developing a methodology is the type of utility that is attempting to set the rates. Utilities
are generally divided into two types by ownership—public and private utilities.
Public utilities are generally owned by a municipality, cooperative, county or special district, and are
operated on a not-for-profit basis. Public utilities are generally capitalized by issuing debt and soliciting
funds from customers through direct capital contributions or user rates. Through statute and/or the lack
of profit motive, public utilities do not pay state and federal income taxes. Finally, a public utility is usually
regulated by a publicly elected or appointed City Council, Board of Commissioners or Board of Trustees.
As a point of reference, the District is a public utility regulated by a Board of Directors.
In contrast, private electric utilities are capitalized by issuing debt or equity (stock) to the general public.
The owners of the private utility are its equity contributors, or shareholders. Private utilities are taxable
entities, and finally, they are generally regulated by state public utility commissions. PG&E is an example
of a private electric utility.
These differences in ownership and other characteristics often lead to two different methods for
reviewing revenue requirement needs. A more detailed discussion of the different methodologies that
may be used is provided below.
2.4 OVERVIEW OF REVENUE REQUIREMENT METHODOLOGIES
By virtue of differences noted above for public versus private utilities, revenue requirements are based
upon different elements or methodologies. Most private utilities use what is known as a “utility” or
“accrual” basis of determining revenue requirement or setting rate levels. This convention calculates a
utility’s annual revenue requirement by aggregating a period’s operation and maintenance (O&M)
expenses, taxes, depreciation expense and a “fair” return on investment. Operating expenses include the
labor, materials, supplies, etc., that are needed to keep the utility functioning. Private utilities must also
pay state and federal income taxes, along with any applicable property, franchise, sales or other forms of
taxes. Next, depreciation expense is a means of recouping the cost of capital facilities over the useful lives
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of those facilities as well as generating internal cash. Finally, a return on the capital invested pays for the
utility’s interest expense on indebtedness, provides funds for a return to the utility’s equity holders in the
form of dividends and leaves a balance for retained earnings and cash flow purposes.
In contrast to the “utility” or “accrual” method of developing revenue requirement for private utilities, a
different method of determining annual revenue requirement is often used for public utilities. The
convention used by most public utilities is called the “cash basis” of cost accounting. As the name implies,
a public utility aggregates its cash expenditures to determine its total revenue requirement for a specified
period of time. This methodology conforms nicely to most public utility budgetary processes and is a very
straightforward and easily understood calculation.
Under the “cash basis” approach, there are four component costs. They are operation and maintenance
expenses, taxes, debt service and capital improvements funded from rates. The operating portion of the
revenue requirement, i.e., O&M and taxes, are similar under either methodology. The major difference
between the two methodologies is the way in which capital costs are viewed and handled. Capital costs
under the cash basis approach are calculated by adding debt service to capital improvements financed
with rate revenues. A utility’s depreciation expense is often used as a measure of the reasonable level of
funding required from rates for capital improvement activities. Depreciation expense represents the
current investment of the utility and that portion that has become worn out or obsolete and must be
renewed or replaced. It should further be noted that the two portions of the capital expense component
(principal and interest) are necessary under the cash basis approach because utilities often cannot finance
all capital facilities with long-term debt.
Table 2-1 compares the cash and utility accounting conventions.
TABLE 2-1: CASH VS. UTILITY BASIS COMPARISON
Cash Basis Utility (Accrual) Basis
+O&M Expense +O&M Expense
+Taxes +Taxes
+Capital Improvements Financed with
Operating Revenues (Depreciation Expense)
+Depreciation Expense
+Debt Service (Principal & Interest)+Interest Expense
+Margin
= Revenue Requirement = Revenue Requirement
For this study, a cash basis was used to determine the utility’s revenue requirement.
2.5 OVERVIEW OF COST ALLOCATION PROCEDURES
After the total revenue requirement has been determined, it is allocated to the various customer classes
of service based upon a fair and equitable methodology that reflects the cost-causal relationships for the
production and delivery of the services. This analytical exercise usually takes the form of a “cost-of-
service” study. A cost of service study begins by “functionalizing” a utility’s revenue requirement as power
supply, transmission, distribution and customer. Next, the functionalized costs are “classified” to
demand-, energy- and customer-related component costs. Demand-related costs are those that the utility
incurs to meet a customer’s maximum instantaneous usage requirement and is usually measured in
kilowatts (kW). Energy-related costs are those that vary directly with longer periods of consumption and
are usually measured in kWh. Customer-related costs are those that vary with the number and type of
customers served. These three component costs are then “allocated” to each class of service based upon
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the most equitable method available for each specific cost. At that point, the revenue requirement has
been allocated to each class of service and a determination of the necessary revenue adjustments
between classes of service can be made.
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3 Development of the Revenue Requirement
This section of the report presents the development of the electric revenue requirement for the District.
Simply stated, a revenue requirement analysis compares the overall revenues of the utility to its expenses
and determines the overall adjustment to rate levels that is required.
3.1 OVERVIEW OF THE DISTRICT’S REVENUE REQUIREMENT METHODOLOGY
In developing the revenue requirement, a number of decisions must be made regarding the basic
methodology to be used. As discussed in the previous section of the report, the first decision the District
must make is the method of accumulating costs. The District utilized the “cash basis” approach for
determining revenue requirement. In summary form, the District’s components to its revenue
requirement include the elements shown in Table 3-1.
