Electric Cost of Service Study — Riverside City Council, September 19, 2023 (part 1 of 3)

JUNE 9, 2023
www.newgenstrategies.net

ELECTRIC COST OF

SERVICE AND RATE

DESIGN STUDY
REPORT
Prepared for:

City of Riverside, California
© 2023 NEWGEN STRATEGIES AND SOLUTIONS, LLC

Economics | Strategy | Stakeholders | Sustainability
Table of Contents
Executive Summary
INTRODUCTION ............................................................................................... 1-1 Introduction ................................................................................................................... 1-1 Schedule ........................................................................................................................ 1-2 Rate Design Objectives/Rate Making Principles ................................................. 1-2 Riverside Five-Year Rate Plan ........................................................................................ 1-3 RPU Financial Projections.................................................................................... 1-4 RPU Study Test Year ............................................................................................ 1-5 Test Year/Audited Year ....................................................................................... 1-6 RPU Specific Rate Considerations .................................................................................. 1-6 California Requirements/Proposition 26 ............................................................ 1-6 Net Energy Metering Regulations ....................................................................... 1-6 Report Outline ............................................................................................................... 1-7 SYSTEM CHARACTERISTICS .............................................................................. 2-1 Introduction ................................................................................................................... 2-1 Demand and Energy Requirements ............................................................................... 2-1 Demand ............................................................................................................... 2-1 Energy Sales ........................................................................................................ 2-2 Average Number of Meters by Customer Class .................................................. 2-3 Customer Statistics ........................................................................................................ 2-4 Fixed/Variable Costs and Cost Recovery ....................................................................... 2-4 REVENUE REQUIREMENT ................................................................................. 3-1 Summary ........................................................................................................................ 3-1 RPU Reserve Policy ........................................................................................................ 3-2 ALLOCATION OF SYSTEM COSTS ....................................................................... 4-1 Functionalization and Classification .............................................................................. 4-1 Functionalization of Test Year Expenditures ................................................................. 4-1 Classification of Various Costs ............................................................................ 4-1 Development of Allocation Factors ............................................................................... 4-2 General 4-2
Demand Allocation Factors ................................................................................. 4-3 Energy Allocation Factors .................................................................................... 4-5 Customer Allocation Factors ............................................................................... 4-6 Adjustments to Allocation Factors ...................................................................... 4-6 ALLOCATED COST OF SERVICE .......................................................................... 5-1 General .......................................................................................................................... 5-1 Allocation and Assignment of Cost of Service ............................................................... 5-1 Cost of Service Process .................................................................................................. 5-2

Table of Contents

ii
Demand-Based Costs .......................................................................................... 5-2 Customer-Based Costs ........................................................................................ 5-2 Energy-Based Costs ............................................................................................. 5-2 Retail Rate Review ......................................................................................................... 5-2 Domestic ........................................................................................................................ 5-3 Domestic Cost Curve ........................................................................................... 5-5 Non-Domestic/Commercial Rate Review ...................................................................... 5-6 Commercial – Flat ............................................................................................... 5-6 Commercial – Flat Cost Curve ............................................................................. 5-7 Commercial – Demand ........................................................................................ 5-8 Commercial – Demand Cost Curve ..................................................................... 5-9 Industrial TOU ................................................................................................... 5-10 Industrial TOU – Cost Curve .............................................................................. 5-11 PROPOSED RATES ............................................................................................ 6-1 General .......................................................................................................................... 6-1 Current Rate Classifications ........................................................................................... 6-2 Existing and Proposed Fixed Cost Recovery .................................................................. 6-2 Reliability Charge ................................................................................................ 6-3 Network Access Charge ....................................................................................... 6-3 Proposed Rate Design .................................................................................................... 6-3 Domestic Rates and Bill Comparison Analysis .................................................... 6-3 Distribution of Bill Impacts – Domestic Customers ............................................ 6-4 Fixed vs. Variable Cost Recovery ......................................................................... 6-6 Non-Domestic/Commercial Rate and Bill Comparison Analysis ................................... 6-7 Commercial – Flat ............................................................................................... 6-7 Distribution of Bill Impacts – Commercial – Flat Customers .............................. 6-8 Fixed vs. Variable Cost Recovery ....................................................................... 6-10 Commercial – Demand ...................................................................................... 6-11 Fixed vs. Variable Cost Recovery ....................................................................... 6-12 Industrial – TOU ................................................................................................ 6-12 Distribution of Bill Impacts – Industrial TOU Customers .................................. 6-14 Fixed vs. Variable Cost Recovery ....................................................................... 6-16 Revenue Impact Analysis ............................................................................................. 6-16 Other Rate Changes ..................................................................................................... 6-17 Street Lighting ................................................................................................... 6-17 Electric Vehicle Charging Rates ......................................................................... 6-19 Domestic TOU Rates ......................................................................................... 6-21 Other Existing Rates Schedules ......................................................................... 6-23 RPU Rate Programs ...................................................................................................... 6-25 All-Electric Service ............................................................................................. 6-25 Multi-Family Service .......................................................................................... 6-25 Conclusions .................................................................................................................. 6-26 Recommendations ....................................................................................................... 6-26

List of Appendices
A Proposed Rates – Other Customer Classes
B Technical Appendix

Table of Contents

iii

List of Tables

Table 1-1 RPU Policy Goals and Five-Year Rate Plan ............................................................... 1-3 Table 1-2 Financial Metrics for Study Period ($000) ................................................................ 1-4 Table 1-3 Revenue Requirement and Revenue for Study Period ($000) ................................. 1-4 Table 1-4 Existing Test Year Rate Revenues vs. Test Year Revenue Requirements ($000) ..... 1-5 Table 2-1 System Usage Characteristics .................................................................................. 2-1 Table 2-2 Historic and Projected Energy Sales (000 kWh or MWh)......................................... 2-3 Table 2-3 Historic and Projected Meters by Class ................................................................... 2-4 Table 2-4 Actual Customer Usage Statistics for FY 2022 ......................................................... 2-4 Table 3-1 Revenue Requirement by Function for Test Year ($000) ......................................... 3-1 Table 3-2 RPU Reserve Policy Summary .................................................................................. 3-2 Table 3-3 RPU Reserve Policy – Minimum and Maximum by Risk Category ($000) ................ 3-3 Table 4-1 Cost of Service by Function ...................................................................................... 4-1 Table 4-2 4 CP Cost Allocation ................................................................................................. 4-3 Table 4-3 4 NCP Cost Allocation ............................................................................................... 4-4 Table 4-4 Energy Cost Allocation ............................................................................................. 4-5 Table 5-1 Existing Test Year Rate Revenues vs. Test Year Revenue Requirements ($000) ..... 5-1 Table 5-2 Domestic Rates (Existing and Cost of Service) ......................................................... 5-3 Table 5-3 Commercial – Flat Rates (Existing and Cost of Service) ........................................... 5-7 Table 5-4 Commercial – Demand Rates (Existing and Cost of Service) .................................. 5-9 Table 5-5 Industrial TOU Rates (Existing and Cost of Service) .............................................. 5-11 Table 6-1 Current Rate Schedules and Customer Class ........................................................... 6-2 Table 6-2 Domestic Rates (Existing and Proposed) ................................................................. 6-4 Table 6-3 Domestic Bill Impacts Year 1 and Year 5; Average Annual Percent ......................... 6-6 Table 6-4 Commercial – Flat (Existing and Proposed) ............................................................. 6-8 Table 6-5 Commercial – Flat Bill Impacts Year 1 and Year 5, Average Annual Percent ......... 6-10 Table 6-6 Commercial – Demand (Existing and Proposed Rates) .......................................... 6-11 Table 6-7 Industrial TOU (Existing and Proposed Rates) ....................................................... 6-13 Table 6-8 Industrial TOU Class Bill Impacts Year 1 and Year 5; Average Annual Percent ..... 6-16 Table 6-9 Projected Revenue by Class ($000) ........................................................................ 6-17 Table 6-10 LED Lamp Photocell Settings ................................................................................ 6-18 Table 6-11 Existing Schedule LS-1 (Per Lamp, Per Month) (1) ................................................ 6-18 Table 6-12 LED Additions to Schedule LS-1 (Energy and Maintenance $/month) (1) ............. 6-19 Table 6-13 Per Charger Energy, Demand, and Load Factor ................................................... 6-20 Table 6-14 Separately Metered EV Charging Rate ($/kWh) .................................................. 6-20 Table 6-15 Domestic Time of Use Schedule DTOU ............................................................... 6-22 Table 6-16 Domestic Electric Vehicle Separately Metered – Schedule EV ............................ 6-23

List of Figures

Figure 2-1. Total Energy Consumption by Customer Class for FY 2022 (000 kWh or MWh) ... 2-2 Figure 2-2. Structure of Test Year (COS) Costs versus FY 2022 Revenues ............................... 2-5 Figure 4-1. 4 CP Demand Cost Allocation ................................................................................ 4-4 Figure 4-2. Allocation of Energy Costs based on MWh Sales .................................................. 4-5 Figure 5-1. Cost and Current Rate Curves for Domestic Rate .................................................. 5-5

Table of Contents

iv
Figure 5-2. Cost and Current Rate Curves for Commercial – Flat Rate .................................... 5-8 Figure 5-3. Cost and Current Rate Curves for Commercial – Demand Rate .......................... 5-10 Figure 5-4. Cost and Current Rate Curves for Industrial TOU Rate........................................ 5-12 Figure 6-1. Fixed and Variable Cost vs. Recovery .................................................................... 6-3 Figure 6-2. Distribution of RPU Domestic Customers’ Monthly Usage (FY 2022) ................... 6-5 Figure 6-3. Average Domestic Bill Increase – First Year and Average for 5 Years ................... 6-6 Figure 6-4. Fixed vs. Variable Cost Recovery by Year – Domestic ........................................... 6-7 Figure 6-5. Distribution of RPU Commercial – Flat Customers’ Monthly Usage (FY 2022) ..... 6-9 Figure 6-6. Average Commercial – Flat Bill Increase – First Year and Average for 5 Years ... 6-10 Figure 6-7. Fixed vs. Variable Cost Recovery by Year – Commercial – Flat ........................... 6-11 Figure 6-8. Fixed vs. Variable Cost Recovery by Year – Commercial – Demand .................... 6-12 Figure 6-9. Distribution of RPU Industrial TOU Customers’ Monthly Energy Usage (MWh = 1,000 kWh, FY 2022) ................................................................................................... 6-15 Figure 6-10. Average Commercial Demand Bill Increase – First Year and Average for 5 Years (MWh = 1,000 kWh) ................................................................................................... 6-15 Figure 6-11. Fixed vs Variable Cost Recovery by Year – Industrial TOU ................................ 6-16

Economics | Strategy | Stakeholders | Sustainability

EXECUTIVE SUMMARY
Introduction
Riverside Public Utilities (RPU) is a municipal public utility owned by the City of Riverside, California (City) that provides power to the citizens of the City. RPU has been providing efficient, reliable service to the City since 1895, and is committed t o providing the highest quality electric service at the lowest possible rates to benefit the community.

Current estimates of projected increases in electricity usage at existing rates are insufficient to cover these projected costs.

Cost of Service Study
In this Electric Cost of Service and Rate Design Study (Study), the costs to electric customers of operating, maintaining and improving the RPU Electric Utility is explored within the framework required by California state law, and City and Utility policies, which dictate that costs for electric services to municipal customers should be cost-based. RPU provides 10-year financial projections for needed revenue for the system. In developing its strategy, RPU has consider ed various scenarios and proposes a proactive approach to infrastructure replacement. This Report identifies the costs to customers and defines a business model that can be sustained. The goals of this Study are to determine the annual Revenue R equirements to operate the electric utility, update the cost of providing electric service to various customer classes , and develop electric rates that are adequate to fund RPU’s electric operations while being compliant with the requirements of Proposition 26.

This Study relies on the concept of a “Test Year.” A Test Year is a standard mechanism utilized in electric cost of service (COS) studies that determines the basis for the proposed rate changes. The Test Year for this Study was determined to be from RPU’s fiscal year (FY) 2024 through FY 2028 (RPU’s FY is from July 1 through June 30). This five -year Test Year was selected because of its alignment with the goals and objectives o f the Utility’s strategic plan . A Test Year results in average values that represent the “mid-point” of that five -year period. The Rate Plan provides a series of rate cha nges over the five- year period; it is critical that the entirety of the rate adjustments be reviewed collectively, as the intent is to achieve spec ific financial and policy objective s throughout the Five-Year Rate Plan period (Rate Plan period).

EXECUTIVE SUMMARY

2 Rate Design Objectives/Rate Making Principles
A rate study should culminate in a set of proposed rate designs , in which the cost recovery mechanisms (rates and charges) for each customer class are established. Rates and charges are designed such that the total revenue needed for the system will be recovered in an equitable manner that is consistent with the results of analyses conducted in the Study. In addi tion, rate design considers and reflects RPU’s overall revenue stability for the utility (and customer class es), its historical rate structures in place, policy considerations for conservation and energy efficiency, competitiveness with neighboring utility systems, as well as legal requirements and other energy -related policies established by the City Council. The following (Table ES-1) provides a list of RPU’s electric rate making principles, with the specific application identified for this Study and the Five-Year Rate Plan.

Table ES-1
RPU Policy Goals and Five-Year Rate Plan
RPU Rate Making Principles
Five-Year Electric Rate Plan –
Implementation
Achieve full recovery of costs Rates designed to recover projected Revenue Requirements over Study period
Equitably allocate costs across and within customer classes Increase/implement fixed cost recovery mechanisms to align rate structures with costs
Encourage efficient use of water and electricity Design rates to discourage overuse and reward efficiency
Provide rate stability Maintain consistency between rates within each year of the Study period
Offer flexibility and options Reduce rate-related bill impacts for customers transitioning between classes
Maintain rate competitiveness in region Consider/mitigate rate–related impacts to all customers including low use customers
Be simple and easy to understand Maintain simplicity of rate structures and components of existing rate structures, as appropriate

Section 6 of this Report provides additional detail on RPU’s Rate making principles.

Summary of Revenue Needs
The required revenue for RPU for each of the years of the Five-Year Rate Plan developed by RPU in its Financial Pro Forma Model is provided in Table ES -2. Additionally, Table ES -2 includes a comparison of the total revenues generated by existing rates (current as of 20 23) for the system. The difference s between these two values represent the necessary rate adjustments for RPU to continue to provide safe and reliable power to the citizens and business of the City and results in a cumulative shortfall of approximately $305.9 million.

EXECUTIVE SUMMARY

3 Table ES-2
Revenue Requirement and Revenue for Study Period ($000) FY 2024 FY 2025 FY 2026 FY 2027 FY 2028 Total
Revenue Requirement $362,009 $388,817 $418,591 $441,832 $456,150 $2,067,400 Revenue from Customers (1) $343,699 $347,316 $351,864 $356,678 $361,988 $1,761,545 Difference (2) $(18,310) $(41,501) $(66,727) $(85,155) $(94,162) $(305,855) (1) Based on existing rates (FY 2023) and RPU projections for load growth over Five Year Rate Plan period. (2) Totals may not add due to rounding.

The Revenue Requirement represents the entire annual revenue anticipated to be needed by RPU and includes its projections for power production (and purchases), on -going operations and maintenance (O&M) expenses for all of its functions, as well as projections for debt service, capital (funded by rates ), transfer to the general fund , and reserves (per RPU’s reserve policy). The revenue needed is offset by “Other Revenues,” which includes transmission revenues, interest income, and other non-rate revenue. A categorization by functional areas of the Revenue Requirements for the Five -Year Test Year is provided in Table ES-3.

Table ES-3
Revenue Requirement by Function ($000)
Function FY 2024 FY 2025 FY 2026 FY 2027 FY 2028
Production O&M $177,117 $169,461 $175,379 $178,159 $188,078 Transmission O&M 64,651 66,913 69,137 71,613 47,543
Distribution O&M 21,482 22,294 23,202 23,940 24,681
Customer O&M 9,446 9,803 10,203 10,527 10,853
Administrative and
General O&M
41,873 43,455 45,226 46,665 48,108
Total O&M $314,569 $311,926 $323,146 $330,905 $319,264 Debt Service 63,000 66,087 69,441 78,260 75,784
Transfer to General
Fund
45,419 45,334 48,505 52,025 54,799
Capital Funded by
Rates
4,071 4,290 4,194 3,502 4,038
Allocation to (Use of)
Reserves
(19,019) 8,445 22,540 28,980 28,212
(minus) Other
Revenues
(46,030) (47,265) (49,235) (51,840) (25,947)
Net Revenue
Requirement
$362,009 $388,817 $418,591 $441,832 $456,150
Source: RPU Financial Pro Forma Model and COS Model. Note, numbers may not add due to rounding.

EXECUTIVE SUMMARY

4 As is typical with most utilities, the production function (generation or purchasing) of electricity is the largest functional element. The debt service estimated for the Test Year includes existing debt service (for outstanding bon ds) and new debt service . RPU’s Financial Pro Forma Model includes a Capital Improvement Plan of approximately $316 million over the Rate Plan period. Of the $316 million Capital Improvement Plan, $276 million in CIP is projected to be funded with bond proceeds during the Five-Year Rate Plan, the remainder is to be funded by a combination of rate revenue, reserves and contributions from developers. The Revenue Requirement off-set (reduction) from other revenues included in Table ES- 3 is mainly interest income and transmission revenue from the California Independent System Operator (CAISO) wholesale market.

Capital Improvement Program
RPU’s investment plan includes a Capital Improvement Plan (CIP) that extends for 10 years and relates to the rehabilitation and replacement of existing infrastructure , procurement of future power supply , and employing advanced technology to provide more efficient and better cus tomer service. The CIP will be funded through a combination of contributions (provided by developers/customers), rates, reserve funds, and debt financing (bond issuances). The sources of funding for the first five years of the CIP are shown in Figure ES-1. RPU intends to utilize reserves during the initial funding of its capital plan, which will be replenished with proceeds from bonds issued during the Five-Year Rate Plan.

Note: The figure excludes Riverside Transmission Reliability Project capital costs which are funded separately by Reliability Charge revenues.

Figure ES-1. Capital Funding Sources for Utility CIP ($000) Reserve Policy
RPU has developed a robust reserve policy, which is designed to promote fiscal sustainability, minimize borrowing costs, and provide a source of emergency funds for unforeseen events. The reserve policy defines the restricted reserves, designated reserves, and undesignated reserves, while also setting the overall minimum and maximum undesignated re serve levels. Detailed information on each specific risk category is provided in Section 3 of this Report. Table ES -4 shows the projected undesignated reserve minimum and maximum levels for each year of the Study period.

EXECUTIVE SUMMARY

5 Table ES-4
RPU Projected Undesignated Reserve Levels ($000)
FY Ending
RPU
Reserve Policy Target 2024 2025 2026 2027 2028
Total Minimum $174,771 $183,088 $200,271 $205,171 $204,714 Maximum $269,177 $282,619 $306,956 $315,673 $313,983
Line of
Credit
$35,000 $35,000 $34,000 $34,000 $34,000
RPU Pro Forma Financial Model

Financial Pro Forma Model vs. Cost of Service Model
RPU has developed its Financial Pro Forma Model to provide a high -level assessment of the revenue projections by customer class and the total expenses for the utility, including its CIP investments and how they will be funded. Revenue projections for the Financial Pro -Forma Model are based on total existing revenue by class and are summed for the system; the results are a “system -wide” rate increase to arrive at a revenue increase necessary for RPU to fund its future expenses and investments (the Financial Pro Forma Model does not consider changes to rate structures). The COS Model is a detailed analysis of RPU’s costs and assigns those costs to the customer classes based on standard industry accepted principles and methodology.

The COS Model is designed to recover the revenue requir ements from RPU’s customer classes over the Five-Year Rate Plan. The average revenue to be collected from RPU’s customers during this period aligns with the average revenue developed by the Financial Pro Forma Model.

Cost of Service Process
The COS process is an industry accepted framework that assigns costs to customer classes. This process determines the “cost to serve” each customer class within a utility. Electric utility costs are typically characterized as either fixed or variable; fixed costs are those that do not change with the production of electricity, whereas variable costs are directly related to the amount of electricity produced and/or purchased. These costs are typically further characterized as those that are demand -based, customer-based, and energy-based.

Demand-based Costs
Demand-based costs for electric utilities are fixed costs that are related to the existing and future investments made to produce, transmit, and deliver power from the generation resources to its customers. For R PU, these costs include the debt service associated with its generation, transmission , and distribution assets, as well as a portion of its contracts for purchased power. The labor and materials associated with the O&M and administration of these systems is also a demand-based cost, as the labor costs are typically fixed in the short-term (budget cycle). In the short-term, fixed costs do not change and

EXECUTIVE SUMMARY

6 represent the on-going costs to meet the needs of the utility. Fixed costs are allocated primarily to t he demand in the COS process because they are designed to support the system as a whole. This means that as a result of the COS process, these costs are assigned based on the electric demand (measured in kilowatts, or kW) that a specific customer or customer class places on the system. RPU, like most utilities, has a cost structure that is highly fixed, which is typical of highly capital-intensive entities.

Customer-based Costs
Customer-based costs for electric utilities are fixed costs as well, these are costs incurred in direct support of the customers served by a utility. For RPU, this includes the costs associated with the labor, equipment, and investments for customer accounting, billing, and customer assistance (call centers). Additionally, a portion of administrative and general (A&G) costs are allocated to the customer-related costs, as they are designed to support this function for RP U. During the COS process, these costs are allocated by the number of customers within a class.

Energy-based Costs
Energy-based costs for electric utilities are typically variable costs that change with the changes in electric load. The primary example of energy-rated costs for RPU are its fuel and purchased power costs. During the COS process, these are allocated to the customer classes by the amount of energy they are projected to utilize within a selected period of time (during the Test Year).

Existing Rate Structures and Fixed Cost Recovery
RPU’s existing rate structures vary by the customer class for which they are designed. All major customer classes include an energy component ($/kilowatt-hour or kWh) and a Reliability Charge ($/month), as well as applicable taxes and surcharges. Most customer classes include a customer component (in $/ per month), and some customer classes include a demand compone nt ($/kW) . Residential and small- commercial customers (referred to as Domestic and Commercial – Flat customers by RPU), do not have a demand charge on their bill; rather the fixed costs associated with demand-related costs are recovered in part by the Reliability Charge (for allocated portion of specific project costs), and the energy charge. The RPU Commercial – Demand and the Industrial Time -of-Use (TOU) customer classes include a demand component in their existing rate structures.

RPU’s Reliability Charge recovers fixed costs associated with the Riverside Transmission Reliability Project, which is a second point of interconnection to the regional grid, and the Riverside Energy Resource Center internal generation units , which provide reliability and are used to meet summer peaking needs . The costs associated with these investments are categorized as demand-related costs in the COS analysis for the purposes of this Study.

Consistent with its rate making principles, RPU has expressed an interest in increasing the portion of fixed cost recovery in its rates. This is proposed due to the existing “misalignment” in RPU’s rate structures compared to its costs. In an era of constant load growth, the recovery of fixed costs through variable rates (energy rates) was commonplace in the industry. However, RPU and many other utilities in California and elsewhere, have experienced reductions in customer energy consumption and demand due to increases in energy efficiency, conservation, and customer self-generation. As sales decrease, but costs remain the same (or increase), the level of fixed cost recovery has become critical. As proposed in its Five-Year Rate Plan, RPU intends to address the level of fixed cost recovery by increasing the fixed components (charges) of existing rate structures while adjusting the energy-only portion of its rates.

EXECUTIVE SUMMARY

7 The results of this Study indicate that the Test Year COS-based costs include a customer charge for the Domestic class that is approxim ately $ 16.69/month, a dem and rate of approximately $ 24.57/kW of demand, and an energy r ate of approximately $0.0 863/kWh, as indicated in Table ES -5. All customers, including Domestic, place a demand on the system through their use of electricity (electric load). The peak electric load (the highest electricity usage during one hour of the month) is referred to as the peak demand of that customer. Dema nd is measured in kWs; most commercial customers, including Commercial – Demand and Industrial TOU customers, have meters that measure the peak demand and are billed for that usage (billed demand). However, Domestic customers and small commercial customers (RPU’s Commercial – Flat customers) do not have demand meters. Therefore, demand-related costs are recovered in the energy portion of their bill (i.e. they are not billed on a demand basis), the customer charge ($/customer), the Reliability Charge and the Network Access Charge (NAC).

For the Domestic class, this means that the costs to serve each customer is equal to $16.69/month; however, RPU’s existing rate structure includes a charge of $12.06/month for this service. Therefore, the remaining customer-related costs are currently included in the energy rate. Additionally, it costs RPU approximately $24.57 per kW of demand to serve each Domestic customer; a portion of these costs are also recovered in the existing energy rates. RPU’s Reliability Charges and NAC recover fixed costs that are included in the $24.57/kW demand calculation. RPU’s COS based energy-related-costs are $0.0863/kWh (not adjusted for tiered costs); however, as a result of a lower customer charge and no demand charge, the existing energy rate is higher than RPU’s “pure” energy costs. RPU’s energy rates are tiered to encourage conservation and equitably allocate costs incurred for higher demand ; the more energy used by Domestic customer, the higher the “per unit” rate ($/kWh).

Table ES-5 also includes a column titled “COS -Energy”; this data is based on the COS analysis and recognizes that Domestic customers are not charged on a demand basis ($/kW). As indicated, Domestic customers do incur these costs; however, they are recovered from the energy rate ($/kWh). Therefore, this table provides an “ adjusted COS-based energy rate,” which includes appropriate demand costs and has been calculated to be approximately $0.1979/kWh (not adjusted for the tiered structure). Note that the customer costs for this COS -Energy column are still $ 16.69/month, compared to the existing rate of $12.06/month.