TABLE 3-1: ELEMENTS OF A CASH BASIS REVENUE REQUIREMENT
+Operation and Maintenance Expenses (O&M)
Power Supply Expense
Transmission Expense
+Distribution Expense
Customer Accounting & Service Expense
Administrative and General Expense
+Debt Service Costs (Principle + Interest)
+Rate Funded Capital
+Franchise Fees
+Taxes
=Total Revenue Requirement
Other Revenue Sources
= Net Revenues Required from Rates
From this basic analytical framework, the next step in determining the revenue requirement methodology
is to select a time period over which to review revenue and expenses. In the case of the District, a calendar
year test period was utilized (January through December). CY 2022 was chosen as the test period for the
cost of service study. The District provided projected CY 2022 and 2023 costs. Revenues from retail rates
and purchased power costs were forecast based on forecast CY 2022 loads. Projected CY 2022 costs are
provided in Schedule 3.1 of the appendix. The District’s revenue requirement allocated to customer
classes can be found in Schedule 3.4 of the model.
3.2 DEVELOPMENT OF THE PROJECTED LOAD FORECAST AND FORECAST REVENUES
The CY 2022 load forecast, including monthly energy consumption, number of customers and billed
demand, was provided by the District. The CY 2022 load forecast includes projected load growth 0.5%
across all customer classes.
The load forecast is a key component of a cost of service study as it is used to allocate costs to the
customer classes and provides the units of consumption used to design final rates. Line losses were
calculated using total CY 2020 system purchases and total CY 2020 customer sales. For CY 2022, line losses
on the secondary system were assumed to be 0.75% while line losses on the primary system were
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assumed to be 0.45 percent. Load factors and coincident factors were determined using the calculated
line losses and actual load data by customer class.
Forecast retail revenues at present rates were calculated for CY 2022 using current retail rate schedules
and forecast CY 2022 loads.
3.3 DEVELOPMENT OF POWER SUPPLY COSTS
The District purchases the majority of its power transactions through UAMPs. The District’s power
portfolio includes both renewable resources (wind and landfill gas), and hydropower. The District also
purchases and sells power on the wholesale market. Power supply costs also include transmission costs
and ancillary services. Projected power and transmission costs were provided by the District.
As with most electric utilities, power supply is one of the District’s largest operating expense.
Approximately $14 million, or 36 percent of the CY 2022 total revenue requirement are power supply and
transmission costs as shown in Table 3-2.
TABLE 3-2: PROJECTED POWER SUPPLY COSTS (THOUSANDS)
2022 2023 2024 2025
Power Purchases
Truckee-Carson Irrigation District - Lahanton $286 $296 $304 $314
Stampede $211 $219 $225 $232
UAMPs $1,652 $1,569 $1,616 $1,665
TJ Landfill Gas $2,556 $2,645 $2,724 $2,806
Market Purchases (Sales)-$174 -$180 -$186 -$191
Wind $3,853 $3,988 $4,108 $4,231
Other1 $4,680 $4,843 $4,989 $5,138
Total Power Purchases $13,063 $13,380 $13,781 $14,195
Transmission and Ancillary $909 $940 $969 $998
Regulatory -$176 -$182 -$188 -$194
Total $13,795 $14,138 $14,562 $14,999
Total, $/MWh $78.38 $79.93 $81.51 $83.13
1.Resources include NEBO, VEYO, Truckee-Fallon Exchange and EIM.
3.4 OTHER OPERATIONS AND MAINTENANCE EXPENSES
Projected CY 2022-2023 expenses were provided by the District based on draft budgets. Projected
operating costs were provided for transmission, distribution, customer service and accounting and
administrative and general expenses categories. Table 3-3 shows the forecast non-power operation and
maintenance expenses (O&M). Overall, these expenses are forecast to escalate at a rate of 3-4% per year.
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TABLE 3-3: PROJECTED NON-POWER O&M (MILLIONS)
2022 2023 2024 2025
Distribution $6.8 $7.0 $7.2 $7.5
Customer Accounts and Services $2.7 $2.8 $2.9 $3.0
Administration and General $3.9 $3.9 $4.0 $4.2
Total $13.3 $13.7 $14.1 $14.6
3.5 INTEREST AND DEBT SERVICE
Total interest and debt service expenses are projected to be $632,394 in CY 2022 which includes long-
term debt expense needed to finance $6.0 million in CY 2022 capital project expenses.
3.6 RATE FUNDED CAPITAL EXPENSES
The District provided the CIP plan in Table 3-4 which includes all rate funded capital expenses.
TABLE 3-4: RATE FUNDED CAPITAL SCENARIOS
2022 2023 2024 2025
Capital Expense After Bond Proceeds $10,397,910 $6,617,937 $8,065,675 $6,161,242
Transfer from Capital Reserve Fund $6,650,000 $650,000 $0 $0
Total Rate-Funded Capital $3,747,910 $5,967,937 $8,065,675 $6,161,242
3.7 CONTRIBUTIONS
The District must make contributions to its reserve funds in order to maintain a financially sound reliable
utility operations. Contributions to the operating reserve, rate reserve fund, vehicle reserve fund and
CalPers interest payments total $1.2 million in 2022 and $0.3 million in 2023 through 2025.
3.8 OTHER REVENUES
Other revenues include AB32 allowance revenues, customer deposits, customer contributions,
miscellaneous service revenue, pole rental fees, dividends and interest, line extension revenue, and sales
for resale. Projected other revenues are provided in Table 3-5 below.
TABLE 3-5: PROJECTED OTHER REVENUES
2022 2023 2024 2025
Joint Use Pole Attachment $277,231 $278,617 $288,369 $298,462
Misc. Service Revenues $115,785 $116,364 $120,437 $124,652
AB32 Allowances $1,000,000 $550,000 $0 $0
Dividends from Affiliates, Interest $19,000 $27,000 $27,945 $28,923
Standby Funds $17,000 $16,600 $17,181 $17,782
Interdepartmental Rental Income $490,824 $572,076 $592,099 $612,822
Total Other Revenues $1,919,840 $1,560,657 $1,046,030 $1,082,641
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3.9 SUMMARY OF REVENUE REQUIREMENT
Once all of the components of the cash basis revenue requirement have been forecast, the parts can be
summed to equal the total revenue requirement. Since the District uses a “cash basis” approach for rate
setting, the basic revenue requirement is presented in that format. A summary of the District’s revenue
requirement for the forecast period is summarized below in Table 3-6.
TABLE 3-6: SUMMARY OF THE 2022 AND 2023 REVENUE REQUIREMENT1
2022 2023
Revenues
Present Rate Revenues $28,369,157 $28,511,003
Other Income 1,919,840 1,560,657
Total Revenues $30,288,997 $30,071,660
Expenses
Power Supply & Transmission $13,795,364 $14,137,861
Distribution 6,755,674 6,994,550
Customer Accounts and Services 2,706,357 2,790,860
Administration and General 3,857,227 3,884,090
Rate Funded Capital Projects 10,397,910 6,617,937
Interest & Debt Service 632,394 441,491
Reserve fund (Transfers) or Contributions -5,480,990 -368,170
Total Expenses $32,663,936 $34,498,619
Surplus/(Deficiency) in Funds ($2,374,939
)
($4,426,960
)
Required Retail Rate Increase/(Decrease)
over Current Rates
8.5%15.5%
Table 3-6 shows that, based on the assumptions detailed above and the District’s current retail rates, the
District is not collecting sufficient revenue to meet projected expenses. Rate increases over present rates
of 8.5% would result in projected revenues that match up with CY 2022 expenses. If rates were not
adjusted for 2022, the 2023 revenue requirement would require rates be increased by up to 15.5%.
3.10 RECOMMENDATION
The District’s projected revenues are not sufficient to cover its projected revenue requirement in CY 2022.
Table 3-6 shows that an 8.5 percent rate increase is needed in CY 2022. The District’s current revenue to
cost balance needs to be continually monitored. Both short- and long-term supply and operating cost
considerations need to be evaluated and analyzed as the Board of Directors works with the District’s
management to reach its operating objectives.
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4 Cost of Service Analysis
The objective of the COSA is to analyze costs and equitably assign those costs to customers commensurate
with the cost of serving those customers. The founding principal of cost allocation is the concept of cost-
causation. Cost-causation evaluates which customer or group of customers causes the utility to incur
certain costs by linking system facility investments and operating costs to serve certain facilities to the
services used by different customers. This section of the report will discuss the general approach used to
apportion the utility’s cost of service and provide a summary of the results.
4.1 COSA DEFINITION AND GENERAL PRINCIPLES
A COSA study allocates the costs of providing utility service to the various customer classes served by the
utility based upon the cost-causal relationship associated with specific expense items. This approach is
taken to develop a fair and equitable designation of costs to each customer class, where customers pay
for the costs that they incur. Because the majority of costs are not incurred by any one type of customer,
the COSA becomes an exercise in spreading joint and common costs among the various classes using
factors appropriate to each type of expense. The COSA is the second step in a traditional three-step
process for developing service rates. The first step is the development of the test period revenue
requirement for the utility, which is the starting input for the COSA. The COSA then spreads the revenue
requirement across the various customer classes, creating per unit costs by class. In the third step, rates
are designed for each customer class, with per unit costs being one consideration in setting the
appropriate rate levels.
A COSA study can be performed using embedded costs or marginal costs. Embedded costs generally
reflect the actual costs incurred by the utility and closely track the costs kept in its accounting records.
Marginal costs reflect the cost associated with adding a new customer and are based on costs of facilities
and services if incurred at the present time. While marginal costs can be valuable for designing rates in
certain instances, marginal costs are generally higher than embedded costs. Therefore, the use of a
marginal COSA study usually requires that all costs be scaled back to a level equal to the embedded cost
revenue requirement established using actual or projected costs from an “accounting” perspective.
This study uses an embedded COSA as its standard methodology. Therefore, the District’s embedded cost
revenue requirement and existing rate base investment are used in developing the COSA results.
There are three basic steps to follow in developing a COSA, namely:
Functionalization
Classification
Allocation
Functionalization separates costs into major categories that reflect the utility’s plant investment and
different services provided to customers. The primary functional categories are production, transmission,
distribution and general.