EXECUTIVE SUMMARY

8 Table ES-5
Domestic Rates
(Existing and Cost of Service)
Rate Component Existing COS COS – Energy (1)
Customer ($/month) $12.06 $16.69 $16.69
Demand ($/kW) -- $24.57 --
Network Access Charge ($/month) (2)
Tier 1 (< or = 12 kWh Daily Average) $2.49
Tier 2 (>12 - 25 kWh Daily Average) $5.97
Tier 3 (>25 kWh Daily Average) $13.16
Energy ($/kWh) (3)
Tier 1 (0–750 S; 0–350 W) $0.1102 $0.0863 $0.1979
Tier 2 (751–1,500 S; 351–750 W) $0.1753 $0.0863 $0.1979 Tier 3 (>1,500 S; >750 W) $0.1988 $0.0863 $0.1979
Reliability Charge ($/month) (4)
Small Residence (<100 Amp) $10.00 -- --
Medium Residence (101–200 Amp) $20.00 -- --
Large Residence (201–400 Amp) $40.00 -- --
Very Large Residence (>400 Amp) $60.00 -- --
(1) Assumes no Demand Charge and bundles demand-related costs within the Energy Charge (2) Network Access Charge is tiered by the Daily Average kWh Usage for the month. (3) The tiered energy rates are the same for summer/winter (S/W); however, the characteristics of the tier change with the season.
(4) The Reliability Charge varies by the size of the customer (measured by the electric panel in Amps), and the costs are included in the Demand COS Charge.

Figure ES-2 provides a summary of the fixed and variable cost recovery for the RPU system. Fixed cost recovery includes revenue from the customer charge, the Reliability Charge, Network Access Charge (NAC) (see text below), and demand charges. Variable cost recovery includes revenue from the energy charge.

Revenues from the public benefits charge, taxes, and other fees are not included in this analysis.

EXECUTIVE SUMMARY

9 Figure ES-2. Fixed and Variable Cost Recovery for RPU System The values for existing revenue and FY 2024–FY 2028 represent the cost recovery from the current and proposed RPU rates, as described herein . RPU is proposing to gradually transition its rate structures to increase its fixed cost recovery during the R ate Plan; however, it does not plan to transition to full fixed cost recovery due to negative financial impacts to customers.

Summary of Proposed Rates
Actual rate increases will vary by customer class and consumption levels ; but, on average, the projected rate increases will result in annualized compounded average system revenue increases to meet future Revenue Requirements.

Why is this Study needed? RPU faces an income shortfall of about $305.9 million if rates are not increased; reserve levels alone are not enough to avoid the need for increased revenues. Reducing reserve levels below minimum leve ls impacts financial metrics , which could result in a lower credit rating, thereby increasing its operating (borrowing) costs.

Tables ES-6 through ES-9 provide a summary of the proposed rates by Domestic, Commercial-Flat, and Industrial customer classes for the proposed rate plan. No changes to the Commercial-Demand rate are proposed. It should be noted that for all of the customer classes, there is no change proposed for the Reliability Charge.

EXECUTIVE SUMMARY

10 Table ES-6
Existing and Proposed Rates – Domestic Customers
Rate Component Existing
Proposed Effective January 1
2024 2025 2026 2027 2028
Customer Charge ($/month) $12.06 $12.90 $13.86 $14.93 $14.93 $15.09 Network Access Charge ($/month)
Tier 1 (or < = 12 kWh Daily Average) $2.49 $3.19 $3.89 $4.60 $5.24 $5.69 Tier 2 (>12 - 25 kWh Daily Average) $5.97 $7.44 $8.91 $10.38 $11.85 $12.65 Tier 3 (>25 kWh Daily Average) $13.16 $15.32 $17.48 $19.64 $21.80 $23.00 Energy Charge ($/kWh)
Tier 1 (0–750 S; 0–350 W) $0.1102 $0.1179 $0.1266 $0.1364 $0.1364 $0.1379 Tier 2 (751–1,500 S; 351–750 W) $0.1753 $0.1880 $0.2007 $0.2134 $0.2261 $0.2388 Tier 3 (>1,500 S; >750 W) $0.1988 $0.2127 $0.2285 $0.2462 $0.2462 $0.2488 Reliability Charge ($/month) (1)
Small Residence (<100 Amp) $10.00 $10.00 $10.00 $10.00 $10.00 $10.00 Medium Residence (101–200 Amp) $20.00 $20.00 $20.00 $20.00 $20.00 $20.00 Large Residence (201-400 Amp) $40.00 $40.00 $40.00 $40.00 $40.00 $40.00 Very Large Residence (>400 Amp) $60.00 $60.00 $60.00 $60.00 $60.00 $60.00 (1) No change to the Reliability Charge is proposed for this class.

EXECUTIVE SUMMARY

11 Table ES-7
Existing and Proposed Rates by Commercial – Flat Class
Rate Component Existing
Proposed Effective January 1
2024 2025 2026 2027 2028
Customer Charge ($/month) $20.50 $21.12 $21.96 $22.95 $23.98 $24.94 Network Access Charge
($/month)

Tier 1 (0–500 kWh) $3.35 $3.45 $3.59 $3.75 $3.92 $4.08
Tier 2 (501–1,500 kWh) $9.50 $9.79 $10.18 $10.64 $11.12 $11.56 Tier 3 (1501–3000 kWh) $16.89 $17.40 $18.10 $18.91 $19.76 $20.55 Tier 4 (>3000 kWh) $40.63 $41.85 $43.52 $45.48 $47.53 $49.43 Energy Charge ($/kWh)
Tier 1 (0-15,000 kWh) $0.1486 $0.1531 $0.1592 $0.1664 $0.1739 $0.1809 Tier 2 (>15,000 kWh) $0.2270 $0.2338 $0.2432 $0.2541 $0.2655 $0.2761 Reliability Charge ($/month) (1)
Tier 1 (0-500 kWh) $10.00 $10.00 $10.00 $10.00 $10.00 $10.00 Tier 2 (501–1,500 kWh) $30.00 $30.00 $30.00 $30.00 $30.00 $30.00 Tier 3 (>1,500 kWh) $60.00 $60.00 $60.00 $60.00 $60.00 $60.00 (1) No change to the Reliability Charge is proposed for this class.

Table ES-8
Existing and Proposed Rates by Commercial – Demand Class Rate Component Existing
Proposed Effective January 1
2024 2025 2026 2027 2028
Customer Charge ($/month) $22.10 $22.10 $22.10 $22.10 $22.10 $22.10 Network Access Charge ($/kW) $1.75 $1.75 $1.75 $1.75 $1.75 $1.75 Energy Charge ($/kWh)
Tier 1 (0-30,000 kWh) $0.1242 $0.1242 $0.1242 $0.1242 $0.1242 $0.1242 Tier 2 (>30,000 kWh) $0.1360 $0.1360 $0.1360 $0.1360 $0.1360 $0.1360 Demand Charge ($/kW)
First 15 kW $160.95 $160.95 $160.95 $160.95 $160.95 $160.95 All excess kW $10.73 $10.73 $10.73 $10.73 $10.73 $10.73 Reliability Charge ($/month) (1) $90.00 $90.00 $90.00 $90.00 $90.00 $90.00 (1) No rate changes are proposed for this class.

EXECUTIVE SUMMARY

12 Table ES-9
Existing and Proposed Rates by Industrial TOU Class
Rate Component Existing
Proposed Effective January 1
2024 2025 2026 2027 2028
Customer Charge ($/month) $659.88 $686.28 $713.73 $742.28 $760.84 $776.06 Network Access Charge ($/kW)
Low Voltage
$2.89 $3.87 $4.85 $5.83 $6.81 $7.77
Network Access Charge ($/kW)
High Voltage
$1.71 $2.24 $3.22 $4.20 $5.18 $6.14
Energy Charge ($/kWh)
On-Peak $0.1154 $0.1197 $0.1245 $0.1295 $0.1314 $0.1340 Mid-Peak $0.0946 $0.0981 $0.1020 $0.1061 $0.1077 $0.1099 Off-Peak $0.0808 $0.0838 $0.0872 $0.0907 $0.0921 $0.0939 Demand Charge ($/kW)
On-Peak $7.38 $7.66 $7.97 $8.29 $8.41 $8.58
Mid-Peak $3.69 $3.83 $3.98 $4.14 $4.20 $4.28
Off-Peak $1.85 $1.92 $2.00 $2.08 $2.11 $2.15
Reliability Charge ($/month) (1)
<= 100 kW $350 $350 $350 $350 $350 $350
101-150 kW $750 $750 $750 $750 $750 $750
151-250 kW $900 $900 $900 $900 $900 $900
251-500 kW $1,100 $1,100 $1,100 $1,100 $1,100 $1,100
501-750 kW $1,850 $1,850 $1,850 $1,850 $1,850 $1,850
> 750 kW $2,650 $2,650 $2,650 $2,650 $2,650 $2,650
(1) No change to the Reliability Charge is proposed.

Further discussion of the proposed rates is provided in Section 6 of this Report. However, the proposed rates are designed to fully recover RPU’s Revenue Requirement on average over the Study period. Rate adjustments for the “other” customer classes are also in Section 6 of this Report.

RPU without Rate Adjustments
RPU’s operations and needed investments cannot be sustained without rate adjustments. Rates must be adjusted to more accurately reflect the high fixed costs relative to the variable cost structure. If rates are not adjusted, RPU will not be able to fund its future investments, its increased operating costs, and will fail to maintain its strong financial metrics. RPU’s existing reserves are not sufficient to pay for the planned investments. Additionally, drawing down on its reserves will also lead to higher borrowing costs for the City, as a result of the anticipated negative impacts to its credit rating.

Economics | Strategy | Stakeholders | Sustainability

INTRODUCTION
Introduction
Riverside Public Utilities (RPU) is a municipal public utility owned by the City of Riverside, California (City) that provides power to the citizens of the City. RPU has been providing efficient, reliable service to the City since 1895, and is committed t o providing the highest quality electric service at the lowest possible rates to benefit the community.

The City has developed a comprehensive strategic planning effort called “Envision Riverside 2025” to support its mission of providing high quality mun icipal services to ensure a safe, inclusive, and livable community. As part of this strategic effort, the City has defined several aspirational descriptions that envision Riverside in 2025, several of which are related to RPU and its operations. These in clude those regarding the environment as “renewable, and stewarded,” the Riverside economy as “growing, fiscally secure, equitable, innovative, and green,” and the community as “well -maintained, safe, and engaged.” These Envision Riverside 2025 efforts also developed several cost -cutting threads which are themes woven into the planning effort and which are reflected in its outcomes. These cost-cutting threads include “Community Trust,” “Equity,” “Fiscal Responsibility,” “Innovation,” and “Sustainability and Resiliency.” These themes are embedded in the City’s strategic priorities within its planning efforts. Of the six strategic priorities identified by the City, there are two primary areas, each with their own specific goals, for which RPU has been assigned responsibility. These are the strategic priorities of “Environmental Stewardship” and “Infrastructure, Mobility and Connectivity.”
Environmental Stewardship is defined in part within Envision Riverside 2025 as “Champion proactive equitable climate solutions . . . to ensure clean air . . . and a resilient green new economy for current and future generations.” Specific goals within this priority that are directly related to RPU’s electric operations include those related to “decreasing Riverside’s carb on footprint . . . to achieve 100% zero carbon electricity production by 2040 while ensuring safe, reliable and affordable energy for all residents.” The “Infrastructure, Mobility and Connectivity” strategic priority is defined, in part, as “ensure safe, reliable infrastructure that benefits the community and facilitate a connection between people, place and information.”
Achieving the goals of the specific strategic objectives assigned to RPU, along with RPU’s ongoing commitments, capital planning effort s, and other financial responsibilities, results in an increased projection of costs for the utility to operate, maintain, and invest in its current and existing infrastructure.

Current estimates of projected increases in electricity usage at existing rates are insufficient to cover these projected costs.

This Electric Cost of Service and Rate Design Study (Study) addresses RPU’s need for increased retail rate revenue to meet projected costs. This Study determines the basis for cost allocations between customer classes. Additionally, this Study considers existing rate trends of other utilities in similar situations to construct new rate designs that meet future revenue needs in an environment of increased energy efficiency, energy conservation, regulatory and environmental uncertainty, and customer self-generation.

The process of conducting a cost of service (COS)/rate design analysis generally proceeds as follows:

Section 1

1-2

1. Establish the Revenue Requirement – determine the total revenues the utility must collect over a specified period of time to serve its customers, maintain its debt service obligations, invest in its system, and provide additional funds required by fiscal and reserve policies, as appropriate. The period of time covered by the Revenue Requirement (as well as the rates) is defined as the Test Year.

2. Functional Unbundling – an electric utility can be thought of as four major business units or functions.

The Functional Unbundling divides the Revenue Requirement into these business units by examining the underlying costs and why they are incurred. These functions include:
a. Production
b. Transmission
c. Distribution
d. Customer service

3. Classify Costs Within Functional Area – costs are classified based on th e underlying nature of these costs, or what is driving each cost category, within each functional area. Classes of costs include system demand, energy consumptions, the number of customers being serviced, or costs that are directly attributed (or allocated) to a specific class or customer.

4. Allocation of Costs across Customer Classes – based on the customer usage characteristics of the system, allocate the classified costs to customer classes, and determine the COS for the classes.

5. Design Rates – rate desig n is based on a combination of analysis of the customer class Revenue Requirements (the allocated share of the system costs) and policy decisions.

In 2021, the City contracted with NewGen Strategies and Solutions, LLC (NewGen) to provide a Study to evaluate RPU’s projected costs, allocate costs to their customer classes, and assist in the recommended changes to their retail rates.

Schedule
The retail rates proposed herein will be conceptually presented to the City Council, the RPU Board , and community groups before being presented to the City Council and the RPU Board for approval. For the purposes of this Report, it is assumed that the recommended series of rate changes would be effective January 1, 2024, and January 1 of the following four years ending in 2028.

Rate Design Objectives/Rate Making Principles
RPU considered a variety of factors in the development of their recommended rates, including a review of their rate making principles. Rate making principals are a common element especially in municipally owned utilities as they provide overall guidance to how the City sets prices for its services. A critical factor included in rate making principles is that rates and charges are designed such that the total Revenue Requirement of the system will be recovered from customers, and that rates are designed in an equitable manner consistent with the results of the Study. In addition, RPU carefully considered the overall revenue stability for the electric utility (and its customer classes), t he historical rate structures in place, policy considerations for conservation and energy efficiency, and competitiveness with neighboring utility systems, as well legal requirements and other energy -related policies established by the City Council during the electric rate design. The following Table 1-1 provides a list of RPU’s policy goals related to its electric and water rate design, with the specific application identified for this Study and the Five-Year Rate Plan.

INTRODUCTION

1-3
Table 1-1
RPU Policy Goals and Five-Year Rate Plan
RPU Ratemaking Principles
Five-Year Electric Rate Plan –
Implementation
Achieve full recovery of costs Rates designed to recover projected Revenue Requirements over Study period
Equitably allocate costs across and within customer classes Increase/implement fixed cost recovery mechanisms to align rate structures with costs
Encourage efficient use of water and electricity Design rates to discourage overuse and to reward efficiency
Provide rate stability Maintain consistency between rates within each year of the Study period
Offer flexibility and options Reduce rate-related bill impacts for customers transitioning between classes
Maintain rate competitiveness in region Consider/mitigate rate-related impacts to all customers including low use customers
Be simple and easy to understand Maintain simplicity of rate structures and components of existing rate structures, as appropriate

Additional detail on RPU’s Rate Policy/Objectives is provided in Section 6 of this Report.

Riverside Five-Year Rate Plan
The retail rates proposed herein include a Five -Year Rate Plan, which is intended to achieve the rate objectives, as defined herein, throughout the period (Rate Plan period), beginning in fiscal year (FY) 2024 and running through FY 2028. The Five-Year Rate Plan is intended to be an all-inclusive plan; if only partial years of the plan are approved, RPU may not achieve its rate objectiv es. Proposed rates for the “major” customer classes are provided in the Report; rates for the other or “ancillary” rate classes are provided in Appendix A to this Report. Detailed information that supports the projected costs, cost allocations, and the development of the retail rates is provided in the Technical Appendix (Appendix B to this Report).

The proposed rates are designed to recover the Revenue Requirement over the projected period and are driven by the proposed investments, expenses, and other financial needs of the system. The proposed rates recognize the potential financial impacts to customers and are designed to achieve rate stability (in terms of year-to-year changes in the rates). Therefore, the rate plan described herein uses a “gradual” approach to achieving the goals and objectives of RPU by the end of the proposed Rate Plan period.

The changes in rates and rate structures support the equitable cost allocation between customer classes, which includes proposed increases in the fixed cost recovery rate components of each customer class rate tariff. The Five-Year Rate Plan promotes rate stability by not dramatically altering rates for each year of the Stud y. Because this gradual approach is phased -in over the Study period, the exact annual total system revenue for each year derived from the COS analysis does not align with the exact annual total revenue in the Financial Pro Forma Model. The result of the proposed changes to RPU’s retail rates in the COS analysis are projected revenues that will support RPU as it moves forward with its investments into the future.

Section 1

1-4
Table 1-2 provides a summary of the debt service coverage calculation utilizing the COS Mode l revenue values applied to the Financial Pro Forma Model. RPU’s Financial Pro Forma targets a debt service coverage of 2.00, while maintaining RPU’s reserve policy target minimum debt service coverage ratio of

1.75 (calculated as the ratio of estimated n et revenues available for debt service divided by maximum annual debt service) for financial planning purposes. The projected debt service coverage ratios range from 1.99 to 2.42, and average 2.21 over the Study period.

Table 1-2
Financial Metrics for Study Period ($000)
Category
FY Ending
2024 2025 2026 2027 2028
Projected Retail Revenue (COSA) $362,738 $384,785 $410,158 $432,613 $451,226 Projected Other Revenue (1) $59,200 $56,831 $72,118 $73,407 $47,084 Expenses, Reserves, other
Obligations
$299,332 $307,177 $325,092 $331,747 $318,852
Net Revenues Available for Debt
Service
$122,605 $134,439 $157,183 $174,272 $179,457
Debt Service (2,3) $61,607 $64,709 $68,008 $76,604 $74,126 Debt Service Coverage (4) 1.99 2.08 2.31 2.27 2.42
(1) For purposes of calculating Debt Service Coverage, RPU includes contributions for greenhouse gas allowances and Contributions in Aid of Construction. See text for details.
(2) For purposes of calculating Debt Service Coverage, the Debt Service is limited to the amount due in any given year for Revenue and Pension Obligation Bonds. This debt does not include capital lease, change in interest payable, and general fund allocation (which is included in the Revenue Requirement in Table ES-3).
(3) Net of Build America Bonds Treasury Credit.
(4) Ratio of Net Revenues Available for Debt Service/Debt Service.

RPU Financial Projections
The Revenue Requirement for each of the five years of the Study Period was developed by RPU in its Financial Pro Forma Model as provided in Table 1-3. Additionally, Table 1-3 includes a comparison of the total revenues generated by rates established in January 1, 2023, for the system. The difference between these two values represents the necessary rate adjustments for RPU to achieve the investments, maintenance objectives, and other policies established by the City, and represents a cumulative revenue shortfall of approximately $306 million.

Table 1-3
Revenue Requirement and Revenue for Study Period ($000) FY 2024 FY 2025 FY 2026 FY 2027 FY 2028 Total
Revenue Requirement $362,009 $388,817 $418,591 $441,832 $456,150 $2,067,400 Revenue from Customers (1) $343,699 $347,316 $351,864 $356,678 $361,988 $1,761,545 Difference (2) ($18,310) ($41,501) ($66,727) ($85,155) ($94,162) ($305,855) (1) Utilizing existing 2023 rates, assuming no adjustments for elasticity. (2) Totals may not add due to rounding.

INTRODUCTION

1-5
RPU Study Test Year
The Test Year for this Study was determined to be FY 2024 through FY 2028 (RPU’s FY is from July 1 through June 30; all references are to FY unless otherwise noted). A Test Year results in an average annual value that represents the “mid-point” of that five -year period; however, due to a nticipated growth of system sales, the mid-year (FY 2026) does not necessarily represent the median values of the Test Year. The Five- Year Rate Plan provides a series of rate changes over the five-year period; it is critical that the entirety of the five-year rate adjustments be reviewed collectively, as the intent is to achieve specific financial and policy objectives at the end of the Rate Plan period.

RPU serves retail electricity to a variety of customer classes, including residential (referred to her ein as Domestic), commercial, industrial, street lighting, and others. Additionally, RPU serves City load under a series of separate tariffs. A summary of the rate classes, their existing rate revenues, and their allocated Test Year Revenue Requirement is provided in Table 1-4.

Table 1-4
Existing Test Year Rate Revenues vs. Test Year Revenue
Requirements ($000)
Rate Class
Test Year
Existing Rate
Revenues (1)
Test Year
Revenue
Requirement Difference
Domestic $138,817 $163,158 $24,340
Commercial – Flat $48,459 $54,403 $5,943
Commercial – Demand $32,173 $29,127 ($3,045)
Industrial TOU $118,918 $150,853 $31,936
Street Lighting (2) $4,867 $5,787 $920
Other (3) $8,950 $10,493 $1,543
Total (4) $352,185 $413,821 $61,637
(1) Based on existing rates and Test Year (five-year average billing determinants). (2) Street Lighting includes Customer Owned and Department Owned. (3) Includes city rates, traffic signals, and agricultural pumping. (4) Totals may not add due to rounding.

The analysis presented in Table 1-4 indicates that the Domestic, Commercial-Flat, Industrial Time-of-Use (TOU), and Other class revenues are not sufficient to meet their respective Test Year Revenue Requirements. The “Other” class primarily consists of City load, as well as minor contributions from traffic signals and agricultural pumping. This analysis suggests that existing rate revenue for the Street Lighting customer class is slightly less than their Test Year Revenue Requirement. The Commercial – Demand customer class revenues are slightly in excess of their projected Test Year Revenue Requirement.

The value of the difference between the total Test Year Existing Rate Revenue and the Test Year Revenue Requirement represents an “average” year (based on the Test Year concept, as discussed). During the course of the Five- Year Rate Plan, it is expected that some customers’ load (sales) will increase, as discussed in Section 2. Therefore, the average revenue difference for the Test Year will equal the shortfall identified in Table 1-4 when applied to the changes in customer usage characteristics.

Section 1

1-6
Test Year/Audited Year
As indicated, the Test Year for RPU was determined to be within the period from FY 2024 to FY 2028, based on unaudited projections provided in the RPU’s Pro Forma Financial Model . For the purposes of this Study, audited FY 2021 values we re utilized as the basis for financial information , with known and measurable changes provided by RPU to develop the Test Year values. The FY 2022 period was utilized to determine the underlying details of the customer usage statistics and estimates for c lass revenue were based on load projections provided by RPU and rates effective January 1, 2023.

RPU Specific Rate Considerations
California Requirements/Proposition 26
As a municipal public utility, RPU must comply with a number of mandates and requirements enacted by the State of California (State), including a renewable portfolio standard (RPS), energy efficiency programs, public benefits charges, and others.

The voters in the State approved Proposition 26 on November 2, 2010. Proposition 26 amend ed Article XIII C of the State Constitution to expand the definition of “tax” to include “any levy, charge, or exaction of any kind imposed by a local government” with listed exceptions. By means of these exceptions, Article XIII C classifies several type s of charges, in addition to property -related charges, that are not taxes, such as charges for specific services or benefits, regulatory charges and penalties.

Article XIII C’s definition of “tax” includes the following exceptions: (1) a charge imposed fo r a specific benefit conferred or privilege granted directly to the payor that is not provided to those not charged, and which does not exceed the reasonable costs to the local government of conferring the benefit or granting the privilege; (2) a charge im posed for a specific government service or product provided directly to the payor that is not provided to those not charged, and which does not exceed the reasonable costs to the local government of providing the service or product; (3) a charge imposed for the reasonable regulatory costs to a local government for issuing licenses and permits, performing investigations, inspections, and audits, enforcing agricultural marketing orders, and the administrative enforcement and adjudication thereof; (4) a charge imposed for entrance to or use of local government property, or the purchase, rental, or lease of local government property; (5) a fine, penalty, or other monetary charge imposed by the judicial branch of government or a local government, as a result of a violation of law; (6) a charge imposed as a condition of property development; and (7) assessments and property -related fees imposed in accordance with the provisions of Article XIII D.

Proposition 26 also provides that the local government bears the burden of proving by a preponderance of the evidence that a levy, charge, or other exaction is not a tax; that the amount is no more than necessary to cover the reasonable costs of the governmental activity; and that the manner in which those costs are allocated to a payor bear a fair or reasonable relationship to the payor’s burdens on, or benefits received from, the governmental activity. This “fair and reasonable relationship” standard is supported by the COS approach.

Net Energy Metering Regulations
Net Energy Metering (NEM) legislation was passed by the State to stimulate private investment in renewable forms of electrical generation (Public Utilit ies Code section 2827 et seq.) . California law imposed these requirements on investor -owned and publicly owned utilit ies. Under NEM legislation,

INTRODUCTION

1-7
customers are able to receive compensation from their utilit y for excess energy that is returned to the electrical grid. Under NEM, customers are compensated for such excess energy at the utility’s average cost o f renewable energy. The NEM legislation provides that when a utility achieves 5% of its total capacity (in megawatts or MW) available at peak usage, it could differentiate such rates for new NEM customers.

RPU introduced changes to its NEM program referr ed to as the “Self -Generation Program” which were adopted by the City Council on May 10, 2022, and have been effective as of November 1, 2022. The primary results of these changes are that the compensation which customers receive for their excess energy i s calculated at RPU’s avoided cost of energy (ACOE); the manner in which excess energy is determined has changed; and there is a new requirement that Self-Generation customers be served on a time of use (TOU) rate schedule for certain customer classes. Customers in the Self-Generation Program are still able to reduce their load by off-setting RPU purchases with production from their on-site systems at applicable retail rates.

Report Outline
The remaining sections of this Report provide a summary of the system and customer class characteristics (Section 2), RPU’s Revenue Requirement (Section 3), the methods utilized for the cost allocation process (Section 4), the results of the cost allocation (Section 5), and the proposed rate design (Section 6).

Appendix A provides a summary of the proposed rates for RPU’s ancillary rate/customer classes .