Classification determines the portion of the cost that is related to specific cost-causal factors, such as
those that are demand-related, energy-related or customer-related. Production costs are related to
supplying and transporting power to customers on the system. Transmission costs are related to the bulk
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transfer of power throughout the system, which is designed to meet the peak demand requirement. The
distribution system is designed to extend service to all customers attached to the system and to meet the
peak load capacity requirement of each customer. Additionally, costs can be classified based on system
revenues or directly assigned to a customer or group of customers.
Allocation of costs to specific customer classes is based on the customer’s contribution to the specific
classifier selected. For instance, demand-related costs are allocated to a customer group using that
customer group’s contribution to the particular measurement of system demand, whether coincident
peak, non-coincident peak or some variation determined to be appropriate for the particular cost item.
An analysis of customer requirement, loads and usage characteristics is completed to develop allocation
factors reflecting each of the classifiers employed within the COSA. The analysis may include an evaluation
of the system design and operations, its accounting and physical asset records, customer load data and
special studies.
4.2 GENERAL RATEMAKING PRINCIPLES
While this section does not address the design of rates, it is important to note that the COSA results will
be one of the considerations when the process of designing rates for various customer classes begins. The
basic goals of rate design include:
The utility has an ability to collect the appropriate revenue requirement
Utility revenues and customer rates are stable and predictable
Proper price signals are sent to create efficiency of resources
Rates are fair and equitable among customers and avoid undue discrimination
Rates are simple, easy to understand and feasible for the utility to implement
The COSA is generally used to assist in meeting the second and fourth goals of rate design. Price signals
are best if they reflect the specific costs incurred. Rates are generally considered fair and equitable if
customers are deemed to pay their share of the costs incurred by the utility. Additionally, the first goal is
met as long as the COSA is based on the appropriate revenue requirement, and the use of a consistent
COSA methodology contributes towards the second goal. Rates are more stable through time if the COSA
methodology is not significantly changed every time a rate application is made.
4.3 FUNCTIONALIZATION OF COSTS
The first step in the COSA process following finalization of the revenue requirement is to functionalize the
revenue requirement. Functionalization is the separation of cost data into the functional activities
performed in the operation of a utility system (i.e., power supply, transmission, distribution and customer
service). Functionalization was accomplished using the District’s system of accounts, which largely
segregates costs in this manner.
In addition to the functionalized costs, certain joint costs are spread to each functional category based on
the relationship of the joint cost to the business function. These joint costs include such items as
administrative and general costs.
4.3.1 Standard Functionalization
Plant investment costs or rate base are generally functionalized into production, transmission, distribution
and general cost categories. The functionalization of rate base typically is very straightforward as costs
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for the different functions are readily identifiable and rate base accounts are maintained by functional
categories.
Expense accounts are also typically kept according to these basic functional categories, with expense
items associated with certain types of plant being treated in the same manner as the corresponding plant
account.
The two areas where there generally are differences in functionalization among utilities are in the
treatment of general plant and A&G expenses. Typically, general plant is considered a separate functional
category. Some utilities, when their internal accounting systems can support such an assignment process,
will record general plant investment by loading the costs into the other functional categories, much like
an overhead assignment or a form of activity-based accounting.
On the expense side, A&G costs can be treated in much the same way. Generally, they are treated as a
separate expense category that can be spread to functions based upon all other O&M expenses. However,
they can also be spread to functions on the basis of total net plant, labor ratios or, in some cases, directly
assigned as part of the activity-based accounting approach.
4.3.2 Functionalization Method
The specific functions used for the District’s COSA are defined below. The functions generally follow
standard cost of service approaches.
Production/Power Supply. The power supply function category includes all power-related services
that are obtained by the utility through generation/production and direct purchase. The purchase
activity represents a form of supply acquisition activity.
Transmission. The transmission services that the District must acquire to deliver the purchased power
supply to the service area are included in purchased power costs. The costs associated with the
distribution system’s transmission service include only those costs for operating and maintaining the
transmission lines, poles, towers, substations, etc., used to deliver power to the distribution network.
Distribution. Distribution services include all services required to move the electricity from the point
of interconnection between the transmission system and the distribution system to the end user of
the power. These include substations, primary and secondary poles and conductors, line
transformers, services and meters, as well as customer costs and any direct assignment items.
Customer. Customer-related services include all services related to the presence of customers on the
system, not to customer usage. These services include meter reading, billing, collections, advertising,
etc.
4.4 CLASSIFICATION OF COSTS
The second step in performing a cost of service study is to classify the functionalized expenses to
traditional cost causation categories. These cost causation categories can be directly related to specific
consumption behavior or system configuration measurements such as coincident peak (CP) or non-
coincident peak (NCP) demand, energy or number of customers. Each classification category will have a
specific allocator that, when applied, will distribute those costs among the appropriate customer classes
during the allocation phase of the analysis.
Functionalized power purchases, generation and transmission system costs are classified as demand-
related and/or energy-related and in some instances directly assigned, while distribution costs are
classified as demand- or customer-related, or directly assigned to specific customer classes of service.
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4.4.1 Standard Classification
The three most general classification categories are demand-related, energy/commodity-related and
customer-related. Within these three categories there are multiple ways of defining each option as well
as varying ways to split costs between two or more classifiers. For example, demand- and energy-related
costs can be separated by seasonal distinctions as well as to reflect peak/off peak consumption periods.