Appendix B provides a technical appendix of the analysis, data sources, and other supporting information utilized in the development of this Report.

Economics | Strategy | Stakeholders | Sustainability

SYSTEM CHARACTERISTICS
Introduction
RPU operates the Electric System as a vertically integrated utility providing service to virtually all electric consumers within the City’s limits, which encompass 81.5 square miles. The City is the sole provider of electric service within its territory. RPU’s power supply consists of electric generation facilities owned by the City, entitlements to other generation facilities, power purchase contracts , and open market purchases.

RPU had 99.2 circuit miles of sub -transmission and 1, 351 circuit miles of distribution lines as of the FY ending June 30, 2022. Of the distribution lines, 821 circuit miles of underground lines are primarily in commercial and new residential areas. There are 16 substations within RPU’s electrical system.

Demand and Energy Requirements
The system peak for the FY ending June 30, 2022, was 576 megawatts (MW), which included providing service to 11 2,328 meters. Table 2 -1 provides a summary of the system usage characteristics for RPU, including total retail customers, megawatt-hours (MWh) of electricity, and the total peak load (MW) for the Electric System during FY 2022, estimated for FY 2023, and for each of the projected years of the Test Year (FY 2024–FY 2028). The peak demand for the Test Year is projected to be lower than the peak demand for FY 2022 as the projections are adjusted for a “normal” weather year by RPU.

Table 2-1
System Usage Characteristics

FY Ending
2022 2023 2024 2025 2026 2027 2028
Total Meters 112,328 112,393 112,904 113,418 113,936 114,458 114,984 Total Energy (MWh) (1) 2,143,518 2,111,926 2,133,347 2,141,350 2,155,793 2,172,475 2,198,523 Peak Demand (MW) (2) 576 595 598 600 602 605 608
(1) Energy projections for 2023–2028 represent expected retail sales after adjusting for elasticity effects. Updated in March 2022. 2022 represents actual energy and peak demand for FY 2022 (ending June 2022) based on RPU’s billing database. (2) Based on RPU forecasted system peaks as of March 2022.

Demand
Demand is a measurement of energy for a short period of time, typically an hour or a 15-minute interval.

Demand is measured in kilowatts (kW) or in thousands of kW ( 1000 kW), which are reported as MW. A utility must be able to meet the demands of its systems, which represent the total hourly demands of its customers, at any given time. To meet these demands, utilities will typically invest in generation facilities that are appropriately sized to meet the peak demand or purchase demand (in the form of capacity

Section 2

2-2
contracts) from the power market. Utilities must plan and invest for the system peak capacity, which may go unused during periods of low electrical use. For RPU, the system typically peaks in the months of June through September. During the non-summer months, there is a significant drop -off in system demand.

The ambient temperature drives RPU ’s system peak; as outside temperatures increase , residential customers utilize their air conditioning units to provide relief. Therefore, from a cost causation perspective, the residential class is driving the majority of the system peak demand.

The peak demand for RPU for FY 2022 was approximately 576 MW, which occurred on June 27, 2022, at 4:00 p.m. The peak demand is often referred to as the “Coincident Peak” (CP) because it is the amount of total load from all customers collectively at the same time (coincident wit h ea ch other). CP is an important tool utilized in allocating costs for a COS Study and is discussed further in Section 4 of this Report.

Energy Sales
Energy is the demand that is measured over multiple hours. Energy is measured in kWh and is the product (and service) that most people associate with purchasing from their electric utility. A utility must provide energy to its customers in a reliable, continuous, and safe fashion. Energy is primarily instantaneous—it cannot be effectively stored in large amounts for later use. A utility will use the installed investment in generation (capacity or available demand) to produce energy, typically by burning fossil fuel (either gas or coal, depending on the resource) or with renewable resources (solar, wind, geothermal). Alternatively, a utility may purchase energy in the power market to meet its customers’ load.

Figure 2 -1 provides a representation of the total energy used by RPU’s primary customer classes for FY 2022 based on analysis of their billing database for that period. Given the historically low energy usage and lack of meters, the street light classes (as well as City load, traffic lights , and agricultural load) are collectively included in the “Other Classes” category for the purposes of the system characteristics (Section 2).

Figure 2-1. Total Energy Consumption by Customer Class for FY 2022 (000 kWh or MWh) Historical and projected energy sales by customer class are provided in Table 2-2 (for the major customer classes).

SYSTEM CHARACTERISTICS

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Table 2-2
Historic and Projected Energy Sales (000 kWh or MWh)

FY Ending
2022 2023 2024 2025 2026 2027 2028
Domestic 759,049 717,866 706,524 708,147 711,702 716,000 723,480 Commercial – Flat 269,075 271,892 278,210 279,645 281,919 284,465 288,086 Commercial – Demand 174,102 182,430 186,469 187,365 188,799 190,409 192,717 Industrial TOU 922,804 939,077 961,484 965,533 972,713 980,941 993,580 Other Classes (2) 18,488 17,502 18,363 18,363 18,363 18,363 18,363 Total System (1,3) 2,143,518 2,128,768 2,151,050 2,159,053 2,173,496 2,190,178 2,216,226 (1) Projections include the projected impact associated with price elasticity; see text for discussion. (2) Other classes include streetlights, traffic lights, and agricultural load. (3) Total System sales excludes losses. Totals may not add due to rounding.

Actual energy sales in FY 20 22 for the Domestic class and the RPU system were higher than those projected for FY 2024. One reason for this is because FY 2022 was an exceptionally hot summer period while projections for FY 2024 and beyond are based on normalized weather patterns . Additionally, FY 2022 domestic usage was influence by coronavirus disease 2019 ( COVID-19) related restrictions, the impacts of which are expected to be reduced in future years. Based on statistical an alysis completed by RPU’s ROSA Team, it is anticipated that total system load growth will incre ase over the course of the Test Year at a rate of approximately 0.75% per year.

In addition to normalizing for weather, the total projected energy sales have been adjusted for the anticipated effects of price elasticity. Price elasticity is an economic theory that suggests that when prices increase/decrease for any item, customers respond in an economic fashion by either purchasing more or less of that item. Price elasticity has been proven to exist for electricity sales. The RPU Financial Pro Forma Model includes estimates of price elasticity on its projections for energy sales. The impacts from the systemwide rate adjustments in the Financial Pro Form a Model have been incorporated into the customer class analyses for this Study, as presented in Table 2 -2 and in the energy sales projections throughout this Report.

Average Number of Meters by Customer Class
The average number of meters by major customer class served by RPU for the period of FY 2022 and projected for FY 2023 through FY 2028 is provided in Table 2-3.

Section 2

2-4
Table 2-3
Historic and Projected Meters by Class

FY Ending
2022 2023 2024 2025 2026 2027 2028
Domestic 99,731 99,550 99,897 100,243 100,590 100,936 101,283 Commercial – Flat 10,942 10,934 11,075 11,218 11,365 11,515 11,668 Commercial – Demand 980 953 965 977 990 1,003 1,016
Industrial TOU 625 608 621 635 649 644 678
Other Classes (1) 50 53 53 53 53 53 53
Total System (2) 112,328 112,098 112,611 113,126 113,647 114,151 114,698 (1) Other classes include streetlights, traffic lights, and agricultural load. (2) Projected meters are the average monthly projected meters for each fiscal year.

Customer Statistics
Meter statistics by major rate class for FY 2022 are provided in Table 2-4. As shown, the majority of the customers served by RPU are in the Domestic rate class ; however, the Industrial TOU rate class has the largest share of the total annual energy sales.

Table 2-4
Actual Customer Usage Statistics for FY 2022

FY Ending 2022
Number of
Meters
Percent
of Total
Annual Sales
(MWh)
Percent
of Total
Domestic 99,731 88.79% 759,049 35.41%
Commercial – Flat 10,942 9.74% 269,075 12.55%
Commercial – Demand 980 0.87% 174,102 8.12%
Industrial TOU 625 0.56% 922,804 43.05%
Other Classes (1) 50 0.04% 18,488 0.86%
Total System (2) 112,328 2,143,518
(1) Other classes include streetlights, traffic lights, and agricultural load. (2) Totals may not add due to rounding. Based on analysis of RPU billing database for 2022.

Fixed/Variable Costs and Cost Recovery
As previously indicated, RPU’s cost structure does not align with its existing rate structure. System costs for the Test Year based on the COS analysis have been identified as approximately 55% fixed, reflecting costs for investments (financed with both cash and debt service), power supply contracts, labor , and

SYSTEM CHARACTERISTICS

2-5
equipment. The remaining costs of approximately 45% are variable, which includes fuel/purchased power (not under long-term contracts) and variable transmission costs.

The revenues generated from retail sales under RPU’s existing rates for FY 20 22 are estimated to be approximately 30% fixed (which includes the customer ch arge, reliability charge, and minimum demand charge, as applicable) and 70% variable (which includes the energy charge). Figure 2 -2 provides a depiction of the mix between the fixed and variable nature of the Test Year costs (on the right ) and the revenues for FY 2022 (on the left).

Figure 2-2. Structure of Test Year (COS) Costs versus FY 2022 Revenues

Economics | Strategy | Stakeholders | Sustainability

REVENUE REQUIREMENT
Summary
The revenue requirement refers to the amount of rate-related revenue a utility is projected to need during the Study period. As indicated earlier, for the purposes of this Study, RPU is utilizing a Test Year that represents the average of the five- year period begin ning in FY 2024 and ending in FY 2028. RPU’s net Revenue Requirement for the Test Year is $413,479,992 (rounded to $413.5 million). This value is driven by the specific “known and measurable changes” related to the investments projected in RPU’s Pro Forma Financial Model. Because the Test Year is a multi-year representation, this value represents the average annual revenue to be collected by RPU’s retail rates. For purposes of rate design, provided in Section 6 of this Report, revenues collected over the Study period will vary by year.

Detailed information regarding each component of RPU’s Revenue Requirement for each year of the Study period is provided in the Technical Appendix B. These projections were obtained from RPU’s Pro Forma Financial Model. A summary of the Test Year Revenue Requirements is provided in Table 3-1.

Table 3-1
Revenue Requirement by Function for Test Year ($000)
Function FY 2024 FY 2025 FY 2026 FY 2027 FY 2028
Test Year
Value
Percent
of O&M
Production O&M $177,117 $169,461 $175,379 $178,159 $188,078 $177,639 55.5% Transmission O&M $64,651 $66,913 $69,137 $71,613 $47,543 $63,972 20.0% Distribution O&M $21,482 $22,294 $23,202 $23,940 $24,681 $23,120 7.2% Customer O&M $9,446 $9,803 $10,203 $10,527 $10,853 $10,166 3.2% Administrative and General O&M $41,873 $43,455 $45,226 $46,665 $48,108 $45,065 14.1% Total O&M $314,569 $311,926 $323,146 $330,905 $319,264 $319,962 Debt Service $63,000 $66,087 $69,441 $78,260 $75,784 $70,514 Transfer to General Fund $45,419 $45,334 $48,505 $52,025 $54,799 $49,216 Capital Funded by Rates $4,071 $4,290 $4,194 $3,502 $4,038 $4,019 Allocation to (Use of) Reserves ($19,019) $8,445 $22,540 $28,980 $28,212 $13,832 (minus) Other Revenues ($46,030) ($47,265) ($49,235) ($51,840) ($25,947) ($44,063) Net Revenue Requirement $362,009 $388,817 $418,591 $441,832 $456,150 $413,480 Source: RPU Financial Pro Forma Model and COS Model. Note, numbers may not add due to rounding.

As Table 3-1 indicates, and as is typical for electric utilities, the production function is the costliest function for RPU to serve its customers. Non-O&M costs include debt service, associated with existing and future debt issues required to fund existing and future investments in th e system; the transfer to the General Fund (as determined by the City); capital funded by revenue, which are investments that are made to the

Section 3

3-2
system and are paid for by rate revenue (not debt financed); and reserves, which are driven by the City’s reserve policy (discussed below).

The calculation of the Revenue Requirement includes an offset (or credit) for revenues that are obtained by RPU from other sources, including interest income , as well as the California Independent System Operator (CAISO) (transmission-related). The credit of “non -retail” revenues recognizes that the net Revenue Requirement is only associated with the revenue needed from retail sales.

RPU Reserve Policy
To support its operations and future borrowing capacity , RPU has developed a robust reserve policy, which is designed to promote fiscal sustainability, minimize borrowing costs, and provide a source of funds to rapidly respond to market volatility, emergencies, demand reductions, or regulatory changes. The reserve policy guidelines were incorporated into its fiscal policy, which was adopted by City Council on July 26, 2016.

The overall reserve target is designed to address five risk categories, each with a minimum and maximum target based on specific metrics. Table 3-2 provides a summary of the metrics that are used to calculate the unrestricted undesignated target minimum and maximum reserve levels for each risk category.

Table 3-2
RPU Reserve Policy Summary
Risk Category Minimum Maximum
Operating (Working Capital): maintain sufficient resources to pay budgeted O&M expenses recognizing the timing differences between payment of expenditures and receipt of revenues.
60 Days of Operating
Expenses
90 Days of Operating
Expenses
Rate Stabilization: mitigates rate shock due to temporary and transitional regulatory changes, loss of a major resource, sharp demand reduction, or market volatility.
10% of Operating
Revenues
20% of Operating
Revenues
Emergency Capital: provides funds to maintain ability to repair system after an emergency or natural disaster such as a flood, earthquake, or major storm.
1% of Depreciable
Assets
2% of Depreciable
Assets
System Improvements Capital: provide funds to maintain continuity of construction over FYs to be reimbursed by bond proceeds or other resources.
6 Months of three year
average Annual CIP
9 Months of three year
average Annual CIP
Debt Service: maintain ability to make debt service payments in an extreme event that may impact RPU’s ability to provide services, thus impacting revenues at a time when critical infrastructure repairs are needed to restore systems. The Debt Service Reserve is intended to prevent an event where RPU would be unable to pay its debt service obligations during such emergencies or extreme market disruptions.

Maximum Annual Debt
Service in Upcoming FY
Maximum Annual
Debt Service in
Upcoming FY

The reserve levels vary in each year based on the expenditures or revenues used to calculate each component. Table 3-3 provides the projected target minimum and maximum reserve for each year of the Five-Year Rate Plan.

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Table 3-3
RPU Reserve Policy – Minimum and Maximum by Risk Category ($000) FY Ending
Risk Category Target 2024 2025 2026 2027 2028
Working Capital Minimum $51,710 $51,276 $53,120 $54,395 $52,482 Maximum $77,565 $76,913 $79,670 $81,593 $78,723
Rate Stabilization Minimum $40,575 $42,936 $47,345 $49,669 $48,553 Maximum $81,150 $85,873 $94,690 $99,339 $97,107
Capital – Emergency Minimum $13,546 $15,354 $16,154 $16,837 $17,553 Maximum $27,092 $30,709 $32,308 $33,673 $35,105
Capital – System Improvements Minimum $28,861 $31,206 $33,253 $33,596 $33,845 Maximum $43,291 $46,809 $49,879 $50,394 $50,767
Debt Service Minimum $40,080 $42,316 $50,399 $50,674 $52,281 Maximum $40,080 $42,316 $50,399 $50,674 $52,281
Total (1) Minimum $174,772 $183,088 $200,271 $205,171 $204,714 Maximum $269,178 $282,620 $306,946 $315,673 $313,983 Source: RPU Pro Forma Financial Model.
(1) Totals may not add due to rounding.

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ALLOCATION OF SYSTEM COSTS
Functionalization and Classification
Allocating cost to a utility ’s customer classes is achieve d through three major processes :
1) functionalization, 2) classification, and 3) allocation. The functionalization and classification of the Test Year Revenue Requirement are discussed in the first part of this Secti on. The development of the allocation factors for the Test Year Revenue Requirement is discussed in the second part of this Section.

Functionalization of Test Year Expenditures
Although budgeting and accounting sy stems generally follow functional groups ( e.g., production, transmission, etc.) , certain costs , such as those associated with administrative and general (A&G) expenses, are not generally assigned by accounting and budgetary convention to major function. A COS study usually requires the rearrangement of certain expenditures into functional groups : 1) to be more representative of the expenditure causation, 2) to combine costs that have been incurred for a similar purpose, and 3) to facilitate the allocation of cost responsibility. Thus, the functionalization of certain costs is a rate making mechanism to apportion such costs to the common utility functions. Table 4-1 provides a categorization of the COS by function (as a result of the cost allocation process).

Table 4-1
Cost of Service by Function
Function
Test Year Value
($000) Percent
Production $246,742 59.6%
Transmission $45,734 11.1%
Distribution $107,640 26.0%
Customer $14,604 3.5%
Direct Assignment (1) ($898) (0.2%)
Total (2) $413,821
(1) Direct Assignment of revenues derived from RPU services provided to other utilities.
(2) Numbers may not add due to rounding.

Classification of Various Costs
Electric utility costs are generally classified as either 1) demand related, 2) energy related, 3) customer related, 4) revenue related, or 5) directly assigned. A discussion of the cost classifications is provided in this section.

Section 4

4-2
Demand (fixed) costs are defined as those expenses that are incurred to maintain a “readiness to serve:” an electric system capable of meeting the total combined demands of all customers at all hours, including peak demand. Demand cost s are those that are generally fixed in the short run, do not materially vary directly with the number of kWh generated or sold, and are not defined as customer costs. Demand costs include a portion of the O&M expenses, debt service, renewal and replacements (ongoing improvements and investments), and other costs that are not defined as specifically customer or variable energy costs.

Energy (variable) costs are defined as those expenses that vary substantially or directly with the amount of energy sold (either generated or purchased), includ ing such items a s fuel and a portion of the O&M expenses for production facilities (known as variable O&M). However, not all energy procurement contracts are variable; contracts may be known as “take or pay ,” in which a utility either accepts the associated energy or not, but is still responsible for a fixed amount of annual capacity costs . RPU has several such contracts, which are defined as fixed costs.

Customer costs are defined as those expenses directly related to the number, type, and size of customers, such as customer accounting and bill collecting, and the costs of meters and ser vices. Also, a portion of the d istribution investment and operating costs are classified as customer costs because the size and design of the distribution system is a function of both the number of customers and their load (demand).

The custom er portion o f the distr ibution system for RPU was det ermined from a minimum system analysis.

Revenue-related costs are associated with the amount of revenue generated by RPU. Taxes are a general example of revenue- related costs. However, for municipal entities such as RPU that do not pay taxes, revenue-related costs include the transfer to the general fund, as discussed in Section 3.

There is another category of cost classification that is known as “direct assignment .” The direct assignment costs may be related to demand, energy, customer , or other type of classification; however, these costs ar e removed from the overall Revenue Requirement and allocated directly to a specific customer class or customer. The example most often cited for direct assignment is the costs associated with providing electric service to street lights because the Federal Energy Regulatory Commission (FERC) chart of accounts includes specific cost account s for street lighting expenses. For the purposes of this Study, both street lighting costs and specific RPU derived revenues (credits) are directly assigned to those individual customer classes. Additionally, because the street lighting class contributes minimally to the total load and energy of the system, for the purposes of this section, they are included in the Other Classes category.

Development of Allocation Factors
General
This Section discusse s the develop ment of the factors utilized to allocate the capa city-related, energy-related, customer -related, and other costs to the various RPU customer classes. The aforementioned costs are allocated to the customer classes according to their respective customer class and the particular cost allocation factor developed for each class and for each type of cost. The customer classes include Domestic, Commercial – Flat (non-Demand), Commercial – Demand, Industrial TOU, City, and Others (including Street Lights).

ALLOCATION OF SYSTEM COSTS

4-3
Demand Allocation Factors
Demand allocation refers to the basis on which capacity and other demand-related costs are distributed or assigned (allocated) among the various customer classes for the purposes of determining the revenues required from each class to re cover such costs. The demand allocation factors, as developed and used herein, reflect the cost responsibility for each of the various customer classes in relation to the capacity- or demand-related cos ts to be allocate d. The demand allocation factors were used to apporti on the following capacity- or demand-related costs among the various customer classes:
 Production expenses (not including fuel)
 Fixed transmission and distribution expenses
 Debt service requirements
For this COS analysis, two different demand allocators were utilized: a 4 Coincident Peak ( 4 CP) and a 4 Non-Coincident Peak (4 NCP). The peak demand is often referred to as the “Coincident Peak” because it is the amount of total load from all customers collectively at the same time (coincident with each other).

For the purposes of this Study, a historic analysis of proxy demand data was used to determine the demand allocators for certain classes. As RPU im plements its advanced metering systems, a review of actual demand readings for these classes will be warranted. 4 CP Method
The CP demand allocation methodology allocates costs based on the customer class contributions to the system CP. Typically, CP allocators are utilized t o assign production demand -related costs to customer classes, because production demand costs are driven by the utility’s need to meet its system peak. A 4 CP is utilized for this Study to allocate production costs for RPU. The projected monthly demand for each major customer class for the Study period is provided in Appendix B. The results of the 4 CP demand cost allocation process are provided in Table 4-2.

Table 4-2
4 CP Cost Allocation
Customer Class 4 CP (MW) Allocation (%)
Domestic 783 44.8%
Commercial – Flat 209 12.0%
Commercial – Demand 117 6.7%
Industrial TOU 589 33.8%
Other Classes (1) 47 2.7%
Total System (2,3) 1,746
(1) Other classes include street lights, City load, traffic signals and agricultural load.
(2) Based on Test Year projections provided by RPU.
(3) Numbers may not add due to rounding.

Section 4

4-4

Figure 4-1. 4 CP Demand Cost Allocation
As provided in Figure 4 -1, the peak demand months for RPU typically occur in June, July, August , and September. The peak demand is primarily driven by the increase in electricity usage by the Domestic class.
4 NCP Method
The NCP demand allocation method is based on the theory that demand costs are strongly influenced by the highest demand of each cu stomer class, regardless of when that class peak demand occurs. NCP demand allocators are primarily used to allocate transmission and distribution-related costs because the design of these facilities is more consistent with the demand of the classes rather than the demand of the entire system. A 4 NCP is used to allocate distribution demand-related costs for RPU (see Table 4-3).

Table 4-3
4 NCP Cost Allocation
Customer Class
4 NCP
(MW) Allocation (%)
Domestic 815 40.0%
Commercial – Flat 272 13.4%
Commercial – Demand 144 7.1%
Industrial TOU 728 35.7%
Other Classes (1) 77 3.8%
Total System (2,3) 2,036
(1) Other classes include street lights, City load, traffic signals and agricultural load.
(2) Based on Test Year projections provided by RPU.
(3) Totals may not add due to rounding
RPU Monthly Coincident Peaks

ALLOCATION OF SYSTEM COSTS

4-5
Energy Allocation Factors
Energy allocation factors are the basis for apportioning those costs or expense s classified as variable or energy related and assumed to vary directly with the level of kWh sales or generation. The costs classified herein as variable or energy related are fuel and the variable portion of other production expenses.

Total Energy Sales are used to allocate energy -related costs; cost allocations are based on customers’ consumption of energy in kWh. For this analysis, Total Energy S ales is used to allocate energy -related production costs (See Figure 4 -2 and Table 4-4). In Figure 4 -2, the left side of the figure represents the allocated costs by major customer class (the blue bars) in thousands of dollars. The right side (the red line) represents the total energy (in MWh, or 1,000 kWh).

Figure 4-2. Allocation of Energy Costs based on MWh Sales Table 4-4
Energy Cost Allocation
Customer Class MWh Sales Allocation (%)
Domestic 722,615 32.8%
Commercial – Flat 274,000 12.5%
Commercial – Demand 173,197 7.9%
Industrial TOU 935,010 42.5%
Other Classes (1) 95,726 4.4%
Total (2,3) 2,200,549
(1) Other classes include street lights, City load, traffic signals, and agricultural load.
(2) Based on Test Year projections provided by RPU.
(3) Totals may not add due to rounding.

Section 4

4-6

Customer Allocation Factors
Customer costs are defined herein as those costs related to the number of customers and the size of service required. Included in the customer -related costs are the costs associated with meter reading, meter maintenance, customer installations, billing, collecting , and other customer -related accounting, service, and information functions. The customer allocation factors developed for this Study were based on the projected average number of customers in each class during the Test Year.

In allocating customer- related costs and revenues to the various customer classes, customer allocation factors were utilized that recognized weighted and un -weighted number of customers by class. The un-weighted factors are simply the number of customers . The weighted customer allocation factor is based on the number of cus tomers in a particular class times a weighting factor. The weighting factors were developed based on the estimated costs associated with serving non -domestic customer classes , recognizing that serving these customer classes is more expensive on a per-customer basis than domestic classes.

Adjustments to Allocation Factors
Other adjustments were made to specific customer classes recognizing their unique characteristics, either defined by their usage, contracts, or accounting. A summary of these adjustments is provided below.

High Voltage Customers
Some customers on the RPU system take service at a “high-voltage” level; they either use that energy at that voltage or own their own voltage regulating equipment. Because these customers are not utilizing the entirety of RPU’s distribution system (they are only using the “primary” system, not the “secondary” or lower voltage system), they should not be assigned the costs associated with the entire distribution system. Therefore, the cost allocation has been adjusted for the Industrial TOU class (the class in which these customers exist) to recognize this reduction in cost causation.

The resulting rate design for a High-Voltage Adjustment is presented in Section 6 of this Report.

City Load
The City’s load is recognized as unique and is allocated costs based upon production (energy) services from “designated resources.” Specifically, these resources include the Hoover Hydroelectric Project, the Intermountain Power Project, and the Palo Verde Nucl ear Generating Station . A cost differentiation associated with the designated resources as compared to the other resources in RPU’s power supply portfolio has been determined . Additionally, professional Utility staff provide services for scheduling electricity from the California market to neighboring utilities for a fee. Fees are utilized to offset the City’s allocated costs. These cost differentiations are used to create an adjusted cost allocation utilized in this Study, as an adjustment to the standard cost allocation methods identified herein.

Other
Other adjustment factors utilized during the cost allocation process include the use of direct assignment for street lighting. RPU operates and maintains the City's street lighting system and recovers the cost for such operations and maintenance (O&M) (including electricity) through a specific rate tariff. The direct

ALLOCATION OF SYSTEM COSTS

4-7
assignment for street lighting include s assigning costs th at are categorized as street lighting related directly to street lighting to ensure that other customer classes are not allocated those costs.

Economics | Strategy | Stakeholders | Sustainability

ALLOCATED COST OF SERVICE
General
As one of the factors considered in the evaluation of RPU’s existing ret ail rate levels and rate structures included herein, certain analyses have been employed that provide a reasonable indication of the revenue required by RPU’s major customer classes, which include the following:
 Domestic
 Commercial – Flat
 Commercial – Demand
 Industrial TOU
 Street Lighting
 Other
Allocation and Assignment of Cost of Service
The results of the cost allocation analysis are presented in Table 5-1, along with a comparison of the cost recovery currently projected for the Test Year under existing retail rate structures.

Table 5-1
Existing Test Year Rate Revenues vs. Test Year Revenue
Requirements ($000)
Customer Class
Test Year
Existing
Rate Revenue (1)
Test Year
Revenue
Requirement Difference
Domestic $138,817 $163,158 $24,340
Commercial – Flat 48,459 54,403 $5,943
Commercial – Demand 32,173 29,127 ($3,045)
Industrial TOU 118,918 150,853 $31,936
Street Lighting (2) 4,867 5,787 $920
Other (3) 8,950 10,493 $1,543
Total (4) $352,185 $413,821 $61,637
(1) Based on existing rates and Test Year (five-year average) billing determinants. (2) Street Lighting includes Customer Owned and Department Owned. (3) Includes City, traffic lights, and agricultural load. (4) Totals may not add due to rounding.

According to the results of this Study, RPU’s Domestic, Commercial- Flat, Industrial TOU, Street Lighting and Other Customer rates are below the costs RPU incurs to serve these customers, and Commercial –

Section 5

5-2
Demand rates are above the COS. The difference between the Test Year existing rate revenue projections and the Test Year Revenue Requirement s helps drive cost r ecovery by customer class in the rate design process.

Cost of Service Process
The COS process is an industry-accepted framework that assigns or allocates costs to each customer class served by a utility . This process determines the “cost to serve” each customer class within the utility.

Electric utility costs are typically characterized as either fixed or variable; fixed costs are those that do not change with the production of electricity, whereas variable costs are directly related to the amount of electricity produced and/or purchased. These costs are typically further characterized as those that are demand based, customer based, and energy based.

Demand-Based Costs
Most of an electric utility ’s cost structure are demand-based costs. Demand-based costs are associated with fixed costs related to existing and future investments made to produce, transmit, and deliver electrical power from the generation resources to the utility’s customers. For RPU, these costs include the debt service associated with its generation, transmission, and distribution assets, as well as a portion of its contracts for purchased power. The labor and materials associated with the O&M and administration of these systems are also demand-based costs, as the labor costs are typically fixed in the short term (budget cycle). In the short term, fixed costs do not change and represent the ongoing costs to meet the needs of the utility. Fixed costs are primarily allocated to the demand in the COS process because they are designed to support the system as a whole. This mean s that as a result of the COS process, these costs are assigned based on the electric demand (measured in kW) that a specific customer or customer class places on the system. RPU, like most utilities, has a cost structure that is highly fixed, which is typical of highly capital intensive entities.

Customer-Based Costs
Customer-based costs for electric utilities are fixed costs as well, but are costs incurred in direct support of the customers served by a utility. For RPU, this includes the costs associated with the labor, equipment, and investments for customer accounting, billing, and customer assistance (call centers). Additionally, a portion of A&G costs are allocated to the customer -related costs, as they are designed to support this function for RPU. During the COS process, these costs are allocated by the number of customers within a class.

Energy-Based Costs
Energy-based costs for electric utilities are typically variable costs that change with the fluctuations in electric load. The primary example of energy-related costs for RPU are its fuel and purchased power costs.

During the COS process, these are allocated to the customer classes by the amount of energy they are projected to utilize within a selected period of time (during the Test Year).

Retail Rate Review
Background information on the existing rate structure of RPU’s major customer classes is presented below. This includes a compariso n of the existing rates to the COS-based rates and a description of the

ALLOCATED COST OF SERVICE

5-3
development of cost and rate curves. These elements were considered for the individual customer class rate proposals provided in Section 6 of this Report.

The Network Access Charge (NAC) is a mechanism to recover a portion of the fixed demand-related costs associated with use of the electric distribution system. The NAC is designed to recover these costs in the form of a monthly charge for Residential and Commercial – Flat customers, which is tiered based on t he amount of energy used within a month. For Commercial – Demand and Industrial TOU customers, the NAC is a demand charge recovered on a $/kW basis.

Domestic
Table 5-2 provides a summary of RPU’s existing D omestic class rates compared to the COS -based rates developed for this Study. The existing rate includes a $12.06 per month customer service charge, a tiered NAC charge, and a tiered energy rate. The NAC tiers are differentiated by average daily energy usage during the month. The tiered energy rate is the same for summer and winter; however, the requirements for the tier change between the seasons. The summer Tier 1 is monthly energy usage from 0–750 kWh, Tier 2 is for 751 –1,500 kWh, and Tier 3 is for energy used over 1,500 kWh. The winter Tier 1 is from 0 – 350 kWh, Tier 2 is for 351–750 kWh, and Tier 3 is for over 750 kWh.

Table 5-2
Domestic Rates
(Existing and Cost of Service)
Rate Component Existing COS COS – Energy (1)
Customer ($/month) $12.06 $16.69 $16.69
Demand ($/kW) -- $24.57 --
Network Access Charge ($/month) (2)
Tier 1 (< or = 12 kWh Daily Average) $2.49
Tier 2 (>12- 25 kWh Daily Average) $5.97
Tier 3 (>25 kWh Daily Average) $13.16
Energy ($/kWh) (3)
Tier 1 (0–750 S; 0–350 W) $0.1102 $0.0863 $0.1979
Tier 2 (751–1,500 S; 351–750 W) $0.1753 $0.0863 $0.1979 Tier 3 (>1,500 S; >750 W) $0.1988 $0.0863 $0.1979
Reliability Charge ($/month) (4)
Small Residence (<100 Amp) $10.00 -- --
Medium Residence (101–200 Amp) $20.00 -- --
Large Residence (201–400 Amp) $40.00 -- --
Very Large Residence (>400 Amp) $60.00 -- --
(1) Assumes no Demand Charge and bundles demand-related costs within the Energy Charge. (2) Network Access Charge ($/month) is tiered by the Daily Average kWh Usage in the month. (3) The tiered energy rates are the same for summer/winter (S/W); however, the characteristics of the tier change with the season. See text for details.
(4) The Reliability Charge varies by the size of the customer (measured by the electric panel in Amps), and the costs are included in the Demand COS charge.

Section 5

5-4
The tiers have been established to reduce the bill impact for customers that use more energy during the four-month summer period (June 1 through September 30). Because the rates are the same for the tiers, a customer is paying the lower tier rate for more energy (kWh) during the summer than in the winter. For the purposes of this analysis, the impact of state surcharges, including the Public Benefits Charge , are ignored because these changes presented costs that are beyond RPU’s control and are structures mandated by state regulations. Any new rates will include these surcharges.

Table 5-2 provides a summary of the rates derived from the COS analysis. This includes a customer charge of $16.69/month, a demand rate of $24.57/kW, and an e nergy rate of $0.0863/kWh. The COS-based customer charge represents the sum of the costs of metering, billing collections, customer service, and an allocated portion of the distribution system costs on a per customer per month basis. The demand charge represents the cost associated with production, transmission , and the non -customer portion of the distribution system ( this includes the invest ment cost a s well as the fixed costs for o perating and maintaining these systems). The costs associated with the projects identified for the “Reliability Charge” are included in the d emand component of the COS analysis; however, these costs are collected in the Reliability Charge (the revenues from this charge are dedicated to those projects identified to enhance the system reliability).

For the Domestic class, the customer -related costs to serve each customer is $16.69/month; however, RPU’s existing rate structure includes a charge of $12.06/month for this service. Therefore, the remaining customer-related costs are included in the energy rate. Additionally, it costs RPU approximately $24.57/kW of demand-related costs to serve Domestic customers; these costs are also recovered in the existing energy rates. The Reliability Charges and NAC recover a portion of the fixed costs that are included in the $ 24.57/kW demand calculation. RPU’s energy costs are $0.0863/kWh (not adjusted for tiered costs); however, as a result of a lower customer charge and no demand charge, the existing energy rate is higher than RPU’s “pure” energy costs. RPU’s energy rates are tiered to encourage conservation and equitably allocate costs incurred for higher demand: the more energy used by a Domestic customer, the higher the “per unit” rate ($/kWh).

It is important to not e that RPU’s Domestic —and most Commercial— Flat customers do not have a demand meter (which is capable of measur ing both energy and demand at the customer’s location). As previously indicated, RPU’s Commercial – Demand and Industrial TOU customers do have a demand meter and are billed on their monthly demand. Most electric ut ilities have not inst alled demand meters at residential customer locations because of the costs (demand meters have historically been more expensive than energy-only meters). However, RPU is in the process of installing meters at residential and commercial locations that are capable of reading demand. While this effort will likely be completed within the next five years, demand rates for residential and Commercial – Flat customers are not proposed for the Five-Year Rate Plan.

Table 5-2 includes a column for the COS that shifts the demand costs to the energy rate. This data is based on the COS analysis and recognizes that Domestic customers are not charged on a demand basis ($/kW).

As indicated, Domestic customers do incur these costs; however, they are recovered from the energy rate ($/kWh). Therefore, this table provides an “adjusted COS-based energy rate,” which includes appropriate demand costs and has been calculated to be approximately $0.1979/kWh (not adjusted for the tiered structure). Note that the customer costs for this COS-Energy column are still $16.69/month compared to the existing rate of $12.06/month.

The proposed Domestic rates discussed in Section 6 recognize the existing and COS rates as well as the specific rate proposal. It is important to understand that the proposed rates are designed to generate the Revenue Requirements for the customer class (as identified in Table 5 -2). These rate components are designed to recover the Revenue Requirement , as adjusted, for the entire customer class, not for each

ALLOCATED COST OF SERVICE

5-5
component. As mentioned, RPU does not intend to require demand rates for the Domestic customer class within this Five -Year Rate Plan; therefore, the demand -related costs must be recovered from a combination of the customer charge, Reliability Charge, and NAC, as well as the energy rate.

Domestic Cost Curve
Figure 5 -1 provides an illustration of a “cost curve” for RPU’s Domestic customer class. A cost curve represents the total costs ($) to serve a customer within a specific rate class over a range of monthly energy usage. The total costs are divided by the total mo nthly energy usage (in kWh) to calculate an “all-in” cost ($/kWh) to serve customers. A cost curve is a convenient tool to understand how unit costs (all-in $/kWh) for fixed cost industries (such as electric utilities) behave. If the customer is only using very small amounts of energy in a month, the all- in costs are high, because of the high fixed costs. However, if the customer is using large amounts of energy in a month, the fixed costs are spread over more energy, so the all-in costs are lower. This is why the cost curves for RPU (and generally speaking, any utility), have the characteristic shape of a high “tail” end on the left , then a rapidly decreasing shape that eventually becomes flatter towards the right end.

Cost curves are useful in rate design to allow a comparison of how rates and rate structures compare to a utility’s costs. For example, in Figure 5 -1, the Existing Rate curve is a representation of RPU’s existing Domestic rate (the Customer Service charge, the tiered energy charge, and the Reliability Charge ). This rate curve has been calculated over a series of usage levels using a “blended month” that represents the impacts of the existing summer and winter rate schedules. Because of the relatively low fixed charge and the relatively high-tiered energy charges for the existing rate, the “all- in” existing rate curve is lower in the front end and slowly gets higher in the tail end, which is the inverse of the cost curve. This supports increases in the fixed cost recovery rate mechanisms in the Domestic customer class.

Figure 5-1. Cost and Current Rate Curves for Domestic Rate

Section 5

5-6
Non-Domestic/Commercial Rate Review
Like the information provided for the Domestic customer class, the following provides a summary of the existing Non-Domestic/Commercial customer class rates compared to the COS analysis. Each subsection details the three major customer classes: Commercial – Flat, Commercial – Demand, and Industrial TOU.

Other rate classes are discussed at the end of this Section.

Commercial – Flat
The Commercial – Flat customer class represents businesses that are relatively low energy users and are not subject to a demand charge. Examples of Commercial – Flat customers may include a doctor’s office, a retail commercial store (within minimal load), or a small office building. The applicability for this rate class (which defines the characteristics of this customer class) includes any “commercial” energy use with a monthly maximum demand not exceeding 20 kW in any 2 of the preceding 12 months. If that threshold is exceeded, the customer is moved to the Commercial – Demand rate (note that for larger Commercial – Flat customers, RPU typically installs a demand meter to monitor usage in t he event that they may need to “move up” to the next rate class [Commercial – Demand]).

According to RPU’s tariff schedule, these customers are rece iving service under “Schedule A – General Service,” under the terms of the “Flat Rate. ” These include a customer c harge of $20.50 per month, a tiered Reliability C harge (tiered by energy), and a tiered energy charge that is non -seasonally differentiated. Table 5-3 provides a summary of RPU’s existing Commercial – Flat rates compared to the COS-based rates. As with the Domestic rates, the impact of state surcharges, including the Public Benefits Charge, is ignored because these changes presented costs that are beyond RPU’s control and are structures mandated by state regulations. Any new rates and rate structures will include these surcharges.

Table 5-3 also provides a summary of the rates derived from th e COS analysis. This includes a customer charge of $47.07/month, a demand rate of $24.47/kW, and an energy rate of $0.0863/kWh. The customer charge represents the costs o f metering, billing collections , customer service, and a mini mum system connection. The demand charge represents the costs associated with production, transmission, and the non-customer portion of the distribution system ( this includes the investment cost , as well as the fixed costs for operating and maintaining these systems). As with the Domestic rates, the costs associated with the projects identified for the Reliability Charge are included in the Deman d component of the COS analysis; however, these costs are collected from the Reliability Charge.

As indicated, the Commercial – Flat customers do not have a demand m eter (which is capable of measuring both energy and demand at the customer’s location). However, RPU intends to install meters at all commercial customer locations that are capable of reading demand. While this effort will likely begin during the next two years, demand rates for the Commercial – Flat customers are not proposed for the Five-Year Rate Plan.

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Table 5-3
Commercial – Flat Rates
(Existing and Cost of Service)
Rate Component Existing COS COS – Energy (1)
Customer ($/month) $20.50 $47.07 $47.07
Demand ($/kW -- $24.47
Network Access Charge
($/month)

Tier 1 (0–500 kWh) $3.35
Tier 2 (501–1,500 kWh) $9.50
Tier 3 (1,501–3,000 kWh) $16.89
Tier 4 (> 3,000 kWh) $40.63
Energy ($/kWh)
Tier 1 (0–15,000 kWh) $0.1486 $0.0863 $0.1760
Tier 2 (>15,000 kWh) $0.2270 $0.0863 $0.1760
Reliability Charge ($/month)
Tier 1 (0–500 kWh) $10.00 -- --
Tier 2 (501–1,500 kWh) $30.00 -- --
Tier 3 (>1,500 kWh) $60.00 -- --
(1) Assumes no Demand Charge and bundles demand-related costs within the Energy Charge.

Commercial – Flat Cost Curve
Like the Domestic rate class review, a cost curve comparison to the existing rate curve for the Commercial – Flat customer class is represented in Figure 5 -2. This shows the relationship between the COS and existing rate recovery (including the tiered Reliability Charge) for a wide range of monthly usage characteristics for this class. Commercial customers, including those within the Commercial – Flat customer class, tend to exhibit a wide range of monthly energy usage within the class, given that customers may include very small applications (such as timers for water sprinkler systems) as well as much larger monthly energy usage (such as a small restaurant or business office).

Section 5

5-8

Figure 5-2. Cost and Current Rate Curves for Commercial – Flat Rate Commercial – Demand
The Commercial – Demand customer class represents businesses that are relatively high energy users and are subject to a demand charge. Examples of Commercial – Demand customers may include a medium- sized restaurant, office building, or retail commercial store. The applicability for this rate class includes any “commercial” energy use with a billing demand equal or ex ceeding 20 kW, but less than 150 kW in any 2 of the preceding 12 months. If that threshold is exceeded, the customer is moved to the Industrial TOU rate.

According to RPU’s tariff schedule, these customers are recei ving service under “Schedule A – General Service,” under the terms of the Demand Rate. These terms include a flat R eliability Charge ($90 per month), a tiered demand charge (the first 15 kW of demand are charged a flat rate of $ 160.95, above which demand is charged $10. 73/kW), and a tiered energy charge that is no t seasonally differentiated.

The tiered demand charge is a common rate str ucture that essentially acts as a “minimum bill” for customers in this rate class and is mathematically determined by the product of the $10.73/kW times the minimum monthly 15 kW.

Table 5-4 provides a summary of RPU’s existing Commercial – Demand rates compared to the COS-based rates developed in the Study . This includes a customer charge of $77.46/month, a demand rate of $15.57/kW, and an energy rate of $0.0863/kWh. The customer charge represents the costs of metering, billing collections, customer service, and a minimum system connection. The demand rate represents the cost associated with production, transmission, and the non-customer portion of the distribution system (this includes the investment cost as well as the fixed costs for operating and maintaining these systems).

The costs associated with the projects identified for the Reliability Charge are included in the Demand component of the COS analysis.

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Table 5-4
Commercial – Demand Rates
(Existing and Cost of Service)
Rate Component Existing Cost of Service
Customer Charge ($/month) $22.10 $77.46
Network Access Charge ($/kW) $1.75
Demand Charge ($/kW)
Fixed – First 15 kW $160.95 $233.52
Excess – Per kW $10.73 $15.57
Energy Charge ($/kWh)
Tier 1 (0-30,000 kWh) $0.1242 $0.0863
Tier 2 (> 30,000 kWh) $0.1360 $0.0863
Reliability Charge ($/month) $90.00 --

Commercial – Demand Cost Curve
Because these customers are measured by their demand on the system ( i.e., the peak hour of energy usage during a month is their billed demand) , to effectively review cost and rate relationships, such customers are often compared across a range of load factors.

A load factor is the ratio of a customer’s energy (in kWh) to its peak demand (in kW) over a period of time.

The period of time may be a month (approximately 720 hours) or even a year (8,760 hours). The load factor is the energy (kWh) divided by the product of the demand (kW) times the number of hours (h); therefore, load factor is expressed as a percentage (as it is the ratio of kWh / (kWh)). Load factor is a measure of efficiency; the higher the load factor (closer to 100%), the more efficiently a customer is using its demand. An electric system can also have a load factor, which is a measure of how efficiently it is using its investments (in demand).

A simplified example is a customer with one single 60-watt light bulb (and no other electric load). If that customer leaves the light bulb on all day, for 24 hours a day, and 7 days a week, then the load factor is 100%. However, if that customer only leaves the light on for 12 hours a day, the load factor is 50%.

Generally, utilities will try to encourage customers to have a higher load factor, as that increases the load factor for the system and suggests that the utility is efficiently utilizing its investments.

A cost curve comparison to the existing rate curve for the Commercial – Demand customer cl ass is represented in Figure 5 -3. This shows the relationship be tween the COS and existing rate recovery (including the Reliability Charge and NAC ) for a wide range of monthly usage characteristics (or load factors) for this class.

Section 5

5-10

Figure 5-3. Cost and Current Rate Curves for Commercial – Demand Rate Figure 5 -3 assumes an “average” demand of approximately 52 kW per month (based on information provided by RPU). The relationship between the existing rates and the COS is applicable only to the average customer in this class. Larger customers (greater than 5 2 kW) and smaller customers (less than 52 kW) will have a different relationship to costs, although the shape of the cost curve will essentially remain the same.

Industrial TOU
The Industrial TOU customer class represents businesses that are large energy users and are subject to a time differentiated demand and energy charge. Examples of Industrial TOU customers may include a large restaurant, a large -sized office, or a large retail commercial store. The applicability for this rate class includes any customers whose service is designed for a 150 kW load or greater, or whose monthly demand level is equal to or exceeding 150 kW for any 2 of the preceding 12 months.

According t o RPU’s tariff schedule, these customers are receiving service under “Schedule TOU Large General and Industrial Service.” These terms include a customer c harge of $659.88 per month, a tiered Reliability Charge ( ranging from $350 - $2,650 per month, depend ing on monthly demand ), and a time differentiated demand and energy charge . The time periods include “ On-Peak,” “Mid-Peak,” and “Off - Peak.” On-Peak is defined as 12:00 p.m. to 6:00 p.m. summer weekdays, and 5:00 p.m. to 9:00 p.m. winter weekdays (excluding holidays). Mid -Peak is defined as 8:00 a.m. to 12:00 p.m . and 6:00 p.m. to 11:00 p.m. summer weekdays , and 8:00 a.m. to 5:00 p.m. winter weekdays (excluding holidays). Off-Peak is defined as all other hours (including holidays). The summer period is defined as June 1 through September 30, and the winter period is the re maining eight months of the year. Customers in this class have time - differentiated demand and energy meters that are able to log and provide 15-minute interval load data.

Table 5-5 provides a summary of RPU’s existing Industrial TOU rates compared to the COS-based rates.

This includes a customer charge of $127.89/month, a demand rate of $31.20/kW, and an energy rate of $0.0863 kWh. The customer charge represents the costs of metering, billing collections, customer service, and a minimum system connection. The demand rate represents the cost associated with production, transmission, and the non-customer portion of the distribution system (this includes the investment cost,

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as well as the fixed costs for operating and maintaining these systems). The costs associated with the projects identified for the Reliability Charge are included in the Demand component of the COS analysis.

Table 5-5
Industrial TOU Rates
(Existing and Cost of Service)
Rate Component Existing
Cost of
Service
Customer Charge $659.88 $127.89
NAC Charge ($/kW) $2.89
High Voltage NAC Charge ($/kW) $1.71
Demand Charge ($/kW) (1) $31.20
On-Peak $7.38
Mid-Peak $3.69
Off-Peak $1.85
Energy Charge ($/kWh) $0.0863
On-Peak $0.1154
Mid-Peak $0.0946
Off-Peak $0.0808
Reliability Charge ($/Month)
Tier 1 (<= 100 kW) $350
Tier 2 (> 100 - 150 kW) $750
Tier 3 (> 150 - 250 kW) $900
Tier 4 (> 250 - 500 kW) $1,100
Tier 5 (> 500 - 750 kW) $1,850
Tier 6 (> 750 kW) $2,650
(1) See text for discussion of time differentiated rates.

Industrial TOU – Cost Curve
A cost curve comparison to the existing rate curve for the Industrial TOU customer class is represented in Figure 5-4. This shows the relationship between the COS and existing rate recovery for a wide range of load factor characteristics for this class (see discussion in Commercial – Flat for explanation of load factor).

For the purposes of this graph , the cost and rate curves represent a “blended” month of the On-/Mid-/Off-Peak demand and energy rates (assuming a demand of 692 kW and varying levels of energy, represented by the range of load factors ). The existing Reliability Charge is included in the current rate .

It should be noted that the relationship between the existing rates and the COS is only applicable to a customer in this class with 692 kW demand per month. Larger customers (greater than 692 kW) and smaller customers (less than 692 kW) will have a different relationship to costs, although the shape of the cost curve will essentially remain the same.

Section 5

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Figure 5-4. Cost and Current Rate Curves for Industrial TOU Rate

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PROPOSED RATES
General
As previously noted, rate design is the end result of a COS study, in which the cost recovery mechanisms (rates and charges) for each customer class are established. Rates and charges are set for each customer class to collectively meet RPU’s average annual Revenue Requirement as well as to address specific policy goals and objectives as determined by RPU. For the purposes of this Stud y, the following rate design objectives were considered during the rate design process , which are inclusive of the rate making principles established by RPU and discussed in Section 1 of this Report.

RPU’s rates are designed to follow the subsequent principles:
 Achieve full recovery of costs.
 Equitably allocate costs across and within customer classes.  Encourage efficient use of water and electricity.
 Provide rate stability.
 Offer flexibility and options.
 Maintain rate competitiveness in the region.
 Be simple and easy to understand.

The recovery of the projected average annual Revenue Requirement is the primary objective of rate design. This means that the specific components of the rates for each customer class must be paired with their respective projected billing determinants (in the form of energy, demand, and number of customers) to collect sufficient revenues for RPU to maintain operations and fund its historic and planned capital investments.

RPU has expressed an interest in increasing the portion of fixed cost recovery in its rates. This is proposed due to the “misalignment” in its existing rate structures relative to its costs struct ures, as previously discussed. In an era of constant load growth, the recovery of fixed costs through variable (energy) rates made sense and was commonplace in the industry. However, RPU (and many other utilities in California and elsewhere) have experienced reductions in customer energy consumption and demand over the recent past due to poor economic conditions and increases in energy efficiency, conservation, and customer self -generation. As sales decrease but costs remain the same (or increase), the fixed cost recovery issue becomes critical for utilities. One partial solution is to increase the fixed components of existing rate structures, or introduce new fixed cost recovery rate structures, while adjusting the energy-only rates of customers.

A related objective is to consider and mitigate the overall bill impacts associated with low-use customers.

While increasing the fixed charges reduces the revenue risk for RPU as a whole, such increases tend to impact low-use customers more than high -use customers. This is because the energy -only portion of a low-use customer’s bill is a smaller percentage than that for a high-use customer. Therefore, on a total unit basis (total dollars for the bill divided by the total energy consumed, $/kWh), the relative increase in fixed charges represents a higher increase for low-use customers than high-use customers.

Section 6

6-2
Current Rate Classifications
As of the time of this Study, RPU has 16 rate schedules in effect. A summary of the current rate schedules and their customer classes is provided in Table 6-1.