Customer-related costs could be separated by demand and customer categories, while customer
categories can distinguish between actual customer and weighted customer characteristics. Other
classifiers sometimes used in the process include revenue-related and direct assignment. In addition,
there are many instances where costs are not specifically classified to a particular category but rather in
the same manner as an individual cost account or subtotal of specific cost accounts.
Generally, power production and purchased power costs are classified by a combination of demand and
energy. Transmission costs are generally classified as peak demand, while distribution costs are generally
split between demand and customer.
There are two methodologies that can be used to classify distribution costs: 100% demand and minimum
system. The 100% demand methodology assumes that the distribution system is built to meet the non-
coincident peak. Therefore, distribution costs are classified as 100% demand-related. Specific distribution
costs are sometimes split between demand and customer according to a minimum system approach. This
approach reflects the philosophy that the system is in place in part because there are customers to serve
throughout the service territory expanse, and that a minimally sized distribution system is needed to serve
these customers even if they only use 1 kWh of energy per year. The concept follows that any costs
associated with a system larger than this minimal size are due to the fact that customers “demand” a
delivery quantity greater than the minimum unit of electricity and that therefore, those costs should be
treated as demand-related. Because the residential class tends to have a higher share of the number of
customers as compared to the share of non-coincident peak, the minimum system methodology tends to
allocate more costs to the residential customer class and customer charges tend to be higher than with
the 100% demand methodology.
The process of cost classification is the area within the COSA that can create considerable cost variability
between customer classes due to differences in system configurations, demand measurements and
assignment philosophy. The complexity of the entire COSA process is further compounded since, in some
cases, the classification category is clear, but the specific allocator is not. For example, a particular cost
item may clearly be peak demand-related but that demand can be measured as either a single coincident
peak for the year, a 2 CP approach to reflect seasonal considerations, the sum of 12 monthly coincident
peaks or through some other approach such as “Average & Excess.”
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4.4.2 Classification Method
The following are the specific classifiers used in the District’s COSA within each of the four functions:
Power Supply
Classifying power supply costs to demand and energy (commodity) components requires the
evaluation of a number of complex, interrelated factors. Consideration must be given to what or who
caused the power supply purchase to be made, and to the uses to which it will be put (i.e., meeting
demand and energy requirement). Within this study, power supply costs are classified to demand
and energy based on the District’s power cost forecast for the test period. The specific classifiers used
for the power supply function include:
Energy
Demand
Energy-related costs are those that vary with the total amount of electricity consumed by a customer.
Electricity usage measured in kWh is used in this portion of the analysis as well. Energy costs are the
costs of consumption over a specified period of time, such as a month or year.
Demand-related costs are those that vary with the maximum demand or the maximum rates of power
supply to customer classes. Customer and system demand for this analysis were measured in kW.
Demand costs are generally related to the size of facilities needed to meet a customer’s maximum
demand at any point in time.
Wholesale Transmission Purchases
The District purchases with transmission services from third-party providers for both its share of
UAMPs and various utility-owned resources. These transmission purchases represent the cost to
transfer power from the high-voltage transmission system to the District’s distribution system.
The transmission bill components are separated into energy and demand costs before they are
allocated to customer classes. The energy cost component is allocated to customer classes based
non-coincident peak demand. The demand-related component is allocated based on each
customer class’s share of the District’s system peak, or coincident peak (CP). Coincident peak and,
conversely, non-coincident peak are discussed more below.
Coincident peak demand (CP) refers to the demand placed upon the system by each customer
at the time of the system maximum peak and is generally related to meeting power supply or
transmission peak requirements.
Non-coincident peak demand (NCP) refers to the sum of the individual customer peak
demands regardless of the time of occurrence. The sizing and corresponding expenses
associated with distribution lines, which are sized to meet the specific individual customer
demands for a limited geographic area within the utility’s service territory, are examples of
non-coincident demand costs.
For this analysis, consumption statistics are reported as either demand (kW) or energy (kWh).
Reported energy consumption reflects monthly-metered customer consumption by class. For
classes that are not billed or metered on measured demand, demand information was derived
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based on an association between energy consumption, days within the particular month and class
load factor assumptions that convert each class’s consumption profile into NCP demand
estimates. From those NCP determinations, customer class CP demand values were derived such
that when the peak month CP values of all the various classes are summed, they match the
District’s maximum system peak metered at its interconnection with the regional transmission
system. The CP and related NCP values developed within the COSA are later used to allocate
demand-related costs to the customer classes examined within the analysis.
Transmission (Utility-Owned)
The transmission function includes the utility’s own transmission assets associated with providing
power to the District’s distribution system. Transmission services that the District purchases in order
to facilitate the delivery of wholesale power purchases to the utility’s service area are included in
power supply costs. The costs associated with the local utility’s transmission service include only
those costs for operating and maintaining the transmission lines, poles, towers, substations, etc. used
to deliver power to the distribution network. The cost of providing transmission service to a customer
is considered to be directly proportional to the demand that customer imposes on the system. The
District does not own nor maintain transmission facilities, therefore, this component is not part of the
COSA.