Table 6-1
Current Rate Schedules and Customer Class
Rate Schedule Rate Code Customer Class
Domestic Service Schedule D Domestic (Residential): All Electric, Electric Water Heater, Multi-family
Domestic Service – Time of Use Schedule D-TOU Domestic Time of Use Domestic Service – Electric
Vehicle
Schedule EV Domestic Electric Vehicle Separately Metered General Service Schedule A – Flat Rate Commercial – Flat (Small Commercial, No Demand Charge):
includes Non-Metered Commercial, Schedule PW-1
General Service Schedule A – Demand Commercial – Demand (Medium Commercial) Large General & Industrial Schedule TOU Industrial TOU: includes customers moved from Contract Service and Schedules BR, ED, TED, and S (as applicable) Street Lighting – City Schedule LS-1 Department Financed Street Lights Street Lighting – Customer Schedule LS-2 Customer Financed Street Lights Outdoor Lighting – City Owned Schedule OL Department Financed Outdoor Lights Traffic Control Schedule TC Traffic Lights: includes City Owned and Cal-Trans (State Owned)
Agricultural Pumping Schedule PA Other Classes
Wind Machines Frost Protection Schedule PW-1 Commercial – Flat (Small Commercial, No Demand Charge) Economic Development Rate Schedule ED Contract Service
Net Energy Metering Schedule NEM Other Applicable Tariff (depending on Customer) Self-Generation Program Schedule Self-Gen Other Applicable Tariff (depending on Customer) Stand By Service Schedule S Contract Service

Existing and Proposed Fixed Cost Recovery
As with most utilities, RPU operational costs are primarily fixed and include debt service, labor, and investments in equipment. Variable costs are primarily related to fuel and purchase d power. However, RPU is typical of many electric utilities in that it currently recovers the majority of its fixed costs from the variable portion of its rate structures (the energy charge or cents per kWh). Figure 6-1 provides a summary of the fixed cost recovery (defined as revenue from customer charges ) compared to the variable co st recovery. As shown in Table 5 -2 for existing Domestic rates , t his non-alignment between costs, cost causation, and the revenue recovery results in customer energy charges that are higher than the COS and fixed charges that are lower than the COS . However, by not pricing the fixed rates at the costs incurred by RPU, the rates can send improper price signals to cus tomers and encourage inefficient use of the system resulting in poor load factor (as dis cussed in Section 5), which underutilizes RPU’s assets.

Additionally, higher energy rates can encourage customers to install distributed generation resources to

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avoid energy-only charges. This can result in higher costs for customers that do not install distributed generation resources.

Figure 6-1. Fixed and Variable Cost vs. Recovery
Reliability Charge
RPU has established a Reliability Charge for all of its customers. This charge is intended to fund specific generation and transmission improvements to the RPU system to increase the reliability of service. For the purposes of this Study, there are no changes proposed for the Reliability Charge.

Network Access Charge
The NAC is based on the demand-related costs associated with the distribution system and is a tiered fixed monthly charge for Domestic – and Commercial – Flat customer classes and a peak monthly dema nd charge ($/kW) for Commercial – Demand and Industrial TOU customer classes. The cost basis for the NAC varies by customer class, depending on its allocated share of the distribution demand costs as determined by the COS study.

Proposed Rate Design
This section of the Report provides a summary of th e proposed rate design for each year of the Five-Year Rate Plan for each major customer class. Included in this summary is an analysis of the proposed rates, including rate impacts for the selected customer types. Proposed a djustments to the “other” customer classes are discussed at the end of this Section, with specific rates included in Appendix A.

Domestic Rates and Bill Comparison Analysis
Table 6-2 provides a summary of the proposed rate adjustments for the Domestic rate class for each year of the Five-Year Rate Plan and a comparison of the rate components to the existing rate structure.

Section 6

6-4
Table 6-2
Domestic Rates
(Existing and Proposed)
Proposed Effective January 1
Rate Component Existing 2024 2025 2026 2027 2028
Customer Charge ($/month) $12.06 $12.90 $13.86 $14.93 $14.93 $15.09 Network Access Charge ($/month)
Tier 1 (or < = 12 kWh Daily Average) $2.49 $3.19 $3.89 $4.60 $5.24 $5.69 Tier 2 (>12 - 25 kWh Daily Average) $5.97 $7.44 $8.91 $10.38 $11.85 $12.65 Tier 3 (>25 kWh Daily Average) $13.16 $15.32 $17.48 $19.64 $21.80 $23.00 Energy Charge ($/kWh)
Tier 1 (0–750 S; 0–350 W) $0.1102 $0.1179 $0.1266 $0.1364 $0.1364 $0.1379 Tier 2 (751–1,500 S; 351–750 W) $0.1753 $0.1880 $0.2007 $0.2134 $0.2261 $0.2388 Tier 3 (>1,500 S; >750 W) $0.1988 $0.2127 $0.2285 $0.2462 $0.2462 $0.2488 Reliability Charge ($/month) (1)
Small Residence (<100 Amp) $10.00 $10.00 $10.00 $10.00 $10.00 $10.00 Medium Residence (101–200 Amp) $20.00 $20.00 $20.00 $20.00 $20.00 $20.00 Large Residence (201-400 Amp) $40.00 $40.00 $40.00 $40.00 $40.00 $40.00 Very Large Residence (>400 Amp) $60.00 $60.00 $60.00 $60.00 $60.00 $60.00 (1) No changes to the Reliability Charge are proposed.

The COS-based rates, provided in Table 5-2 for the Domestic class, indicate a customer charge of $ 16.69 per month. The proposed customer charge starts at $12.90 per month (January 1, 2024) and is increased over the Study period to $15.09 per month (2028). The Tier 1 NAC charge is proposed to increase to $3.19 per month (2024) and increase over the Study period to $5.69 per month (2028). Similarly, the Tier 2 NAC charge is proposed to increase to $7.44 per month (2024) and increase annually to $12.65 per month by 2028. The Tier 3 NAC charge is proposed to increase to $15.32 per month (2024) and increase annually to $23.00 by 2028.

The proposed energy rates in Table 6 -2 reflect cost recovery for the energy and demand-related costs).

The Tier 1 energy charge starts at $0.1179/kWh (January 1, 2024) and is increased over the Study period to $0.1379/kWh (2028). The Tier 2 energy charge starts at $0.1880/kWh and is increased to $0.2388/kWh by 2028. The Tier 3 energy charge starts at $0.2127/kWh (2024) and increases to $0.2488/kWh by 2028.

Distribution of Bill Impacts – Domestic Customers
Figure 6 -2 provides an analysis of the distribution of electricity consumption within RPU’s existing Domestic customer class, as determined from RPU Domestic customer billing data. This graph shows the average monthly kWh for FY 2022 and shows that approximately 9 0% of Domestic customers utilize between 250 to 1,450 kWh per month.

Figure 6-3 and Table 6-3 quantify the expected bill impacts to Domestic customers for various levels of representative consumption for the first year (FY 20 22) and over the Fiv e-Year period. An analysis was

PROPOSED RATES

6-5
conducted to determine the first year bill impacts to representative customers within the class for small, medium, and large users. Small use Domestic customers (0–600 kWh/month) should expect to see their average monthly bill increase from $ 3.05 to $6.44 (approximately 6.4% to 7.1%) during the first year of the rate plan . Medium use customers ( 601–1,200 kWh/month) should expect to see their avera ge monthly bill increase from $8.87 to $13.97 (approximately a 7.2% increase). Large use customers (1,201– 2,000 kWh/month) should expect to see bill increases in the range of $16.57 to $20.85 (approximately a

7.2% increase) during this time.

As discussed above, this bill impact will vary based on individual customer usage patterns . However, approximately 90% of RPU Domestic customers are expected to receive a typical first year bill increase of between 6.8% to 7.2%, and to see typical monthly bill increases of between $4.38 to $20.85 per account.

Over the Five- Year period, approximately 90% of RPU Domestic customers are expected to receive a typical bill increase of between 5.3% to 6.0%, and to see typical monthly bill increases of between $3.39 to $17.11 per account (note that this information is based on a combination of Figure 6-2 and Table 6-3).

Figure 6-2. Distribution of RPU Domestic Customers’ Monthly Usage (FY 2022)

Section 6

6-6

Figure 6-3. Average Domestic Bill Increase – First Year and Average for 5 Years Table 6-3
Domestic Bill Impacts
Year 1 and Year 5; Average Annual Percent
Avg. Monthly
kWh Usage
Avg. Monthly
Current Bill
Avg. Monthly
New Bill – Yr 1
Annual Increase
1 Yr. (%)
Avg. Monthly
New Bill – Yr. 5
Annual Increase
5 Yr. (%)
0-200 $47.46 $50.51 6.4% $59.22 5.0%
201-400 $64.08 $68.47 6.8% $81.01 5.3%
401-600 $90.57 $97.01 7.1% $116.32 5.7%
601-800 $122.74 $131.61 7.2% $159.65 6.0%
801-1,000 $156.77 $168.12 7.2% $204.96 6.1%
1,001-1,200 $193.37 $207.34 7.2% $252.65 6.1%
1,201-1,400 $230.27 $246.84 7.2% $299.82 6.0%
1,401-2,000 $291.61 $312.46 7.2% $377.16 5.9%
> 2,000 $685.32 $733.62 7.0% $869.87 5.4%

Fixed vs. Variable Cost Recovery
As previously indicated, RPU’s existing rate structures rely primarily on volumetric energy charges to recover both fixed and variable costs (although the customer charge and the Reliability Charge do provide fixed cost recovery in the form of fixed charges). One of RPU’s objectives for this Study was to increase the amount of fixed cost recovery from fixed charges. The proposed Domestic rates achieve this by increasing the tiered NAC. Figure 6-4 provides a summary of the analysis of the fixed versus variable cost recovery in the existing rates, as well as the proposed changes in rates over the Five -Year Rate Plan.

PROPOSED RATES

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Additionally, this figure includes a comparison to the COS analysis, which in dicates that RPU’s costs are approximately 62% fixed and 38% variable for the Domestic customer class.

Figure 6-4. Fixed vs. Variable Cost Recovery by Year – Domestic Non-Domestic/Commercial Rate and Bill Comparison Analysis The following provides a summary of the bill impact from the proposed rate changes for the non-domestic rate classes, including Commercial – Flat, Commercial – Demand, and Industrial TOU.

Commercial – Flat
Table 6-4 provides a summary of the proposed rate adjustments for the Commercial – Flat rate class for each year of the Five-Year Rate Plan and a comparison of the rate components to the existing rate levels.

The Commercial – Flat energy charge has two tiers based on 15,000 kWh per month energy usage; however, Tier 2 is set to encourage customers to either lower their energy usag e (and remain in the Commercial – Flat class) or switch to the next level of commercial service (Commercial – Demand).

Therefore, there are very few customers that utilize greater than 15,000 kWh per month on a consistent basis. If a Commercial – Flat customer utilized greater than 15,000 kWh, they would utilize greater than 20 kW of demand, and thus be moved to th e Commercial – Demand class. The Commercial – Demand class has a tiered energy rate based on 30,000 kWh.

Section 6

6-8
Table 6-4
Commercial – Flat
(Existing and Proposed)
Proposed Effective January 1
Rate Component Existing 2024 2025 2026 2027 2028
Customer Charge ($/month) $20.50 $21.12 $21.96 $22.95 $23.98 $24.94 Network Access Charge ($/month)
Tier 1 (0–500 kWh) $3.35 $3.45 $3.59 $3.75 $3.92 $4.08
Tier 2 (501–1,500 kWh) $9.50 $9.79 $10.18 $10.64 $11.12 $11.56 Tier 3 (1501–3000 kWh) $16.89 $17.40 $18.10 $18.91 $19.76 $20.55 Tier 4 (>3000 kWh) $40.63 $41.85 $43.52 $45.48 $47.53 $49.43 Energy Charge ($/kWh)
Tier 1 (0-15,000 kWh) $0.1486 $0.1531 $0.1592 $0.1664 $0.1739 $0.1809 Tier 2 (>15,000 kWh) $0.2270 $0.2338 $0.2432 $0.2541 $0.2655 $0.2761 Reliability Charge ($/month) (1)
Tier 1 (0-500 kWh) $10.00 $10.00 $10.00 $10.00 $10.00 $10.00 Tier 2 (501–1,500 kWh) $30.00 $30.00 $30.00 $30.00 $30.00 $30.00 Tier 3 (>1,500 kWh) $60.00 $60.00 $60.00 $60.00 $60.00 $60.00 (1) No changes to the Reliability Charge for the Commercial – Flat class are proposed.

Rate changes proposed for Commercial – Flat include an increase in the Customer Charge, increases in the tiered NAC, and increases in the energy charges over the Rate Plan period. The Tier 1 NAC is for customers ranging from 0 to 500 kWh and is proposed to increase to $3.45 per month (January 1, 2024) and increase over the Study period to $4.08 per month (2028). The Tier 4 NAC is for customers over 3,000 kWh per month and proposed to increase to $41.85 per month (2024) and is increased to $ 49.43 per month by 2028.

The COS-based rates for the Commercial – Flat class, provided in Table 5-3, indicate a Test Year customer charge of $ 47.07 per month. The cus tomer charge is proposed to increase from $20.50/month to $24.94/month.

The COS-Energy rate (Table 5 -3) suggests a “demand -adjusted” energy rate of $0. 1760/kWh; however, that rate has not been adjusted for the tiers and does not reflect the revenue received from Commercial – Flat customers from the Reliability Charge. The energy rates in Table 6 -4 reflect the cost recovery for the demand -related costs and the recognition of the revenue received from the Reliability Charge. As indicated, the tiered rate structure associated with this class has been maintained from the existing rate structure and is designed to equitably recover costs from customers who may move between this rate class and the Commercial – Demand rate class.

Distribution of Bill Impacts – Commercial – Flat Customers Figure 6 -5 provides an analysis of the distribution of electricity consumption within RPU’s existing Commercial – Flat customer class, as determined from RPU customer billing data. The energy usage in this customer class is highly diverse (i.e., the data distribution is strongly right skewed). This graph shows

PROPOSED RATES

6-9
the average monthly kWh for FY 2022 and shows that approximately 90% of Commercial – Flat customers utilize between 250 to 5,250 kWh per month.

Figure 6-6 and Table 6 -5 quantify the expected bill impacts to Commercial – Flat customers for various levels of representative consumption for the first year (FY 2024) and over the Five-Year period. An analysis was conducted to determine the first year bill impacts to representative customers within the class for small, medium, and large users . Small customers, defined as those using between 0 and 500 kWh per month, would be expected to see an average increase of approxim ately $1.30 on their mo nthly bill, or approximately 2.4% increase in year one (FY 2024). Medium sized users, defined as those using between 1,500 and 5,000 kWh per month, would be expected to see an average year one monthly bill increase of between approximately $6.60 and $11.43/month, or between 2.5% and 2.7% compared to 2023 rates.

Large users, defined as those using greater than 10,000 kWh per month, would be expected to see an average monthly bill increase of approximately $45.90, or 3.1% compared to 2024 rates.

The impact of the proposed rate changes to these customers will vary based on individual customer usage patterns. However, approximately 90 % of RPU Commercial – Flat customers are expected to receive a typical first year bill change of 2.4% to 2.7% and to see typical monthly bill increases of $1.30 to $11.43 per account. Over the Five- Year period, approximately 90% of RPU Commercial – Flat customers are expected to receive a typical bill increase of 3.1% and to see a typical monthly bill increase of between $1.65 to $12.95 per account (note that this information is based on a combination of Figure 6-5 and Table 6-5).

Figure 6-5. Distribution of RPU Commercial – Flat Customers’ Monthly Usage (FY 2022)

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6-10

Figure 6-6. Average Commercial – Flat Bill Increase – First Year and Average for 5 Years Table 6-5
Commercial – Flat Bill Impacts
Year 1 and Year 5, Average Annual Percent
Avg. Monthly
kWh Usage
Avg. Monthly
Current Bill
Avg. Monthly
New Bill – Yr. 1
Annual
Increase 1 Yr. %)
Avg. Monthly
New Bill – Yr. 5
Annual
Increase
5 Yr. (%)
0–500 $53.27 $54.57 2.4% $61.54 3.1%
501–1,500 $133.27 $136.51 2.4% $152.36 2.9%
1,501–3,000 $263.15 $269.75 2.5% $300.88 2.9%
3,001–5,000 $420.68 $432.11 2.7% $485.43 3.1%
5,001–10,000 $810.33 $834.18 2.9% $942.41 3.3%
> 10,000 $1,501.02 $1,546.92 3.1% $1,752.17 3.3%

Fixed vs. Variable Cost Recovery
Figure 6 -7 provides a summary of the fixed versus variable cost recovery in th e existing rates for Commercial – Flat customers as well as the proposed rate changes over the Five-Year Rate Plan. Figure 6-7 includes a comparison to the COS analysis, which indicates that for the Commercial – Flat class, RPU’s costs are approximately 57% fixed and 43% variable.

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Figure 6-7. Fixed vs. Variable Cost Recovery by Year – Commercial – Flat Commercial – Demand
Table 6-6 provides a summary of the proposed rate adjustments for the Commercial – Demand rate class for each year of the Five-Year Rate Plan and a comparison of the rate components to the existing rate structure. Because Commercial-Demand is currently over collecting relative to its COS, no changes in rate levels are proposed for this class for the period of the Rate Plan.

Table 6-6
Commercial – Demand
(Existing and Proposed Rates)
Rate Component Existing
Proposed Effective January 1
2024 2025 2026 2027 2028
Customer Charge ($/month) $22.10 $22.10 $22.10 $22.10 $22.10 $22.10 Network Access Charge ($/kW) $1.75 $1.75 $1.75 $1.75 $1.75 $1.75 Energy Charge
Tier 1 (0–30,000 kWh) $0.1242 $0.1242 $0.1242 $0.1242 $0.1242 $0.1242 Tier 2 (> 30,000 kWh) $0.1360 $0.1360 $0.1360 $0.1360 $0.1360 $0.1360 Demand Charge ($/kW)
Fixed Charge (First 15 kW) $160.95 $160.95 $160.95 $160.95 $160.95 $160.95 All Excess kW ($/kW) $10.73 $10.73 $10.73 $10.73 $10.73 $10.73 Reliability Charge ($/month) (1) $90.00 $90.00 $90.00 $90.00 $90.00 $90.00 (1) No changes to the Reliability Charge are proposed.

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Fixed vs. Variable Cost Recovery
Figure 6 -8 provides a summary of the fixed versus variable cost recovery in the existing rates for the Commercial – Demand customer class over the Five-Year Rate Plan. This figure includes a comparison to the COS analysis, which indicates that RPU’s costs for the Commercial – Demand class are approximately 49% fixed and 51% variable. The change in fixed and variable cost recovery during the Rate Plan period is due to changes in estimated load from the class.

Figure 6-8. Fixed vs. Variable Cost Recovery by Year – Commercial – Demand Industrial – TOU
Table 6-7 provides a summary of the proposed rate adjustments for the Industrial TOU rate class for each year of the Five-Year Rate Plan and a comparison of the rate components to the existing rate structure.

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Table 6-7
Industrial TOU
(Existing and Proposed Rates)
Rate Component Existing
Proposed Effective January 1
2024 2025 2026 2027 2028
Customer Charge ($/month) $659.88 $686.28 $713.73 $742.28 $760.84 $776.06 Network Access Charge ($/kW) Low Voltage $2.89 $3.87 $4.85 $5.83 $6.81 $7.77 Network Access Charge ($/kW) High Voltage $1.71 $2.24 $3.22 $4.20 $5.18 $6.14 Energy Charge ($/kWh)
On-Peak $0.1154 $0.1197 $0.1245 $0.1295 $0.1314 $0.1340 Mid-Peak $0.0946 $0.0981 $0.1020 $0.1061 $0.1077 $0.1099 Off-Peak $0.0808 $0.0838 $0.0872 $0.0907 $0.0921 $0.0939 Demand Charge ($/kW)
On-Peak $7.38 $7.66 $7.97 $8.29 $8.41 $8.58
Mid-Peak $3.69 $3.83 $3.98 $4.14 $4.20 $4.28
Off-Peak $1.85 $1.92 $2.00 $2.08 $2.11 $2.15
Reliability Charge ($/month) (1)
<= 100 kW $350 $350 $350 $350 $350 $350
101-150 kW $750 $750 $750 $750 $750 $750
151-250 kW $900 $900 $900 $900 $900 $900
251-500 kW $1,100 $1,100 $1,100 $1,100 $1,100 $1,100
501-750 kW $1,850 $1,850 $1,850 $1,850 $1,850 $1,850
> 750 kW $2,650 $2,650 $2,650 $2,650 $2,650 $2,650
(1) No changes to the Reliability Charge are proposed.

The COS-based rates for Industrial TOU class, provided in Table 5-5, indicate a Test Year customer charge of $27.89 per month. The customer charge is proposed to increase to $686.28 per month starting January 1, 2024, and is increased over the Study period to $721.07 per month (January 1, 2028). The NAC charge (for standard voltage service) is proposed to increase to $3.87/kW (2024) and is increased over the Study period to $ 7.77/kW (202 8). The On-Peak Energy charge is proposed to be $0.11 97/kWh in 2024, increasing to $0.1340/kWh in 2028.

The COS-based rates indicate a demand charge of $31.20/kW for the Industrial TOU class. The proposed changes to the On -Peak demand rates start on January 1, 2024 at $7.66/kW and increase to $ 8.58/kW (2028). The relationship between the On-Peak, Mid-Peak, and Off-Peak prices maintains the existing rate structure differentials. RPU also recogn izes that many customers in this class have shifted resources to respond to the existing rate structures (i.e., they have shifted load to the Mid - and Off -Peak times) .

Therefore, RPU has determined to adjust the ra te component relationships in a manner that minimizes rate impacts to customers in this class. It should be noted that the COS-based demand rate includes fixed costs that are currently recovered from customers from the Reliability Charge.

The COS for this class indicates an energy rate of $0.0 863/kWh. As with the proposed demand charges, the difference between the On-Peak, Mid-Peak, and Off-Peak proposed energy rates reflects the existing

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6-14
rate structure differentials. The energy rates proposed in Table 6-7 reflect the cost recovery for the demand-related costs not recovered through the combination of the proposed changes to the customer charges, NAC charges, demand charges, or the Reliability Charge. No change is proposed for the Reliability Charge for this class.

Distribution of Bill Impacts – Industrial TOU Customers Figure 6 -9 provides an analysis of the distribution of electricity consumption within RPU’s existing Industrial TOU customer class, as determined from RPU customer billing data. This graph shows the average monthly kWh for FY 2022 and shows that approximately 90% of Industrial TOU customers utilize between 13,000 kWh and 263,000 kWh per month (between 13 and 263 MWh, as 1,000 kWh equals 1 MWh).

Expected bill impacts for Industrial TOU customers are quantified in Figure 6-10 and Table 6-8 for various levels of representative consumption for the first year (FY 2024) and over the Five-Year period. An analysis was conducted to determine the first-year bill impacts to representative customers within the class for small, medium, and large users. Small customers, defined as those using between 0 and 100,000 kWh per month, would be expected to see an avera ge increase between $341 and $731 on their monthly bill, or approximately between 6.1% and 6.2% increase in year one (FY 20 24). Medium sized users, defined as those using between 100,000 and 250,000 kWh per month, woul d be expected to see an average year one monthly bill increase of between $1,137 and $2,872, or approximately 6.0% compared to 2023 rates.

Large users, defined as those using greater than 500,000 kWh, would be expected to see a year one average monthly bill increase of approximately $8,272 or 5.9% compared to 2023 rates.

As with the other classes, the proposed rate impact on the Industrial TOU customers’ bill will vary based on individual customer usage patterns. However, approximately 90% of RPU Industrial TOU customers are expected to receive an average first year bill change of between 6.0% to 6.2% and to see typical monthly bill changes of $341 to $1,694 per account. Over the Five- Year period, approximately 90% of RPU’s Industrial TOU customers are expected to receive a typical monthly bill increase of between 5.9% to 6.6% and to see a typical monthly bill change of between $363 to $1,753 per account (note that this information is based on a combination of Figure 6-9 and Table 6-8).

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Figure 6-9. Distribution of RPU Industrial TOU Customers’ Monthly Energy Usage (MWh = 1,000 kWh, FY 2022)

Figure 6-10. Average Commercial Demand Bill Increase – First Year and Average for 5 Years (MWh = 1,000 kWh)

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6-16
Table 6-8
Industrial TOU Class Bill Impacts
Year 1 and Year 5; Average Annual Percent
Avg. Monthly
kWh Usage
Avg.

Monthly
Load Factor
Avg. Monthly
Current Bill
Avg. Monthly
Bill Yr. 1
Annual
Increase
1 Yr. (%)
Avg. Monthly
New Bill
Yr. 5
Annual
Increase 5
Yr. (%)
0–50,000 23% $5,474.44 $5,815.55 6.2% $7,290.53 6.6% 50,001–100,000 37% $11,988.59 $12,719.54 6.1% $15,812.75 6.4% 100,001–150,000 40% $18,844.41 $19,981.00 6.0% $24,753.71 6.3% 150,001–250,000 48% $28,353.78 $30,047.40 6.0% $37,121.67 6.2% 250,001–500,000 55% $49,648.32 $52,520.48 5.8% $64,383.77 5.9% > 500,000 59% $140,065.25 $148,337.58 5.9% $182,444.60 6.1%

Fixed vs. Variable Cost Recovery
Figure 6-11 provides a summary of the fixed versus variable cost recovery in the existing rates for the Industrial – TOU customer class over the Five -Year Rate Plan. Figure 6-11 includes a comparison to the COS analysis, which in dicates that for the Industrial TOU class, RPU’s costs are approximately 4 6% fixed and 54% variable.

Figure 6-11. Fixed vs Variable Cost Recovery by Year – Industrial TOU Revenue Impact Analysis
Table 6-9 provides a summary of the overall revenue contributions by customer class under the proposed rates, as well as the total system revenue projected to be collected in each year of the Five-Year Rate Plan.