Distribution
Distribution services include all services required to get energy supply from the point of
interconnection between the transmission system and the utility’s service area to the end user of the
power. Classifying distribution costs requires a special analysis of the nature of the costs. Most
distribution costs are split between demand and customer components. The demand component is
the cost of facilities built to serve a particular load, such as distribution substations. The customer
component is the cost of facilities that varies with the number of customers, such as meters. The
following are the specific classifiers used for the distribution function:
Non-coincident peak demand (NCP) on Primary System
NCP on Secondary System
Actual Customer
Customers Weighted for Acct/Meter Reading
Direct Assignment
The minimum system analysis is used to determine the lowest level of plant investment required to
serve a utility’s customers compared to the actual facilities in place to meet varying customer
demands. With a relatively uniform customer base and a low percentage of industrial customers, a
greater portion of costs are classified as customer-related relative to demand under a minimum
system approach to allocating costs. Using a “100 percent demand” classification approach assumes
that distribution investment is based entirely on meeting the non-coincident peak demand.
Customer
Customer-related services include all services related to the presence of customers on the system,
not to customer usage. These services include meter reading, billing, collections, advertising, etc.
Customer-related costs vary with the number and type of customers. They do not vary with system
supply levels. These costs are sometimes referred to as “readiness to serve” or “availability” charges.
Customer costs are incurred by the utility to have electricity supply readily available for a customer
whether it is utilized or not.
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There are two types of customer-related cost classification categories—actual and weighted. Actual
customer costs vary proportionally with the addition or deletion of a customer, regardless of the size
or usage characteristics of the customer. An example of an actual customer-related cost is postage
on customer bills. The cost of postage does not vary regardless of the type or size of customer or
usage levels. In contrast, a weighted customer cost reflects a disproportionate cost attributable to
the addition or deletion of a customer. An example of weighted customer costs is meter-reading
expenses. In some cases, it takes less time and effort to read a residential energy meter than it does
to serve a large commercial customer that also has a demand meter. This type of difference is
accounted for in the weighted customer allocation factors.
The specific classification of costs by account can be found in Schedule 3.1 of the COSA model.
Direct Assignment
Some costs can be directly assigned to certain customer classes without being classified as demand-,
energy-, or customer-related. These are generally costs associated with specific services, such as
dedicated capital facilities, or with specific customer classes, such as lighting customers.
4.5 ALLOCATION OF COSTS
The third step in performing a cost of service study is the allocation of the utility’s total functionalized and
classified revenue requirement to the customer classes of service. This is performed through the
application of an appropriate allocation methodology.
4.5.1 Allocation
The following are the specific allocation methods used in the District’s COSA. The specific method of cost
allocation by customer can be found in Schedule 3.1 of the COSA model and in this technical appendix.
Demand Allocation Factors. For purposes of this study, five types of demand allocation factors were
developed.
Non-coincident peak demand allocation factor (NCP).First, a non-coincident peak demand
allocation factor was developed for each customer class. Expenses classified and allocated by the
non-coincident peak demand allocation factor included those predicated on maximum demands
such as distribution substations, and a portion of poles and lines, mains, meters and services. The
NCP demand method allocates costs to each class of service based upon their highest individual
non-coincident peak demand regardless of the time of occurrence. The NCP allocation factor is
used to allocate distribution.
1 Coincident peak (1 CP).For each class of service, a contribution to a single annual system
coincident peak was derived from the non-coincident peak by use of a coincidence factor. This
coincident peak demand allocation method is referred to as the single coincident peak (1 CP)
method. The 1 CP method allocates demand costs on the basis of a single demand value at the
time of the system peak demand by each class. Expenses allocated on the 1 CP allocation factor
include those related to the District’s transmission system. The 1 CP allocation method is not
used in this study.
Sum of the two months coincident peaks (2 CP).For each class of service, a contribution to a
seasonal system coincident peak was also derived from the non-coincident peak by use of a
coincidence factor. The coincident peak demand allocation method used was the sum of the
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summer and winter coincident peaks (2 CP) method. The 2 CP method allocates demand costs on
the basis of the sum of the contributions to seasonal system peak demands by each class. The 2
CP method was not used in this study.
Sum of monthly coincident peak (12 CP). As with the 1 CP calculation,a contribution to monthly
system coincident peaks was derived from the non-coincident peak by use of a coincidence factor.
This coincident peak demand allocation method is referred to as the sum of the monthly
coincident peak (12 CP) method. The 12 CP method allocates demand costs on the basis of
demand value at the time of the system peak demand in each month by each class. As discussed
previously, the 12 CP method is used for power supply costs and transmission costs.
Average and excess method (A&E). The average and excess method represents an alternative
approach to CP-related cost allocation. The A&E method compares each customer class’s average
demand against its maximum NCP demand in order to reflect its potential peak demand volatility,
and therefore its inherent ability to increase system peak requirement. The A&E method was not
used in this study.
Energy Allocation Factors. Energy costs vary directly with consumption. Accordingly, energy
allocation factors were based upon electricity sales for each class. Energy allocation factors were used
to allocate power supply costs, green-energy related costs and revenues and surplus sales revenue.
Customer Allocation Factors. Two basic types of customer costs were identified—actual and
weighted. The allocation factor for actual customers was derived from the actual number of
customers served in each class of service. Two weighted customer allocation factors were also
developed. The first weighted customer allocation factor considered the relative differences among
the various customer classes of meter costs. The second weighted customer allocation factor
considered the cost of customer accounting and meter reading by each rate class. Customer
allocation factors were used to allocate some distribution costs such as meters and meter
installations, and costs associated with customer service, accounts and sales.
Rate Base Allocation. The value of the District’s assets as of December 2020 is functionalized,
classified and then allocated to customer classes. The resulting functionalized, classified and allocated
rate base is then used to develop rate base allocation factors. These allocation factors (i.e., general
plant, net plant, distribution rate base, etc.) are then used to allocate revenue requirement expenses.
For example, maintenance of station equipment can be allocated using station equipment rate base,
or property taxes might be allocated using net plant.
Other Cost Allocation. Other costs are allocated based on specific rate base items, O&M function
totals, revenues, labor ratios and other allocation factors. These other allocation factors were used
to allocate administrative and general expense items, as well as some other revenues such as dividend
income or non-operating rental income.
Administrative and General (A&G). All costs that are related to general overhead are classified to this
area. Costs are allocated to customers based on their percentage of all other O&M expenses without
power supply.
Miscellaneous/Other Revenues. Miscellaneous/other revenues are generally allocated to customers
based on allocation of all other O&M expenses.
4.6 REVIEW OF CUSTOMER CLASSES OF SERVICE
Customer classes of service refer to the arrangement of customers into groups that reflect common usage
characteristics or facility requirement. The classes of service used within this study were as follows:
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Permanent Residents
Non-Permanent Residents
Small Commercial
Medium Commercial
Large Commercial
Public Authority
Pumping/Water Department
Temporary Power
Security Lights
4.7 MAJOR ASSUMPTIONS OF THE COST OF SERVICE STUDY
Major assumptions used in conducting the cost of service study for the District are as follows:
Forecast calendar year 2022 was selected as the period for the allocation of costs within the cost of
service study.
The revenue requirement as outlined in Section 2 was used for the cost of service study.
Power purchased is assigned to energy and demand depending on the nature of the product.
Distribution plant was classified based both on a “minimum system” approach and a “100% demand”
approach.
Projected loads were based on data provided by the District.
Given these key assumptions, the cost of service analysis could be completed. Schedules 3.4 and 4.3 in
the COSA model show the functionalized and classified revenue requirement and rate base, respectively,
allocated to each class of service.
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4.8 COST OF SERVICE RESULTS
Given the above assumptions regarding the cost of service analysis, the various costs were classified and
allocated to the customer classes of service. Table 4-1 shows the results of this analysis by function for
the minimum system approach for CY 2022.
TABLE 4-1: SUMMARY OF FUNCTIONALIZED COST OF SERVICE (CY 2022)
MINIMUM SYSTEM APPROACH
Production
Related
Trans-
mission
Related
Distribution
Related
Customer
Related
Direct
Assign-
ment
Net Revenue
Requirement
Permanent
Residents
3,971,963 0 1,678,503 3,264,88
3
0 8,915,349
Non-Permanent
Residents 3,751,529 0 2,362,719 5,105,38
2
0 11,219,630
Small Commercial 1,802,475 0 1,364,150 918,937 0 4,085,562
Medium
Commercial 989,850 0 850,939 50,887 0 1,891,676
Large Commercial 587,845 0 1,157,126 15,155 0 1,760,126
Public Authority 1,962,094 0 1,213,125 270,678 0 3,445,897
Pumping/Water
Dept 617,252 0 851,666 55,383 0 1,524,301
Temp Power 14,937 0 19,614 19,946 0 54,496
Sec Lights 11,024 0 9,267 4,286 16,348 40,924
TOTAL 13,708,96
8
0 9,507,109 9,705,53
7
16,348 32,937,962
Table 4-2 provides the functionalized COSA results using a 100% demand methodology.
TABLE 4-2: SUMMARY OF FUNCTIONALIZED COST OF SERVICE (CY 2022)
100% DEMAND APPROACH
Production
Related
Transmission
Related
Distribution
Related
Customer
Related
Direct
Assignment
Net Revenue
Requirement
Permanent
Residents 3,971,963 0 2,878,952 1,685,77
8
0 8,536,693
Non-Permanent
Residents
3,751,529 0 4,175,252 2,636,09
5
0 10,562,876
Small Commercial 1,802,475 0 1,894,418 512,573 0 4,209,466
Medium
Commercial 989,850 0 1,060,236 36,435 0 2,086,521
Large Commercial 587,845 0 1,431,827 12,605 0 2,032,278
Public Authority 1,962,094 0 1,540,676 193,805 0 3,696,575
Pumping/Water
Dept 617,252 0 1,061,162 39,654 0 1,718,068
Temp Power 14,937 0 29,140 10,299 0 54,375
Sec Lights 11,024 0 13,543 197 16,348 41,111
TOTAL 13,708,96
8
0 14,085,206 5,127,44
0
16,348 32,937,962
The overall COSA results are summarized in Table 4-3 for minimum system and in Table 4-4 for 100%
demand.