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Table 6-9
Projected Revenue by Class ($000)
Customer Class FY 2024 FY 2025 FY 2026 FY 2027 FY 2028
Domestic $137,004 $147,188 $158,517 $167,543 $172,937
Commercial – Flat $51,761 $53,752 $56,335 $59,237 $62,364 Commercial – Demand $33,973 $34,207 $34,536 $34,897 $35,371 Industrial TOU $139,876 $149,511 $160,640 $170,801 $180,416 Other (1) $5,042 $5,243 $5,451 $5,668 $5,893
Total (2) $367,657 $389,901 $415,478 $438,146 $456,981 (1) Other Classes include street lights and agricultural load. (2) Numbers may not add due to rounding.

Table 6 -9 suggests that the revenues from the Domestic rate class are projected to increase from approximately $1 37 million in FY 2024 to $ 172.9 million in FY 202 8. T he Commercial – Flat, Commercial – Demand, Industrial TOU customer, and Other Rates classes will also see an increase in the total revenue generated by the class. As noted previously, there are no proposed rate changes for the Commercial-Demand class, however, the projected load for that class is expected to increase during the Rate Plan period.

Other Rate Changes
There are several other rate changes that RPU is proposing as part of this Five-Year Rate Plan. A discussion of each of these “other” customer and rate classes, and the changes proposed, is provided below.

Street Lighting
RPU is finalizing its process to fully replace its existing inventory of City-owned street lights with LED lamps.

This effort will result in lower energy costs but will require a significant capital investment. The capital investment for the replacement is being funded from non-retail rate revenues. Approximately 26,000 LED lamps currently under the Schedule LS-1 (Str eet Lighting Service – Department Financed) have been installed and the remainder of approximately 5,000 lamps are expected to be installed before the end of the Five-Year Rate Plan. The proposed LED lamps are to be charged on a per lamp/per month basis and are differentiated by both the fixture’s nameplate wattage and a photocell setting. Each LED lamp can be set to a different photocell setting which provides varying levels of light dimming based on the time of day. There are four photocell options for the LED Lamps in the LS -1 schedule. The lamp dimming varies before and after midnight. Table 6-10 below describes the dimming provided by each photocell.

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6-18
Table 6-10
LED Lamp Photocell Settings
Dimming Percentage
Photocell Setting
Before
Midnight
After
Midnight
PC-1 100% 100%
PC-2 50% 50%
PC-3 70% 50%
PC-4 100% 50%

This type of street light rate structure is common for municipal electric utilities. The proposed rates are sufficient to recover the costs associated with street lighting, capital costs (hardware), O&M-related costs, and the cost of electricity. Photocell settings that employ dimming have slightly lower rates to reflect the reduction in energy costs from the lamp dimming. The proposed rates for non -LED LS-1 Streetlights are listed in Table 6-11 below and the proposed rates for LED lamps are listed in Table 6-12 below, beginning on January 1, 2024. The nameplate wattage of the lamp and the photocell setting are used to determine a lamp’s specific rate.

Table 6-11
Existing Schedule LS-1 (Per Lamp,
Per Month) (1)
Light Type
Existing
Rate
Incandescent
1,000 Lumens $6.82
2,500 Lumens $10.12
4,000 Lumens $13.44
Mercury Vapor
3,500 Lumens $10.77
7,000 Lumens $12.76
10,000 Lumens $15.68
Sodium Vapor
5,800 Lumens $10.51
9,500 Lumens $11.85
16,000 Lumens $13.88
22,000 Lumens $15.75
25,000 Lumens $17.39
40,000 Lumens $21.84
(1) LS-1 Rate Schedule is Department Financed Lights.

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Table 6-12
LED Additions to Schedule LS-1 (Energy and Maintenance $/month) (1) LED Fixture Wattage 2024 2025 2026 2027 2028
0-75 Watts
PC-1 $13.07 $13.58 $14.11 $14.66 $15.03
PC-2 $12.29 $12.77 $13.26 $13.78 $14.13
PC-3 $12.43 $12.92 $13.42 $13.94 $14.29
PC-4 $12.65 $13.14 $13.65 $14.18 $14.54
75-125 Watts
PC-1 $14.78 $15.12 $15.47 $15.82 $16.11
PC-2 $13.54 $13.86 $14.17 $14.50 $14.76
PC-3 $13.77 $14.09 $14.41 $14.74 $15.01
PC-4 $14.35 $14.68 $15.01 $15.36 $15.38
125-175 Watts
PC-1 $18.24 $18.33 $18.43 $18.52 $18.61
PC-2 $15.83 $15.91 $15.99 $16.07 $16.14
PC-3 $16.27 $16.35 $16.43 $16.52 $16.60
PC-4 $16.94 $17.02 $17.11 $17.19 $17.27
175-260 Watts
PC-1 $19.10 $19.46 $19.83 $20.21 $20.52
PC-2 $16.05 $16.35 $16.66 $16.98 $17.24
PC-3 $16.61 $16.92 $17.24 $17.57 $17.84
PC-4 $17.45 $17.78 $18.12 $18.46 $18.75
(1) LS-1 Rate Schedule is Department Financed Lights. These rates are proposed to be charged monthly per LED light by watt and photocell rating. Rate changes are effective on January 1 of each year.

Electric Vehicle Charging Rates
Proposed EV Separately Metered Charger Rate
As part of this Study, RPU requested the development of a separately metered EV charger rate. Currently, there are several EV charging stations available within the City; some are dedicated to specific charging only (due to proprietary charging equipment) and some non-specific chargers are owned and operated by third-party entities. However, all current EV chargers in the City are located as part of a series of several charges situated behind one meter. For the purposes of this Study, RPU sought an EV charger rate that would be applied to a single, standalone charging facility with its own dedicated metering technology.

For this assignment, NewGen reviewed charger data provided by RPU for two specific sample charger locations. Analysis of the hourly load at these two facilities suggests that on average, a single EV charger could set a peak demand during the year of approximately 51 kW. At that level of demand, the charging facility would be within RPU’s Commercial- Demand rate class. A summary of the estimate average kWh

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per month per charger, average peak demand and average load factor for these two charging locations is provided in in Table 6-13:

Table 6-13
Per Charger Energy, Demand, and Load Factor
Supercharger
Location
Average kWh per
Month per Charger
Peak Demand
(kW/charger)
Average Monthly Load
Factor
Location 1 1,409 29.5 7.4%
Location 2 4,992 75.0 9.9%
Weighted Average 3,649 50.9 9.8%

One challenge in developing EV charging rate is assigning the demand related costs to all users of the facility. For customers with a dedicated charger behind the meter, this cost can be assigned to that user.

However, for a charger with multiple users, the demand cost must be spread across the estimated energy usage for the period (month). This is consistent with several approaches to EV charging rates in the City, as well as those adopted elsewhere in California and in other jurisdictions.

To develop the EV charging rate, the average usage characteristics from Table 6-13 were applied to the current Commercial – Demand rate to calculate an estimated total cost for a single charging facility within a month. The total cost was divided by the average kWh/month to determine an all -energy rate for a stand-alone charger. The development of this proposed Separately Metered EV Charging rate is provided in Table 6-14.

Table 6-14
Separately Metered EV Charging Rate ($/kWh)
Rate Component Rate
Usage Per
Month Monthly Charge
Customer Charge ($/Month) $22.10 1 $22.10
Reliability Charge ($/Month) $90.00 1 $90.00
Network Access Charge
($/kW)
$1.75 50.93 $89.13
Demand Charge ($/kW)
Fixed Charge (First 15 kW) $160.95 1 $160.95
All Excess kW ($/kW) $10.73 35.93 $385.52
Energy

Tier 1 (0–30,000 kWh) $0.1242 3,649 $453.26
Tier 2 (> 30,000 kWh) $0.1360 0 $ -
Total: $1,200.96
$/kWh: $0.3291

As indicated above, applying the average EV charger usage characteristics to RPU’s existing Commercial Demand results in a total monthly charge of approximately $1,201. Dividing the total monthly charge by the total estimated monthly usage of 3,649 kWh results in an average energy only rate of $0.3291/kWh.

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Therefore, for this Study, the EV Charging rate is proposed to be $0.3291/kWh. Because the Commercial Demand rate is not proposed to change during the period of this Study, th is EV Charger rate is proposed to remain the same as well. It is recommended that RPU review the usage characteristics of the current and future EV charging facilities within the City to ensure that average usage is consistent with the assumptions developed herein.

Domestic TOU Rates
As a result of the previous rate study, RPU introduce d optional Domestic TOU rate s for customers interested in shifting load, including EV owners that intend to charge their electric vehicles at their residences. There are two TOU rate offerings available to domestic RPU customers; one is a tiered TOU (DTOU) and the other is a TOU for EV only (Schedule EV). The DTOU rate does not require an additional meter, and all other applicable rate charges (e.g., customer charge, NAC charge, public benefits fee, taxes, etc.) would apply. This rate is shown in Table 6-15.

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Table 6-15
Domestic Time of Use Schedule DTOU
Rate Component Existing
Proposed Effective January 1
2024 2025 2026 2027 2028
Customer Charge ($/Month) $12.06 $12.90 $13.86 $14.93 $14.93 $15.09 Network Access Charge

Tier 1 (< or = 12 Daily Avg kWh Usage) $2.49 $3.19 $3.89 $4.60 $5.24 $5.69 Tier 2 (< 12 ‐ 25 Daily Avg kWh Usage) $5.97 $7.44 $8.91 $10.38 $11.85 $12.65 Tier 3 (>25 Daily Avg kWh Usage) $13.16 $15.32 $17.48 $19.64 $21.80 $23.00 Energy Charge (1)

Summer On-Peak

0 - 330 kWh $0.1860 $0.1990 $0.2138 $0.2304 $0.2304 $0.2329 > 330 kWh $0.2976 $0.3184 $0.3421 $0.3686 $0.3686 $0.3726 Summer Mid-Peak

0 - 550 kWh $0.1209 $0.1294 $0.1390 $0.1497 $0.1498 $0.1514 > 550 kWh $0.1934 $0.2069 $0.2223 $0.2395 $0.2396 $0.2421 Summer Off-Peak

0 - 220 kWh $0.1012 $0.1083 $0.1163 $0.1253 $0.1254 $0.1267 > 220 kWh $0.1488 $0.1083 $0.1163 $0.1253 $0.1254 $0.1267 Winter On-Peak

0 - 135 kWh $0.1395 $0.1493 $0.1603 $0.1728 $0.1728 $0.1747 > 135 kWh $0.2232 $0.2388 $0.2565 $0.2764 $0.2765 $0.2794 Winter Mid-Peak

0 - 250 kWh $0.1116 $0.1194 $0.1283 $0.1382 $0.1382 $0.1397 > 250 kWh $0.1786 $0.1911 $0.2053 $0.2212 $0.2212 $0.2236 Winter Off-Peak

0 - 115 kWh $0.1012 $0.1083 $0.1163 $0.1253 $0.1254 $0.1267 > 115 kWh $0.1488 $0.1083 $0.1163 $0.1253 $0.1254 $0.1267 Reliability Charge (2)

Small Residence (<100 Amp) $10.00 $10.00 $10.00 $10.00 $10.00 $10.00 Medium Residence (101–200 Amp) $20.00 $20.00 $20.00 $20.00 $20.00 $20.00 Large Residence (201-400 Amp) $40.00 $40.00 $40.00 $40.00 $40.00 $40.00 Very Large Residence (>400 Amp) $60.00 $60.00 $60.00 $60.00 $60.00 $60.00 (1) Summer season of June 1 to September 30 Energy Charge and Network Access Charge. On-Peak hours are 2:00 p.m. to 7:00 p.m. during summer months and 4:00 p.m. to 9:00 p.m. during winter months. Mid-Peak hours are 6:00 a.m. to 2:00 p.m. and 7:00 p.m. to 11:00 p.m. during summer months, and 6:00 a.m. to 4:00 p.m. and 9:00 p.m. to 11:00 p.m. during winter months. Off-Peak hours are 11:00 p.m. to 6:00 a.m. throughout the year. (2) No change to the Reliability Charge is proposed for this class.

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The Domestic EV Separately Metered (Schedule EV) rate is applicable only to domestic customers with an EV and a separately metered dedicated EV charger. This rate includes a customer charge, but does not have a separate reliability charge or NAC. Upon election to receive service under the Schedule EV rate, the customer’s standard domestic service will receive the Tier 3 NAC charge. The EV rate is not tiered by usage but do es include a TOU component for O n-/Mid-Peak period energy usage. Table 6 -16 provides the current and proposed EV rates.

Table 6-16
Domestic Electric Vehicle Separately Metered – Schedule EV Rate Component Existing
Proposed Effective January 1
2024 2025 2026 2027 2028
Customer Charge ($/Month) $12.06 $12.90 $13.86 $14.93 $14.93 $15.09 Energy Charge ($/kWh) (1)

Summer – On-Peak $0.2753 $0.2899 $0.3054 $0.3216 $0.3387 $0.3567 Summer – Mid-Peak $0.1572 $0.1656 $0.1744 $0.1836 $0.1934 $0.2037 Summer – Off-Peak $0.1102 $0.1161 $0.1222 $0.1287 $0.1356 $0.1428 Winter – On-Peak $0.2065 $0.2175 $0.2290 $0.2412 $0.2541 $0.2676 Winter – Mid-Peak $0.1451 $0.1528 $0.1609 $0.1695 $0.1785 $0.1880 Winter – Off-Peak $0.1102 $0.1161 $0.1222 $0.1287 $0.1356 $0.1428 (1) Summer season of June 1 to September 30 Energy Charge. On-Peak hours are 2:00 p.m. to 7:00 p.m. during summer months and 4:00 p.m. to 9:00 p.m. during winter months. Mid-Peak hours are 6:00 a.m. to 2:00 p.m. and 7:00 p.m. to 11:00 p.m. during summer months, and 6:00 a.m. to 4:00 p.m. and 9:00 p.m. to 11:00 p.m. during winter months. Off-Peak hours are 11:00 p.m. to 6:00 a.m. throughout the year.

Other Existing Rates Schedules
RPU provides a variety of services to other rate classes that are collectively referred to as “Other Rates” for this Study. These rates include “classes within classes,” such as Domestic TOU Tiered (DTOU Tiered), as well as various lighting classes, renewable type classes, agricultural electric use classes , and stand-by service, as well as “rate programs” offered by RPU. Each rate was reviewed relative to either its own COS or a comparison to similar RPU class costs (as determined by this Study). Generally spe aking, these rate classes have less customers, lower loads, or some other unique applicability relative to the other “major” classes described herein. Because of these characteristics, it is a challenge to apply system wide cost allocation factors to these classes. Therefore, many of the rates for these classes and programs are subject to the annual system average rate of 5.3% per year increase. A description of each rate class and program, as well as proposed rate/rate structure changes, as appropriate, is discussed below. Each proposed rate schedule is provided in Appendix A to this Report.

Schedule ED – Economic Development Rates
Many utilities, including RPU, have developed Economic Development (ED) Rates. RPU’s ED Rate is tied to the OAT and requires a certain level of investment for specified industries (defined by government codes). The ED Rate provides a gradual increase on a percentage basis over a three-year period to the full implementation of the OAT. The increased load benefits all customers as RPU’s fixed costs are allocated to more units. No changes are proposed to this rate or rate structure as a result of this Study.

Section 6

6-24
Schedule Feed-In Tariff
RPU provides a Feed-in Tariff (FIT) rate for customer generators of no more than 3 MW who wish to sell output from renewable generation to RPU. The FIT is defined by a tariff and is adjusted annually to reflect RPU’s average cost of all renewable energy purchased by RPU. There are currently no customers that are provided service under the RPU’s FIT. No changes are proposed to the FIT tariff as a result of this Study.

Schedule LS-2
RPU provides two types of services to customers who install and own their own street lighting systems.

The first service is an “Energy Only” service wherein the customer is responsible for the maintenance and operations of their systems and RPU provides the necessary energy. The second type of services is “Energy and Maintenance” wherein RPU provides the energy and maint enance services on the customer-owned lighting facilities. Both services are charged an annual fee on a per light per lumen basis (there are different rates for Incandescent, Mercury Vapor, and Sodium Vapor type lights, as well as varying lumens within each light type). The existing differential between the Energy Only and Energy and Maintenance services is based on costs and averages approximately $20.59 per month. Proposed changes to this rate class include an annual increase of 5.3 % per year for existing lights. See Appendix A Tables A-1 and A-2 for revised Energy Only and Energy and Maintenance rates for non-LED.

Schedule OL
Like Schedule LS-1, RPU offers services for outdoor lighting whereby the equipment is owned, installed, and maintained by RPU. The rates for this tariff are applicable to two specific lumen ratings for two types of lighting fixtures (Merc ury Vapor and Sodium Vapor). RPU proposes to increase the existing rate structure at the annual rate of 5.3%. Proposed changes for these rates is provided in Appendix A Table A-

3. Schedule PA
RPU offers a specific rate for water pumping services for general agricultural use, referred to as “Power – Agricultural Pumping.” This rate is based on an annual service charge that varies by the horsepower rating of the pump, as well as a flat energy rate and a Reliability Charge. Proposed changes to this rate include an increase in each energy rate by approximately 5.3% per year, which results in a total rate class revenue increase on a percentage basis similar to the increase required for the system over the Study period (the Revenue Requirement). Additionally, customers in this class will be subject to the proposed changes in the Commercial – Flat tiered NAC. Proposed rate tariff additions are provided in Appendix A Table A-4.

Schedule PW 1
RPU offers a specific rate for agricultural customers that utilize wind machines for frost protection of their crops. This rate includes a customer charge and a tiered energy change (based on a tier of 15,000 kWh).

Given the seasonality of this specific load, the meters on this tariff are read annually. Pro posed changes to this tariff include adjustments to the NAC and energy rate (based on the proposed Commercial – Flat NAC and energy rate changes). Appendix A Table A-5 includes the proposed rate changes for this tariff.

Schedule S
RPU offers Stand -by Ser vice to non -residential customers that provide all or part of their load with generation located on the customer’s premises. The stand-by service includes a demand charge based on the size of the customer’s contract demand that is tiered at 50 kV . The standby charge is designed to

PROPOSED RATES

6-25
recover a portion of RPU’s fixed costs (investment) that stands ready to serve the customer’s load in the event their on-site generation fails or is offline due to scheduled maintenance.

The customer is also responsible for customer, energy, demand, NAC, and reliability charges as defined in their OAT. Proposed changes to this tariff include adjustments to the Stand -by Charge based on adjustments to the On -Peak demand rate proposed for the Industrial TOU tariff. Appendix A Ta ble A-6 includes the proposed rate changes for this tariff.

Schedule TC
RPU offers service under its Traffic Control tariff for all traffic signals. This service is charged an energy - only rate. Proposed changes to this tariff are based on the analysis conducted for the Study and include annual adjustments of 5.3%. Appendix A Table A-7 includes the proposed changes to this tariff.

RPU Rate Programs
RPU provides service under a variety of rate programs designed to address unique rate options. Several of these programs are designed for residential customers with qualifying medical equipment, as w ell as its Multi- Family program that is designed to provide service to master metered dwellings, su ch as mobile-home parks. RPU has offered All- Electric, Electric Water Heater, and Electric Space Heater rate programs in the past; however, these specific rate programs are no longer open to additional customers.

RPU is proposing to maintain the structur e of these programs, as they existed prior to November 2010 with the addition of the NAC charges applied during the previous rate study. Additionally, rates for these services will change with the changes in RPU’s system costs.

All-Electric Service
RPU offered service to customers with “All- Electric” appliances and load, as well as to customers with Electric Water Heater and Electric Space Heater appliances. RPU currently services approximately 1,400 customers within these three programs; however, these rates are closed to new customers who did not take building permits or wiring permits before March 1, 1974. Proposed changes for this rate program include an increased customer charge, increased NAC (based on the changes for the Domestic rate), and an increase in the energy charge. The energy rate is adjusted to increase the revenue for each of these rate programs to recognize the Revenue Requirement for the system. Proposed rates for these three programs are included in Appendix A Tables A-8A, A-8B and A-8C.

Multi-Family Service
RPU offers service for “master- meter” communities under its Multi -Family Service rate program to approximately 200 customers. Service under this rate program is currently charged a customer charge, a tiered energy charge, and a Reliability Charge similar to the Domestic rates. Proposed changes include an increased customer charge, increased NAC, and increased energy charges. See Table 6-2 for the proposed changes to the rate components applicable to this rate program , which are equivalent to the Domestic rates.

Section 6

6-26
Conclusions
Based on the results of the analysis completed for this Study, the following conclusions are presented:
 RPU seeks to advance the City’s mission to provide high -quality municipal water and electric utility services to its customers. This mission is detailed in the infrastructure improvements and upgrades identified in its utility plans . RPU’s current rates and rate structures are insufficient to provide the revenue necessary to support the se improvements. Based on the development of th e Test Year Revenue Requirement from RPU’s Financial Pro Forma Model , current rates are not projected to generate sufficient revenues to cover its projected costs. This shortfall is expected to be approximately $305.9 million at the end of the Five-Year Rate Plan.
 RPU’s existing rate components (i.e., demand, customer charge, and energy) are not properly aligned with its fixed and variable costs. These existing rates and rate structures contribute to RPU’s current under-recovery of its fixed costs from fixed revenues . The proposed changes herein provide for an increase in RPU’s fixed cost recovery through fixed revenues , consistent with its established rate objectives.

Recommendations
Based on the conclusions and supporting analyses presented herein, NewGen makes the following recommendations:
 The City should adopt rates as described and proposed in Five-Year Rate Plan and this Report.  The City should continue its efforts to increase the fixed cost recovery mechanisms in its rate structures.
 The City should continue to invest in infrastructure, equipment, and personnel to ensure its ability to meet customer demand for innovation and reliable power supply.  The City should continue to monitor and evaluate evolving technologies, systems, and operations to maximize its investments.

APPENDIX A:

PROPOSED RATES – OTHER

CUSTOMER CLASSES

ELECTRIC COST OF SERVICE AND RATE DESIGN
STUDY

Economics | Strategy | Stakeholders | Sustainability
Appendix A
PROPOSED RATES – OTHER CUSTOMER CLASSES
The following provides a summary of the proposed rates for RPU’s Other Classes, including LED and non- LED rates for customer -owned street lights (LS -2) and Department -owned outdoor lights (OL), power agriculture (PA), wind frost protection rate (PW -1), Standby Service (Schedule S) , and Traffic Control (Schedule TC). See text for details on proposed rate changes.

Additionally, proposed rate changes for RPU’s Rate Programs, including All Electric, Electric Water Heater, and Electric Space Heater, are included following the Other Class rates. See text for additional information on proposed changes to the rates for these programs.

Appendix A

A-2
Tiered
Schedule LS-2
Table A-1
Existing Schedule LS-2 (Energy Only, $/year) (1)
Light Type
(Wattage)
Existing
Rate 2024 2025 2026 2027 2028
Incandescent
1,000 Lumens $49.29 $51.26 $53.31 $55.44 $57.66 $59.97 2,500 Lumens $102.97 $107.09 $111.37 $115.83 $120.46 $125.28 4,000 Lumens $157.33 $163.62 $170.17 $176.97 $184.05 $191.42 6,000 Lumens $180.99 $188.23 $195.76 $203.59 $211.73 $220.20 Mercury Vapor
7,000 Lumens $110.66 $115.09 $119.69 $124.48 $129.46 $134.63 10,000 Lumens $152.64 $158.75 $165.10 $171.70 $178.57 $185.71 20,000 Lumens $242.98 $252.70 $262.81 $273.32 $284.25 $295.62 35,000 Lumens $419.07 $435.83 $453.27 $471.40 $490.25 $509.86 55,000 Lumens $589.11 $612.67 $637.18 $662.67 $689.18 $716.74 Sodium Vapor
5,800 Lumens $46.79 $48.66 $50.61 $52.63 $54.74 $56.93 9,500 Lumens $73.89 $76.85 $79.92 $83.12 $86.44 $89.90 16,000 Lumens $107.31 $111.60 $116.07 $120.71 $125.54 $130.56 22,000 Lumens $138.22 $143.75 $149.50 $155.48 $161.70 $168.17 25,000 Lumens $166.71 $173.38 $180.31 $187.53 $195.03 $202.83 40,000 Lumens $252.56 $262.66 $273.17 $284.10 $295.46 $307.28 LED by Average Lumens
3,100 Lumens $63.70 $66.25 $68.90 $71.65 $74.52 $77.50 6,750 Lumens $104.18 $108.35 $112.68 $117.19 $121.88 $126.75 9,667 Lumens $120.12 $124.92 $129.92 $135.12 $140.52 $146.14 17,333 Lumens $142.14 $147.83 $153.74 $159.89 $166.28 $172.94 25,000 Lumens $161.47 $167.93 $174.65 $181.63 $188.90 $196.45 37,500 Lumens $251.20 $261.25 $271.70 $282.57 $293.87 $305.62 55,000 Lumens $319.76 $332.55 $345.85 $359.69 $374.07 $389.04 (1) LS-2 Rate Schedule is for Customer Owned Lights, whereby RPU provides either the energy or the energy and maintenance for the light. The rates are proposed to be charged annually per LED light by average lumen. Rate changes are effective on January 1 of each year.

PROPOSED RATES – OTHER CUSTOMER CLASSES

A-3
Table A-2
Existing LS-2 Street Lights (Energy and Maintenance, $/year) (1) Light Type
(Wattage)
Existing
Rate 2024 2025 2026 2027 2028
Incandescent
1,000 Lumens $62.82 $65.33 $67.95 $70.66 $73.49 $76.43 2,500 Lumens $119.90 $124.70 $129.68 $134.87 $140.27 $145.88 4,000 Lumens $180.99 $188.23 $195.76 $203.59 $211.73 $220.20 6,000 Lumens $228.34 $237.47 $246.97 $256.85 $267.13 $277.81 Mercury Vapor
7,000 Lumens $134.34 $139.71 $145.30 $151.11 $157.16 $163.45 10,000 Lumens $179.68 $186.87 $194.34 $202.12 $210.20 $218.61 20,000 Lumens $275.08 $286.08 $297.53 $309.43 $321.80 $334.68 35,000 Lumens $462.99 $481.51 $500.77 $520.80 $541.63 $563.30 55,000 Lumens $648.28 $674.21 $701.18 $729.23 $758.40 $788.73 Sodium Vapor
5,800 Lumens $62.02 $64.50 $67.08 $69.76 $72.55 $75.46 9,500 Lumens $90.79 $94.42 $98.20 $102.13 $106.21 $110.46 16,000 Lumens $125.92 $130.96 $136.20 $141.64 $147.31 $153.20 22,000 Lumens $156.83 $163.10 $169.63 $176.41 $183.47 $190.81 25,000 Lumens $186.99 $194.47 $202.25 $210.34 $218.75 $227.50 40,000 Lumens $283.28 $294.61 $306.40 $318.65 $331.40 $344.65 LED by Average Lumens
3,100 Lumens $78.92 $82.08 $85.36 $88.77 $92.33 $96.02 6,750 Lumens $124.47 $129.45 $134.63 $140.01 $145.61 $151.44 9,667 Lumens $149.99 $155.99 $162.23 $168.72 $175.47 $182.49 17,333 Lumens $168.05 $174.77 $181.76 $189.03 $196.59 $204.46 25,000 Lumens $181.75 $189.02 $196.58 $204.44 $212.62 $221.13 37,500 Lumens $281.51 $292.77 $304.48 $316.66 $329.33 $342.50 55,000 Lumens $378.94 $394.10 $409.86 $426.26 $443.31 $461.04 (1) LS-2 Rate Schedule is for Customer Owned Lights, whereby RPU provides either the energy or the energy and maintenance for the light. The rates are proposed to be charged annually per LED light by average lumen. Rate changes are effective on January 1 of each year.

Appendix A

A-4
Schedule OL
Table A-3
Schedule OL (1)
Light Type Existing 2024 2025 2026 2027 2028
Mercury Vapor
7,000 Lumens $11.63 $12.10 $12.58 $13.08 $13.60 $14.14
20,000 Lumens $20.54 $21.36 $22.21 $23.10 $24.02 $24.98 High Pressure Sodium
9,500 Lumens $11.69 $12.16 $12.65 $13.16 $13.69 $14.24
16,000 Lumens $16.38 $17.04 $17.72 $18.43 $19.17 $19.94 LED
3,500-5,800 Lumens $11.83 $12.30 $12.79 $13.30 $13.83 $14.38 7,000-9,500 Lumens $13.24 $13.77 $14.32 $14.89 $15.49 $16.11 10,000-16,000 Lumens $15.75 $16.38 $17.04 $17.72 $18.43 $19.17 (1) OL Rate Schedule is for Outdoor Lights that are owned, installed, and maintained by RPU. The rates are proposed to be charged monthly per light by average lumen. Rate changes are effective January 1 of each subsequent year.

Schedule PA
Table A-4
Power – Agricultural Pumping
Rate Component Existing
Proposed Effective January 1
2024 2025 2026 2027 2028
Effective Customer Charge (1) $52.60 $54.70 $56.89 $59.17 $61.54 $64.00 Network Access Charge ($/month)

Tier 1 (0–500 kWh) $3.35 $3.48 $3.62 $3.76 $3.91 $4.07 Tier 2 (501–1500 kWh) $9.50 $9.88 $10.28 $10.69 $11.12 $11.56 Tier 3 (1501–3000 kWh) $16.89 $17.57 $18.27 $19.00 $19.76 $20.55 Tier 4 (>3000 kWh) $40.63 $42.26 $43.95 $45.71 $47.54 $49.44 Energy Charge

All kWh ($/kWh) $0.1117 $0.1162 $0.1208 $0.1256 $0.1306 $0.1358 Reliability Charge ($/month) (2) $60.00 $60.00 $60.00 $60.00 $60.00 $60.00 (1) Effective Customer Charge is an annual service charge per horsepower (HP) that varies by the horsepower rating of the pump. 2 HP minimum. (2) Reliability Charge same as Commercial – Flat Tier 3. No change proposed.

PROPOSED RATES – OTHER CUSTOMER CLASSES

A-5
Schedule PW 1
Table A-5
Wind Frost Protection
Rate Component Existing
Proposed Effective January 1
2024 2025 2026 2027 2028
Customer Charge ($/Month) $20.50 $20.50 $20.50 $20.50 $20.50 $20.50 Network Access Charge
($/month)

Tier 1 (0–500 kWh) $3.35 $3.45 $3.59 $3.75 $3.92 $4.08
Tier 2 (501–1500 kWh) $9.50 $9.79 $10.18 $10.64 $11.12 $11.56 Tier 3 (1501–3000 kWh) $16.89 $17.40 $18.10 $18.91 $19.76 $20.55 Tier 4 (>3000 kWh) $40.63 $41.85 $43.52 $45.48 $47.53 $49.43 Energy Charge ($/kWh)

Tier 1 (0–15,000 kWh) $0.1486 $0.1531 $0.1592 $0.1664 $0.1739 $0.1809 Tier 2 (> 15,000 kWh) $0.2270 $0.2338 $0.2432 $0.2541 $0.2655 $0.2761

Schedule S
Table A-6
Schedule S (Standby Service)
Rate Component Existing
Proposed Effective January 1
2024 2025 2026 2027 2028
Demand Charge
($/kW)

< 50 kV $7.38 $7.66 $7.97 $8.29 $8.41 $8.58
> 50 kV $4.95 $5.14 $5.35 $5.56 $5.64 $5.75

Schedule TC
Table A-7
Schedule TC (Traffic Control)
Rate Component Existing
Proposed Effective January 1
2024 2025 2026 2027 2028
Energy Charge (all kWh)

$/kWh $0.1098 $0.1156 $0.1218 $0.1283 $0.1351 $0.1423

Appendix A

A-6
RPU Rate Programs
All Electric Service
Table A-8A
All Electric Service (1)
Rate Component Existing
Proposed Effective January 1
2024 2025 2026 2027 2028
Customer Charge ($/month) $12.06 $12.90 $13.86 $14.93 $14.93 $15.09 Network Access Charge
($/month)

Tier 1 (or < = 12 kWh
Daily Average)
$2.49 $3.19 $3.89 $4.60 $5.24 $5.69
Tier 2 (>12 - 25 kWh Daily
Average)
$5.97 $7.44 $8.91 $10.38 $11.85 $12.65
Tier 3 (>25 kWh Daily
Average)
$13.16 $15.32 $17.48 $19.64 $21.80 $23.00
Energy Charge - Summer
($/kWh)

0–750 kWh $0.1102 $0.1179 $0.1266 $0.1364 $0.1364 $0.1379 751–1,500 kWh $0.1753 $0.1880 $0.2007 $0.2134 $0.2261 $0.2388 > 1,500 kWh $0.1743 $0.1870 $0.1996 $0.2122 $0.2249 $0.2375 Energy Charge - Winter
($/kWh)

0–350 kWh $0.1102 $0.1179 $0.1266 $0.1364 $0.1364 $0.1379 351–750 kWh $0.1753 $0.1880 $0.2007 $0.2134 $0.2261 $0.2388 >750 kWh $0.1743 $0.1870 $0.1996 $0.2122 $0.2249 $0.2375 (1) Reliability charged as Domestic.

PROPOSED RATES – OTHER CUSTOMER CLASSES

A-7
Table A-8B
Electric Water Heater (1)
Rate Component Existing
Proposed Effective January 1
2024 2025 2026 2027 2028
Customer Charge ($/month) $12.06 $12.90 $13.86 $14.93 $14.93 $15.09 Network Access Charge
($/month)

Tier 1 (or < = 12 kWh Daily
Average)
$2.49 $3.19 $3.89 $4.60 $5.24 $5.69
Tier 2 (>12 - 25 kWh Daily
Average)
$5.97 $7.44 $8.91 $10.38 $11.85 $12.65
Tier 3 (>25 kWh Daily
Average)
$13.16 $15.32 $17.48 $19.64 $21.80 $23.00
Energy Charge - Summer
($/kWh)

0–600 kWh $0.1102 $0.1179 $0.1266 $0.1364 $0.1364 $0.1379 601–950 kWh $0.1245 $0.1332 $0.1430 $0.1541 $0.1541 $0.1558 951–1500 kWh $0.1753 $0.1880 $0.2007 $0.2134 $0.2261 $0.2388 > 1,500 kWh $0.1988 $0.2127 $0.2285 $0.2462 $0.2462 $0.2488 Energy Charge - Winter
($/kWh)

0–350 kWh $0.1102 $0.1179 $0.1266 $0.1364 $0.1364 $0.1379 351–600 kWh $0.1753 $0.1880 $0.2007 $0.2134 $0.2261 $0.2388 601–950 kWh $0.1245 $0.1332 $0.1430 $0.1541 $0.1541 $0.1558 >950 kWh $0.1988 $0.2127 $0.2285 $0.2462 $0.2462 $0.2488 (1) Reliability charged as Domestic.

Appendix A

A-8
Table A-8C
Electric Space Heater (1)
Rate Component Existing
Proposed Effective January 1
2024 2025 2026 2027 2028
Customer Charge ($/month) $12.06 $12.90 $13.86 $14.93 $14.93 $15.09 Network Access Charge
($/month)

Tier 1 (or < = 12 kWh Daily
Average)

2.49 $3.19 $3.89 $4.60 $5.24 $5.69
Tier 2 (>12 - 25 kWh Daily
Average)

5.97 $7.44 $8.91 $10.38 $11.85 $12.65
Tier 3 (>25 kWh Daily
Average)

13.16 $15.32 $17.48 $19.64 $21.80 $23.00
Energy Charge - Summer
($/kWh)

0–750 kWh $0.1102 $0.1179 $0.1266 $0.1364 $0.1364 $0.1379 751–1500 kWh $0.1753 $0.1880 $0.2007 $0.2134 $0.2261 $0.2388 > 1,500 kWh $0.1988 $0.2127 $0.2285 $0.2462 $0.2462 $0.2488 Energy Charge - Winter
($/kWh)

ELECTRIC COST OF SERVICE AND RATE DESIGN
STUDY
APPENDIX B:

TECHNICAL APPENDIX

# Tab Name Content Type
1 Functional UnbundlingAllocation of detailed costs to utility functions. Analysis/Reporting 2 Production Allocation of production related costs to demand and energy components Analysis/Reporting
3 Transmission Allocation of transmission related costs to demand and energy components Analysis/Reporting
4 Distribution Allocation of distribution related costs to demand and customer components Analysis/Reporting
5 Customer Allocation of customer related costs to various types of customer services. Analysis/Reporting
6 COS Allocation of functionalized test-year costs to customer classes.Analysis/Reporting 7 Summary Rates Rate schedule through FY28 by class and rate type Analysis/Reporting 8 WP-1A Rev Req Revenue requirement projection through FY28 Supporting Data 9 WP-1C Rev Req Scenario 2Revenue requirement projection through FY28 - Scenario 2Supporting Data 10 WP-2A Other RevenueDetailed Statement of Other Revenue Supporting Data 11 WP-2C Other Revenue Scenario 2Detailed Statement of Other Revenue - Scenario 2 Supporting Data 12 WP-3A Operating ExpensesDetailed Statement of Operating Expenses Supporting Data 13 WP-3E Oper Expenses Scenario 2Detailed Statement of Operating Expenses - Scenario 2Supporting Data 14 WP-4A Debt by FunctionFunctionalization of Debt Service Supporting Data 15 WP-4C Debt by Function S2Functionalization of Debt Service - Scenario 2 Supporting Data 16 WP-5A Plant in ServiceDetailed Statement of Plant Balances Supporting Data 17 WP-6A Labor Detailed Statement of Labor Expenses Supporting Data 18 WP-7A Purchased PowerFunctionalization of Purchased Power Expenses Supporting Data 19 WP-8A Transmission CostsBreakdown of Transmission Expenses Supporting Data 20 WP-9A CIP Allocator Cost Allocation of of CIP Forecast Supporting Data 21 WP-10 A&G Allocator Functionalization of A&G Expenses Supporting Data 22 WP-11 Minimum SystemCalculation of Minimum System Cost Supporting Data 23 WP-12A Reserve BalancesForecast of reserve balance through FY32 Supporting Data 24 WP-13 TY Demand - FY19 LPForecast of TY Demand by class using FY19 Load ProfileSupporting Data 25 WP-13 TY Demand - FY22 LPForecast of TY Demand by class using FY22 Load ProfileSupporting Data 26 WP-14 Lighting Info Street Lighting Class Data Supporting Data 27 WP-15 Generation Costs - DCRRenewable energy delivery capital recovery through FY30Supporting Data 28 WP-16 HV Cost High voltage demand adjustment cost calculations Supporting Data Table of Contents
Model Developer Statement:

This model has been prepared by NewGen Strategies and Solutions, LLC (NewGen) solely for the use on behalf of our client for the specific purposes identified in our agreement with the client and its use is restricted for any other purposes. NewGen has relied upon information provided by the client or others that is used in the preparation of this model to be accurate and makes no representations or warranties as to the accuracy of this information. NewGen gives no assurances related to the use of this model except as explicitly set forth in the final results produced using this model as presented and set forth in the NewGen report that presents these final results. For model support, please contact [email protected].

Electric System Rate Study
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57 A B C D E F
Functional Unbundling
Line Fiscal Year Test Year Adjusted
No. Item Account/ID 2021 Adjustment Test Year
1 Production O&M
2 Steam Production Operation
3 Supervision & Engineering 500 -$ -$ -$ 4 Fuel (Transportation & Handling) 501 -$ -$ -$ 5 Steam Power Fuel - Gas 50110 -$ -$ -$ 6 Steam Power Fuel - Oil 50120 -$ -$ -$ 7 Steam Power Fuel - Coal 50130 -$ -$ -$ 8 Steam Expense 502 -$ -$ -$ 9 Electric Expense 505 -$ -$ -$ 10 Miscellaneous 506 -$ -$ -$ 11 Rent 507 -$ -$ -$ 12 Subtotal Steam Production Opeation -$ -$ -$ 13 14 Steam Production Maintenance
15 Supervision & Engineering 510 -$ -$ -$ 16 Structures 511 -$ -$ -$ 17 Boilers 512 -$ -$ -$ 18 Electric Plant 513 -$ -$ -$ 19 Miscellaneous Labor 515 -$ -$ -$ 20 Subtotal Steam Production Maintenance -$ -$ -$ 21 22 Nuclear Production Operation
23 Supervision & Engineering 517 -$ -$ -$ 24 Nuclear Fuel Expense 518 -$ -$ -$ 25 Electric Expense - Turbine Generators 523 -$ -$ -$ 26 Reserved NA -$ -$ -$ 27 Miscellaneous Power Expenses 524 684,381$ (363,181)$ 321,200$ 28 Reserved NA -$ -$ -$ 29 Subtotal Nuclear Production Operation 684,381$ (363,181)$ 321,200$ 30 31 Nuclear Production Maintenance
32 Supervision & Engineering 528 -$ -$ -$ 33 Reserved NA -$ -$ -$ 34 Reserved NA -$ -$ -$ 35 Reserved NA -$ -$ -$ 36 Miscellaneous Plant 530 137,801$ 403,628$ 541,428$ 37 Subtotal Nuclear Production Maintenance 137,801$ 403,628$ 541,428$ 38 39 Combined Cycle Operation
40 Supervision & Engineering NA -$ -$ -$ 41 Fuel NA -$ -$ -$ 42 Combined Cycle Fuel - Gas NA -$ -$ -$ 43 Combined Cycle Fuel - Oil NA -$ -$ -$ 44 Generation Expense NA -$ -$ -$ 45 Miscellaneous NA -$ -$ -$ 46 Subtotal Combined Cycle Operation -$ -$ -$ 47 48 Combined Cycle Maintenance
49 Supervision & Engineering NA -$ -$ -$ 50 Structures NA -$ -$ -$ 51 Electric Plant NA -$ -$ -$ 52 Miscellaneous Plant NA -$ -$ -$ 53 Subtotal Combined Cycle Maintenance -$ -$ -$ 54 1
2 3