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TABLE 4-3: SUMMARY OF COST OF SERVICE ANALYSIS – MINIMUM SYSTEM (CY 2022)
Present Rate
Revenues
Net Revenue
Requirement
Surplus/(Deficiency)
in Present Rates
Rate Increase
(Decrease)
Permanent Residents $7,509,871 $8,348,729 ($838,859)11.2%
Non-Permanent Residents 8,608,730 10,469,475 (1,860,746)21.6%
Small Commercial 4,121,566 3,812,307 309,259 -7.5%
Medium Commercial 1,935,414 1,763,137 172,277 -8.9%
Large Commercial 1,327,805 1,622,814 (295,009)22.2%
Public Authority 3,504,023 3,226,124 277,900 -7.9%
Pumping/Water Dept 1,294,848 1,412,278 (117,430)9.1%
Temporary Power 36,443 50,569 (14,126)38.8%
Security Lights 30,456 38,662 (8,206)26.9%
TOTAL $28,369,157 $30,744,096 ($2,374,939)8.5%
TABLE 4-4: SUMMARY OF COST OF SERVICE ANALYSIS – 100% DEMAND (CY 2022)
Present Rate
Revenues
Net Revenue
Requirement
Surplus/(Deficiency)
in Present Rates
Rate Increase
(Decrease)
Permanent Residents $7,509,871 $8,006,336 ($496,466)6.6%
Non-Permanent Residents 8,608,730 9,875,617 (1,266,887)14.7%
Small Commercial 4,121,566 3,924,345 197,221 -4.8%
Medium Commercial 1,935,414 1,939,322 (3,908)0.2%
Large Commercial 1,327,805 1,868,902 (541,097)40.8%
Public Authority 3,504,023 3,452,795 51,228 -1.5%
Pumping/Water Dept 1,294,848 1,587,488 (292,640)22.6%
Temporary Power 36,443 50,459 (14,016)38.5%
Security Lights 30,456 38,831 (8,375)27.5%
TOTAL $28,369,157 $30,744,096 ($2,374,939)8.5%
The results show that under present retail rates, the District is not collecting sufficient revenues to meet
projected revenue requirements.
attachment 3
TRUCKEE-DONNER PUBLIC UTILITY DISTRICT Electric Cost of Service Study
prepared by EES CONSULTING 25
5 Present Rates and COSA Unit Costs
This section of the report provides six tables comparing the District’s current rates to the unit costs
developed in the cost of service study under each methodology. A detailed lighting study may be needed
to develop rates for security lights.
TABLE 5-1: COMPARISON OF PRESENT RATES, COSA-DERIVED RATES
PERMANENT RESIDENTS
Present
Rates
COSA Unit Costs
Minimum
System
COSA Unit Costs
100% Demand
Basic Charge ($/month)$18.55 $49.95 $17.94
Energy Charge ($/kWh)$0.132 $0.110 $0.132
Rate Change Over Present Rates 11.2%6.6%
TABLE 5-2: COMPARISON OF PRESENT RATES, COSA-DERIVED RATES
NON-PERMANENT RESIDENTS
Present
Rates
COSA Unit Costs
Minimum
System
COSA Unit Costs
100% Demand
Basic Charge ($/month)$18.55 $49.95 $27.57
Energy Charge ($/kWh)$0.151 $0.126 $0.174
Rate Change Over Present Rates 21.6%14.7%
TABLE 5-3: COMPARISON OF PRESENT RATES, COSA-DERIVED RATES
SMALL COMMERCIAL
Present
Rates
COSA Unit Costs
Minimum
System
COSA Unit Costs
100% Demand
Basic Charge ($/month)$27.32 $54.76 $32.58
Energy Charge ($/kWh)$0.170 $0.136 $0.1693
Rate Change Over Present Rates -8.9%-4.8%
TABLE 5-4: COMPARISON OF PRESENT RATES, COSA-DERIVED RATES
MEDIUM COMMERCIAL
Present
Rates
COSA Unit Costs
Minimum
System
COSA Unit Costs
100% Demand
Basic Charge ($/month)$272.84 $86.03 $65.11
Energy Charge ($/kWh)$0.110 $0.077 $0.081
Demand Charge ($/kW-mo.)$13.67 $22.89 $31.13
Rate Change Over Present Rates -18.0%0.2%
attachment 3
TRUCKEE-DONNER PUBLIC UTILITY DISTRICT Electric Cost of Service Study
prepared by EES CONSULTING 26
TABLE 5-5: COMPARISON OF PRESENT RATES, COSA-DERIVED RATES
LARGE COMMERCIAL
Present
Rates
COSA Unit Costs
Minimum
System
COSA Unit Costs
100% Demand
Basic Charge ($/month)$1,196.79 $146.16 $127.67
Energy Charge ($/kWh)$0.104 $0.077 $0.081
Demand Charge ($/kW-mo.)$13.06 $28.48 $38.51
Rate Change Over Present Rates 17.2%40.8%
TABLE 5-6: COMPARISON OF PRESENT RATES, COSA-DERIVED RATES
TEMPORARY POWER
Present
Rates
COSA Unit Costs
Minimum
System
COSA Unit Costs
100% Demand
Basic Charge ($/month)$20.22 $49.95 $27.57
Energy Charge ($/kWh)$0.164 $0.181 $0.249
Rate Change Over Present Rates 38.8%38.5%
attachment 3