A B C D E F
Functional Unbundling
Line Fiscal Year Test Year Adjusted
No. Item Account/ID 2021 Adjustment Test Year
58 59
60 61
62 63
64 65
66 67
68 69
70 71
72 73
74 75
76 77
78 79
80 81
82 83
84 85
86 87
88 89
90 91
92 93
94 95
96 97
98 99
100
101
102
103
104
105
106
107
108
109
110
111
112
113
114
115
116
117
118
119
120
121
122
123
124
125
126
127
128
129
130
131
132
133
134
135
55 Other Production
56 Intermountain Power (take or pay) 546 34,485,975$ (24,583,186)$ 9,902,789$ 57 Fuel Expense 547 5,166,723$ 14,127,688$ 19,294,411$ 58 Hoover (take or pay) 548 501,172$ 425,790$ 926,962$ 59 Misc. Other Power Generation 549 -$ -$ -$ 60 Palo Verde Power (take or pay) 550 2,372,198$ 2,358,182$ 4,730,380$ 61 Deseret Power (take or pay) 552 -$ -$ -$ 62 Maint/Generating & Elec. Equip. 553 5,254,765$ (1,026,189)$ 4,228,576$ 63 System Load Control 556 5,009,358$ (1,358,611)$ 3,650,747$ 64 Other Expenditures 557 8,035,233$ 6,581,780$ 14,617,013$ 65 Purchased Power 555 102,260,731$ 17,485,708$ 119,746,439$ 66 Purchased Power - Energy Direct Assignment 55501 -$ -$ -$ 67 Subtotal Other Production 163,086,156$ 14,011,161$ 177,097,317$ 68 69 Total Production O&M 163,908,338$ 14,051,608$ 177,959,946$ 70 321,000$
71 Fuel & Purchased Power 144,786,800$ 9,814,181$ 154,600,981$ 72 73 Total Production O&M less Fuel & Purchased Power 19,121,538$ 4,237,427$ 23,358,965$ 74 75 Transmission O&M
76 Transmission Operation
77 Supervision & Engineering 560 -$ -$ -$ 78 Load Dispatch 561 -$ -$ -$ 79 Station Equipment 562 150,052$ (77,659)$ 72,393$ 80 Overhead Lines 563 -$ -$ -$ 81 Underground Lines 564 -$ -$ -$ 82 Miscellaneous 566 220,184$ (34,554)$ 185,629$ 83 Rents 567 -$ -$ -$ 84 Subtotal Transmission Operation 370,236$ (112,213)$ 258,023$ 85 86 Transmission Maintenance
87 Supervision & Engineering 568 -$ -$ -$ 88 Structures 569 -$ -$ -$ 89 Station Equipment 570 223,984$ (108,554)$ 115,430$ 90 Overhead Lines 571 12,042$ (8,626)$ 3,415$ 91 Underground Lines 572 -$ -$ -$ 92 Miscellaneous 573 1,405,306$ (666,009)$ 739,297$ 93 Subtotal Transmission Maintenance 1,641,332$ (783,189)$ 858,143$ 94 95 Wheeling
96 Transmission Cost Fixed 565 18,299,896$ 1,614,868$ 19,914,764$ 97 Transmission Cost Variable 565 39,458,690$ 3,482,018$ 42,940,708$ 98 Subtotal Wheeling 57,758,586$ 5,096,886$ 62,855,472$ 99 100 Total Transmission O&M 59,770,154$ 4,201,484$ 63,971,638$ 101 -$
102 Distribution O&M
103 Distribution Operations
104 Operation Maintenance and Engineering 580 4,351,633$ 803,338$ 5,154,971$ 105 Load Dispatch 581 2,619,584$ 599,677$ 3,219,260$ 106 Station Equipment 582 20,012$ (546)$ 19,467$ 107 Overhead Lines 583 -$ 91$ 91$ 108 Underground Lines 584 -$ 4,616$ 4,616$ 109 Street Lighting & Signal Expenses 585 -$ -$ -$ 110 Metering 586 68,265$ 39,728$ 107,992$ 111 Customer Installations 587 196,749$ (59,922)$ 136,827$ 112 Miscellaneous 588 60,250$ 29,477$ 89,726$ 113 Rents 589 -$ -$ -$ 114 Subtotal Distribution Operations 7,316,492$ 1,416,458$ 8,732,950$ 115
116 Distribution Maintenance
117 Supervision 590 -$ -$ -$ 118 Structures 591 55,080$ 13,840$ 68,920$ 119 Station Equipment 592 1,085,659$ 163,649$ 1,249,308$ 120 Overhead Lines 593 8,844,686$ (1,120,633)$ 7,724,053$ 121 Underground Lines 594 2,387,820$ 488,589$ 2,876,410$ 122 Transformers 595 51,576$ 27,360$ 78,936$ 123 Street Lighting & Signals 596 1,313,480$ (87,216)$ 1,226,264$ 124 Metering 597 177,434$ 176,217$ 353,651$ 125 Miscellaneous 598 502,532$ 203,476$ 706,008$ 126 Subtotal Distribution Maintenance 14,418,266$ (134,717)$ 14,283,549$ 127
128 Total Distribution O&M 21,734,758$ 1,281,742$ 23,016,500$ 129
130 Customer O&M
131 Customer Accounting Expense
132 Supervision 901 252,050$ (8,170)$ 243,880$ 1 2
3 A B C D E F
Functional Unbundling
Line Fiscal Year Test Year Adjusted
No. Item Account/ID 2021 Adjustment Test Year
136
137
138
139
140
141
142
143
144
145
146
147
148
149
150
151
152
153
154
155
156
157
158
159
160
161
162
163
164
165
166
167
168
169
170
171
172
173
174
175
133 Meter Reading 902 1,073,989$ 285,947$ 1,359,936$ 134 Customer Records and Collection Expenses 903 5,503,244$ 1,504,888$ 7,008,132$ 135 Reserved NA -$ -$ -$ 136 Uncollectible Accounts 904 4,034,000$ (2,793,560)$ 1,240,440$ 137 Miscellaneous 905 -$ -$ -$ 138 Subtotal Customer Accounting Expense 10,863,283$ (1,010,896)$ 9,852,388$ 139
140 Other Customer Costs
141 Supervision 907 -$ -$ -$ 142 Customer Assistance 908 1,616,598$ (553,924)$ 1,062,674$ 143 Advertisement 909 20,865$ 188,617$ 209,483$ 144 Miscellaneous 910 -$ -$ -$ 145 Subotal Other Customer Costs 1,637,464$ (365,307)$ 1,272,157$ 146
147 Sales Expense
148 Sales Expense - Supervision 911 -$ -$ -$ 149 Demonstrations & Selling 912 -$ 239,001$ 239,001$ 150 Advertising Expenses 913 381$ 2,581$ 2,962$ 151 Miscellaneous Sales Expense 916 -$ -$ -$ 152 Subtotal Sales Expense 381$ 241,583$ 241,963$ 153
154 Total Customer O&M 12,501,128$ (1,134,620)$ 11,366,508$ 155
156 Administrative & General Expense
157 Administrative Salaries & Misc. Labor 920 16,530,398$ (579,878)$ 15,950,520$ 158 Office Supplies & Expense 921 451,863$ 267,919$ 719,781$ 159 Interdepartmental Charges 922 (24,856,031)$ (3,710,117)$ (28,566,148)$ 160 Outside Services 923 5,039,527$ 1,160,587$ 6,200,114$ 161 Property Insurance 924 -$ -$ -$ 162 Injuries and Damages 925 -$ -$ -$ 163 Employee Pensions and Benefits 926 20,023,879$ 3,643,466$ 23,667,345$ 164 Franchise Requirements 927 -$ -$ -$ 165 Compliance & Consultants (Regulatory Commission Expense) 928 -$ 10,902$ 10,902$ 166 General Advertising Expense 930 -$ 2,137$ 2,137$ 167 Rents 931 1,357,223$ 269,781$ 1,627,004$ 168 Miscellaneous General Expenses 933 3,235,604$ 279,511$ 3,515,115$ 169 Maintenance of General Plant 932 127,337$ 21,136$ 148,473$ 170 Duplicate Charges - Credit 929 -$ -$ -$ 171 Subtotal Administrative & General Expense 21,909,800$ 1,365,443$ 23,275,243$ 172
1 2
3 A B C D E F
Functional Unbundling
Line Fiscal Year Test Year Adjusted
No. Item Account/ID 2021 Adjustment Test Year
176
177
178
179
180
181
182
183
184
185
186
187
188
189
190
191
192
193
194
195
196
197
198
199
200
201
202
203
204
205
206
207
208
209
210
211
212
213
214
215
216
217
218
219
220
221
222
223
224
225
226
227
228
229
230
231
232
233
234
235
236
237
238
173 Miscellaneous and Clearing Accounts
174 General Government Charges 701 13,059,522$ 2,666,755$ 15,726,277$ 175 Expenses Transferred from Electric 702 4,268,209$ 374,170$ 4,642,379$ 176 IDI Utility Charges 703 134,736$ (93,525)$ 41,211$ 177 Removal Expenses 704 -$ -$ -$ 178 Taxes 707 -$ -$ -$ 179 Stores Expenses 781 -$ -$ -$ 180 Transportation Expenses 782 1,387,941$ 199,258$ 1,587,199$ 181 Tool and Shop Expenses 783 (1,361,058)$ (7,992)$ (1,369,050)$ 182 Insurance 788 877,009$ 171,694$ 1,048,703$ 183 Non-Operating Expenses 790 -$ -$ -$ 184 Subtotal Miscellaneous and Clearing Accounts 18,366,360$ 3,310,359$ 21,676,719$ 185 40,276,160$
186 Total O&M Expense 298,190,537$ 23,076,016$ 321,266,553$ 187 (4,032,693)$ 1,304,591$ 188 Total O&M Expense less Purchased Power 153,403,737$ 13,261,835$ 166,665,572$ 189
190 Additional Expenses & Deductions
191 Debt Service
192 Generation 18,079,640$ 666,520$ 18,746,160$ 193 Transmission 2,997,414$ 110,502$ 3,107,916$ 194 Distribution 26,500,946$ 976,978$ 27,477,924$ 195 Customer -$ -$ 196 New Debt -$ 21,182,400$ 21,182,400$ 197 Total Debt Service 47,578,000$ 22,936,400$ 70,514,400$ 198
199 Taxes and Transfer to General Fund
200 General Fund Transfer 39,899,000$ 9,317,427$ 49,216,427$ 201 Other -$ -$ -$ 202 Other -$ -$ -$ 203 Other -$ -$ -$ 204 Subtotal Taxes and Transfer to General Fund 39,899,000$ 9,317,427$ 49,216,427$ 205
206 Capital Paid from Current Earnings
207 Production -$ 17,623$ 17,623$ 208 Transmission -$ -$ -$ 209 Distribution 1,188,984$ 2,812,393$ 4,001,377$ 210 Customer 26,016$ (26,016)$ -$ 211 Street Lighting Capital -$ -$ -$ 212 NA -$ -$ -$ 213 Sutotal Capital Paid from Current Earnings 1,215,000$ 2,804,000$ 4,019,000$ 214
215 Reserves - Additional Cash Requirements Minimum Target -$ 5,988,642$ 5,988,642$ 216
217 Total Additional Expenses & Deductions 88,692,000$ 41,046,469$ 129,738,469$ 218
219 Subtotal Revenue Requirement 386,882,537$ 64,122,485$ 451,005,022$ 220 (4,032,693)$ 1,304,591$ 221 Other Income 1.05% 1.64%
222 Other Operating Revenue:
223 Uncollectibles -$ -$ -$ 224 Diversion 344400 -$ -$ -$ 225 Service Connect Charges - Electric 344410 279,444$ 589,016$ 868,460$ 226 Misc Service Revenues - Electric 344491 21,288$ 2,388,312$ 2,409,600$ 227 Misc Operating Revenues - Electric 344492 9,279$ 21$ 9,300$ 228 Corona Fees- Rev 344493 -$ -$ -$ 229 Cap and Trade Auction 344511 8,250,800$ -$ -$ 230 REC Sale 344523 125,392$ (125,392)$ -$ 231 RA Capacity Sale 344522 1,461,211$ 279,363$ 1,740,574$ 232 Low Carbon Fuel Standard Credits 344514 1,165,678$ 760,623$ 1,926,300$ 233 Non Energy Receipts ABC Admin OH 344513 785,888$ 4,579$ 790,467$ 234 Subtotal Other Operating Revenue 12,098,980$ 3,896,520$ 7,744,701$ 235
1 2
3 A B C D E F
Functional Unbundling
Line Fiscal Year Test Year Adjusted
No. Item Account/ID 2021 Adjustment Test Year
239
240
241
242
243
244
245
246
247
248
249
250
251
252
253
254
255
256
257
258
259
260
261
262
263
264
265
266
267
268
269
270
271
272
273
274
275
276
277
278
279
280
281
282
283
284
285
236 Other Non-Operating Revenues (Expenses):
237 Gain (Loss) on retirement of utility plant N/A -$ -$ -$ 238 Interest Income N/A -$ -$ -$ 239 Corona Fees - Rev 344493 -$ -$ -$ 240 Misc. Settlement Reimbursement 344494 -$ -$ -$ 241 Late Payment Penalties 353400 -$ -$ -$ 242 Land and Building Rental 373100 2,378,690$ 428,490$ 2,807,180$ 243 Other Property Rental 373120 68,439$ 3,415$ 71,853$ 244 Pole Attachments 373125 502,110$ (233,641)$ 268,470$ 245 Substation Operation & Maintenance 373126 -$ -$ -$ 246 Substation Leasing 373127 -$ -$ -$ 247 Communication Services 373128 62,124$ 51,336$ 113,460$ 248 CIS User Fee 373132 -$ -$ -$ 249 Refunds and Reimbursements 374000 15,332$ (4,797)$ 10,535$ 250 Miscellaneous Receipts 374200 3,177,761$ (2,777,761)$ 400,000$ 251 Cash Over/Shortage 374207 79$ (79)$ -$ 252 Asset Forfeiture Revenue 374500 -$ -$ -$ 253 Bad Debt Recovery 374800 -$ -$ -$ 254 Settlement Recovery 374801 64,485$ (64,485)$ -$ 255 Settlement Recovery - SONGS 374802 -$ -$ -$ 256 Liquidated Damages 374810 -$ -$ -$ 257 Sale of Salvage Materials 380030 64,788$ (29,788)$ 35,000$ 258 Damage Claim Recoveries 380100 562,389$ (562,389)$ -$ 259 Operating Transfer from 650 Fund 985650 -$ -$ -$ 260 Utilization Charges 61250000 -$ -$ -$ 261 Subtotal Other Non-Operating Revenue 6,896,197$ (3,189,699)$ 3,706,497$ 262
263 Wholesale Sales 26,781$ (26,781)$ -$ 264
265 Transmission Revenue 32,315,656$ (6,583,255)$ 25,732,402$ 266
267 Total Other Income 51,337,614$ (5,903,214)$ 37,183,600$ 268
269 Total Retail Revenue Requirement 335,544,923$ 70,025,700$ 413,821,422$ 270 Reconcile to RPU Proforma
271 Adjustment for Cap and Trade Auction (8,250,800)$
272 Reconciled Total Retail Revenue Requirement 327,294,123$ 413,821,422$ 273 Difference from Proforma 4,887,311$ 341,430$ 274 % Difference from Proforma 1.52% 0.08%
275 Current Scenario Scenario 2
276 Revenue from Current Retail Rates - RPU Projections from Proforma 277 Residential $133,460,257.35 1,970,866.34$ $135,431,123.69 278 Commercial - Flat $43,345,273.73 9,021,593.68$ $52,366,867.41 279 Commercial - Demand $25,531,762.03 6,589,425.89$ $32,121,187.92 280 Industrial - TOU $115,205,533.21 19,396,479.99$ $134,602,013.20 281 Other $4,863,985.30 (477,346.89)$ $4,386,638.42 282 Total Revenue from Current Retail Rates $322,406,811.62 36,501,019.00$ $358,907,830.63 1 2
3 A B C D E F
Functional Unbundling
Line Fiscal Year Test Year Adjusted
No. Item Account/ID 2021 Adjustment Test Year
286
287
288
289
290
291
292
293
294
295
296
297
298
299
300
301
302
303
304
305
306
307
308
309
310
311
312
313
314
315
316
317
318
319
320
321
322
323
324
325
326
327
328
329
330
331
332
333
334
335
336
337
338
339
340
341
283
284 PLANT IN SERVICE
285
286 Gross Plant in Service
287 Intangible Plant
288 Organization 301 -$ -$ 289 Franchises and Consents 302 -$ -$ 290 Misc. Intangible Plant 303 32,637,528$ 32,637,528$ 291 Misc. Computer Software 3030 -$ -$ 292 Subtotal Intangible Plant 32,637,528$ -$ 32,637,528$ 293
294 Production Plant
295 Steam Production
296 Land and Land Rights 310 17,142$ 17,142$ 297 Structures & Improvements 311 -$ -$ 298 Boiler Plant Equipment 312 -$ -$ 299 Engines and Engine Generators 313 -$ -$ 300 Turbo-Generator Units 314 -$ -$ 301 Accessory Electric Equipment 315 -$ -$ 302 Misc. Power Plant Equipment 316 -$ -$ 303 Subtotal Steam Produciton 17,142$ -$ 17,142$ 304
305 Hydraulic Production
306 Land and Land Rights 330 -$ -$ 307 Structures & Improvements 331 -$ -$ 308 Reservoirs, Dams and Water Ways 332 -$ -$ 309 Water Wheel, Turbine and Generator 333 -$ -$ 310 Accessory Electric Equipment 334 -$ -$ 311 Misc. Power Plant Equipment 335 -$ -$ 312 Roads, Railroads and Bridges 336 -$ -$ 313 Subtotal Hydraulic Production -$ -$ -$ 314
315 Combustion Turbine & Other Production
316 Land and Land Rights 340 1,038,596$ 1,038,596$ 317 Structures & Improvements 341 703,469$ 703,469$ 318 Fuel Holders, Prod, & Acc. 342 -$ -$ 319 Prime Movers 343 -$ -$ 320 Generators & Other Production 344 268,544,986$ 268,544,986$ 321 Accessory Electric Equipment 345 -$ -$ 322 Misc. Production Plant 2000 -$ -$ 323 Subtotal Combustion Turbine & Other Production 270,287,051$ -$ 270,287,051$ 324
325 Total Production Plant 302,941,722$ -$ 302,941,722$ 326
327 Transmission Plant
328 Land and Land Rights 350 2,683,037$ 2,683,037$ 329 Reserved 351 -$ -$ 330 Structures & Improvements 352 971,062$ 971,062$ 331 Station Equipment - System 353 4,790,451$ 4,790,451$ 332 Towers and Fixtures 354 3,567,512$ 3,567,512$ 333 Poles and Fixtures 355 22,928,628$ 22,928,628$ 334 Overhead Conductor 356 8,716,136$ 8,716,136$ 335 Underground Conductor 357 5,748,846$ 5,748,846$ 336 Underground Conduit 358 2,356,742$ 2,356,742$ 337 Misc. Transmission Plant 359 -$ -$ 338 Subtotal Transmission Plant 51,762,414$ -$ 51,762,414$ 1 2
3 A B C D E F
Functional Unbundling
Line Fiscal Year Test Year Adjusted
No. Item Account/ID 2021 Adjustment Test Year
342
343
344
345
346
347
348
349
350
351
352
353
354
355
356
357
358
359
360
361
362
363
364
365
366
367
368
369
370
371
372
373
374
375
376
377
378
379
380
381
382
383
384
385
386
387
388
389
390
391
392
393
394
395
396
397
398
399
400
401
402
403
404
405
406
407
408
339
340 Distribution Plant
341 Land and Land Rights 360 41,183,402$ 41,183,402$ 342 Structures & Improvements 361 15,397,298$ 15,397,298$ 343 Station Equipment 362 160,729,872$ 160,729,872$ 344 Misc. Plant 363 -$ -$ 345 Towers and Fixtures 364 44,909,055$ 44,909,055$ 346 Overhead Conductor 365 45,300,634$ 45,300,634$ 347 Undgeround Conduit 366 131,830,676$ 131,830,676$ 348 Underground Conductor 367 137,105,611$ 137,105,611$ 349 Line Transformers 368 63,370,705$ 63,370,705$ 350 Services 369 29,359,860$ 29,359,860$ 351 Meters 370 21,963,893$ 21,963,893$ 352 Inst. on Customer Premises 371 851,584$ 851,584$ 353 Street Light / Signal System 373 55,987,877$ 55,987,877$ 354 Total Distribution Plant 747,990,468$ -$ 747,990,468$ 355
356 Subtotal Plant Before General 1,102,694,603$ -$ 1,102,694,603$ 357
358 General Plant
359 Land and Land Rights 389 8,119,611$ 8,119,611$ 360 Structures & Improvements 390 69,112,396$ 69,112,396$ 361 Structures & Improvements - Other 3900 -$ -$ 362 Office Furniture & Equipment 391 8,821,955$ 8,821,955$ 363 Info System Computers 3910 -$ -$ 364 Transportation Equipment 392 12,709,126$ 12,709,126$ 365 Stores Equipment 393 45,523$ 45,523$ 366 Tools, Shop & Garage Equipment 394 410,934$ 410,934$ 367 Laboratory Equipment 395 814,618$ 814,618$ 368 Power Operated Equipment 396 1,682,546$ 1,682,546$ 369 Communication Equipment 397 22,907,698$ 22,907,698$ 370 Miscellaneous Equipment 398 1,170,480$ 1,170,480$ 371 Other Tangible Property 399 18,944$ 18,944$ 372 Subtotal General Plant 125,813,830$ -$ 125,813,830$ 373
374 Total Gross Plant in Service 1,228,508,433$ -$ 1,228,508,433$ 375
376
377 Accumulated Depreciation
378 Intangible Plant
379 Organization 301 -$ -$ 380 Franchises and Consents 302 -$ -$ 381 Misc. Intangible Plant 303 32,637,528$ 32,637,528$ 382 Misc. Computer Software 3030 -$ -$ 383 Subtotal Intangible Plant 32,637,528$ -$ 32,637,528$ 384
385 Production Plant
386 Steam Production
387 Land and Land Rights 310 -$ -$ 388 Structures & Improvements 311 -$ -$ 389 Boiler Plant Equipment 312 -$ -$ 390 Engines and Engine Generators 313 -$ -$ 391 Turbo-Generator Units 314 -$ -$ 392 Accessory Electric Equipment 315 -$ -$ 393 Misc. Power Plant Equipment 316 -$ -$ 394 Subtotal Steam Produciton -$ -$ -$ 395
396 Hydraulic Production
397 Land and Land Rights 330 -$ -$ 398 Structures & Improvements 331 -$ -$ 399 Reservoirs, Dams and Water Ways 332 -$ -$ 400 Water Wheel, Turbine and Generator 333 -$ -$ 401 Accessory Electric Equipment 334 -$ -$ 402 Misc. Power Plant Equipment 335 -$ -$ 403 Roads, Railroads and Bridges 336 -$ -$ 404 Subtotal Hydraulic Production -$ -$ -$ 405
1 2
3 A B C D E F
Functional Unbundling
Line Fiscal Year Test Year Adjusted
No. Item Account/ID 2021 Adjustment Test Year
409
410
411
412
413
414
415
416
417
418
419
420
421
422
423
424
425
426
427
428
429
430
431
432
433
434
435
436
437
438
439
440
441
442
443
444
445
446
447
448
449
450
451
452
453
454
455
456
457
458
459
460
461
462
463
464
465
466
467
468
469
470
406 Combustion Turbine & Other Production
407 Land and Land Rights 340 -$ -$ 408 Structures & Improvements 341 155,300$ 155,300$ 409 Fuel Holders, Prod, & Acc. 342 -$ -$ 410 Prime Movers 343 -$ -$ 411 Generators & Other Production 344 111,722,271$ 111,722,271$ 412 Accessory Electric Equipment 345 -$ -$ 413 Misc. Production Plant 2000 -$ -$ 414 Subtotal Combustion Turbine & Other Production 111,877,570$ -$ 111,877,570$ 415
416 Total Production Plant 144,515,099$ -$ 144,515,099$ 417
418 Transmission Plant
419 Land and Land Rights 350 -$ -$ 420 Reserved 351 -$ -$ 421 Structures & Improvements 352 710,957$ 710,957$ 422 Station Equipment - System 353 4,522,181$ 4,522,181$ 423 Towers and Fixtures 354 1,251,520$ 1,251,520$ 424 Poles and Fixtures 355 8,164,974$ 8,164,974$ 425 Overhead Conductor 356 3,637,134$ 3,637,134$ 426 Underground Conductor 357 1,856,873$ 1,856,873$ 427 Underground Conduit 358 1,257,665$ 1,257,665$ 428 Misc. Transmission Plant 359 -$ -$ 429 Subtotal Transmission Plant 21,401,303$ -$ 21,401,303$ 430
431 Distribution Plant
432 Land and Land Rights 360 -$ -$ 433 Structures & Improvements 361 4,266,581$ 4,266,581$ 434 Station Equipment 362 56,848,424$ 56,848,424$ 435 Misc. Plant 363 -$ -$ 436 Towers and Fixtures 364 18,346,185$ 18,346,185$ 437 Overhead Conductor 365 24,052,960$ 24,052,960$ 438 Undgeround Conduit 366 37,896,415$ 37,896,415$ 439 Underground Conductor 367 68,490,579$ 68,490,579$ 440 Line Transformers 368 33,474,633$ 33,474,633$ 441 Services 369 15,070,839$ 15,070,839$ 442 Meters 370 7,206,731$ 7,206,731$ 443 Inst. on Customer Premises 371 762,056$ 762,056$ 444 Street Light / Signal System 373 36,039,497$ 36,039,497$ 445 Total Distribution Plant 302,454,899$ -$ 302,454,899$ 446
447 Subtotal Plant Before General 468,371,301$ -$ 468,371,301$ 448
449 General Plant
450 Land and Land Rights 389 -$ -$ 451 Structures & Improvements 390 16,266,385$ 16,266,385$ 452 Structures & Improvements - Other 3900 -$ -$ 453 Office Furniture & Equipment 391 6,564,847$ 6,564,847$ 454 Info System Computers 3910 -$ -$ 455 Transportation Equipment 392 10,269,478$ 10,269,478$ 456 Stores Equipment 393 45,523$ 45,523$ 457 Tools, Shop & Garage Equipment 394 353,329$ 353,329$ 458 Laboratory Equipment 395 814,618$ 814,618$ 459 Power Operated Equipment 396 1,480,842$ 1,480,842$ 460 Communication Equipment 397 17,135,827$ 17,135,827$ 461 Miscellaneous Equipment 398 1,069,802$ 1,069,802$ 462 Other Tangible Property 399 6,315$ 6,315$ 463 Subtotal General Plant 54,006,965$ -$ 54,006,965$ 464
465 Total Accumulated Depreciation 522,378,266$ -$ 522,378,266$ 466
467
1 2
3 A B C D E F
Functional Unbundling
Line Fiscal Year Test Year Adjusted
No. Item Account/ID 2021 Adjustment Test Year
471
472
473
474
475
476
477
478
479
480
481
482
483
484
485
486
487
488
489
490
491
492
493
494
495
496
497
498
499
500
501
502
503
504
505
506
507
508
509
510
511
512
513
514
515
516
517
518
519
520
521
522
523
524
525
526
527
528
529
530
531
532
533
534
535
536
537
538
539
540
541
542
468 Net Plant in Service
469 Intangible Plant
470 Organization 301 -$ -$ 471 Franchises and Consents 302 -$ -$ 472 Misc. Intangible Plant 303 19,290,334$ 19,290,334$ 473 Misc. Computer Software 3030 -$ -$ 474 Subtotal Intangible Plant 19,290,334$ -$ 19,290,334$ 475
476 Production Plant
477 Steam Production
478 Land and Land Rights 310 17,142$ 17,142$ 479 Structures & Improvements 311 -$ -$ 480 Boiler Plant Equipment 312 -$ -$ 481 Engines and Engine Generators 313 -$ -$ 482 Turbo-Generator Units 314 -$ -$ 483 Accessory Electric Equipment 315 -$ -$ 484 Misc. Power Plant Equipment 316 -$ -$ 485 Subtotal Steam Produciton 17,142$ -$ 17,142$ 486
487 Hydraulic Production
488 Land and Land Rights 330 -$ -$ 489 Structures & Improvements 331 -$ -$ 490 Reservoirs, Dams and Water Ways 332 -$ -$ 491 Water Wheel, Turbine and Generator 333 -$ -$ 492 Accessory Electric Equipment 334 -$ -$ 493 Misc. Power Plant Equipment 335 -$ -$ 494 Roads, Railroads and Bridges 336 -$ -$ 495 Subtotal Hydraulic Production -$ -$ -$ 496
497 Combustion Turbine & Other Production
498 Land and Land Rights 340 1,038,596$ 1,038,596$ 499 Structures & Improvements 341 548,169$ 548,169$ 500 Fuel Holders, Prod, & Acc. 342 -$ -$ 501 Prime Movers 343 -$ -$ 502 Generators & Other Production 344 156,822,716$ 156,822,716$ 503 Accessory Electric Equipment 345 -$ -$ 504 Misc. Production Plant 2000 -$ -$ 505 Subtotal Combustion Turbine & Other Production 158,409,481$ -$ 158,409,481$ 506
507 Total Production Plant 177,716,957$ -$ 177,716,957$ 508
509 Transmission Plant
510 Land and Land Rights 350 2,683,037$ 2,683,037$ 511 Reserved 351 -$ -$ 512 Structures & Improvements 352 260,105$ 260,105$ 513 Station Equipment - System 353 268,270$ 268,270$ 514 Towers and Fixtures 354 2,315,992$ 2,315,992$ 515 Poles and Fixtures 355 14,763,654$ 14,763,654$ 516 Overhead Conductor 356 5,079,002$ 5,079,002$ 517 Underground Conductor 357 3,891,973$ 3,891,973$ 518 Underground Conduit 358 1,099,077$ 1,099,077$ 519 Misc. Transmission Plant 359 -$ -$ 520 Subtotal Transmission Plant 30,361,110$ -$ 30,361,110$ 521
522 Distribution Plant
523 Land and Land Rights 360 41,183,402$ 41,183,402$ 524 Structures & Improvements 361 11,130,717$ 11,130,717$ 525 Station Equipment 362 103,881,448$ 103,881,448$ 526 Misc. Plant 363 -$ -$ 527 Towers and Fixtures 364 26,562,871$ 26,562,871$ 528 Overhead Conductor 365 21,247,674$ 21,247,674$ 529 Undgeround Conduit 366 93,934,261$ 93,934,261$ 530 Underground Conductor 367 68,615,032$ 68,615,032$ 531 Line Transformers 368 29,896,072$ 29,896,072$ 532 Services 369 14,289,021$ 14,289,021$ 533 Meters 370 14,757,162$ 14,757,162$ 534 Inst. on Customer Premises 371 89,528$ 89,528$ 535 Street Light / Signal System 373 19,948,380$ 19,948,380$ 536 Total Distribution Plant 445,535,569$ -$ 445,535,569$ 537
538 Subtotal Plant Before General 653,613,636$ -$ 653,613,636$ 539
1 2
3 A B C D E F
Functional Unbundling
Line Fiscal Year Test Year Adjusted
No. Item Account/ID 2021 Adjustment Test Year
543
544
545
546
547
548
549
550
551
552
553
554
555
556
557
558
559
560
561
562
563
564
565
566
567
568
569
570
571
572
573
574
575
576
577
578
579
580
581
582
583
584
585
586
587
588
589
590
591
592
593
594
595
596
597
598
599
600
601
602
603
604
605
606
607
608
609
610
611
612
540 General Plant
541 Land and Land Rights 389 8,119,611$ 8,119,611$ 542 Structures & Improvements 390 52,846,011$ 52,846,011$ 543 Structures & Improvements - Other 3900 -$ -$ 544 Office Furniture & Equipment 391 2,257,107$ 2,257,107$ 545 Info System Computers 3910 -$ -$ 546 Transportation Equipment 392 2,439,648$ 2,439,648$ 547 Stores Equipment 393 -$ -$ 548 Tools, Shop & Garage Equipment 394 57,605$ 57,605$ 549 Laboratory Equipment 395 (0)$ (0)$ 550 Power Operated Equipment 396 201,704$ 201,704$ 551 Communication Equipment 397 5,771,871$ 5,771,871$ 552 Miscellaneous Equipment 398 100,678$ 100,678$ 553 Other Tangible Property 399 12,629$ 12,629$ 554 Subtotal General Plant 71,806,865$ -$ 71,806,865$ 555
556 Total Net Plant in Service 725,420,501$ -$ 725,420,501$ 557
558
559 Labor
560
561 Production Labor
562 Steam Production Operation
563 Supervision & Engineering -$ -$ -$ 564 Fuel (Transportation & Handling) -$ -$ -$ 565 Steam Expense -$ -$ -$ 566 Electric Expense -$ -$ -$ 567 Miscellaneous -$ -$ -$ 568 Rent -$ -$ -$ 569 Total Steam Production Operation -$ -$ -$ 570
571 Steam Production Maintenance
572 Supervision & Engineering -$ -$ -$ 573 Structures -$ -$ -$ 574 Boilers -$ -$ -$ 575 Electric Plant -$ -$ -$ 576 Miscellaneous Labor -$ -$ -$ 577 Total Steam Production Maintenance -$ -$ -$ 578
579 Hydro Production Operation
580 Supervision & Engineering -$ -$ -$ 581 Water for Power -$ -$ -$ 582 Hydraulic Expense -$ -$ -$ 583 Electric Expense -$ -$ -$ 584 Miscellaneous -$ -$ -$ 585 Rent -$ -$ -$ 586 Total Hydro Production Operation -$ -$ -$ 587
588 Hydro Production Maintenance
589 Supervision & Engineering -$ -$ -$ 590 Structures -$ -$ -$ 591 Reservoirs & Dams -$ -$ -$ 592 Electric Plant -$ -$ -$ 593 Miscellaneous Plant -$ -$ -$ 594 Total Hydro Production Maintenance -$ -$ -$ 595
596 Combined Cycle Operation
597 Labor -$ -$ -$ 598 Fuel Handling -$ -$ -$ 599 Generation Expense -$ -$ -$ 600 Miscellaneous Plant -$ -$ -$ 601 Total Combined Cycle Operation -$ -$ -$ 602
603 Combined Cycle Maintenance
604 Supervision & Engineering -$ -$ -$ 605 Structures -$ -$ -$ 606 Electric Plant -$ -$ -$ 607 Miscellaneous Plant -$ -$ -$ 608 Total Combined Cycle Maintenance -$ -$ -$ 609
1 2
3 A B C D E F
Functional Unbundling
Line Fiscal Year Test Year Adjusted
No. Item Account/ID 2021 Adjustment Test Year
613
614
615
616
617
618
619
620
621
622
623
624
625
626
627
628
629
630
631
632
633
634
635
636
637
638
639
640
641
642
643
644
645
646
647
648
649
650
651
652
653
654
655
656
657
658
659
660
661
662
663
664
665
666
667
668
669
670
671
672
673
674
675
676
610 Other Production
611 RERC/Acorn Gen. Plant 6120130 3,041,888$ 146,477$ 3,188,365$ 612 Clearwater Generating Plant 6120140 972,663$ 39,488$ 1,012,152$ 613 PU Elec Power Supply Operations 6120000 7,688,970$ 1,996,558$ 9,685,528$ 614 Total Other Production 11,703,521$ 2,182,523$ 13,886,044$ 615
616 Total Production Labor 11,703,521$ 2,182,523$ 13,886,044$ 617
618 Transmission Labor
619 Transmission Operations
620 Supervision & Engineering -$ -$ -$ 621 Load Dispatch -$ -$ -$ 622 Station Equipment -$ -$ -$ 623 Overhead Lines -$ -$ -$ 624 Underground Lines -$ -$ -$ 625 General Labor -$ -$ -$ 626 Miscellaneous -$ -$ -$ 627 Rents -$ -$ -$ 628 Total Transmission Operations -$ -$ -$ 629
630 Transmission Maintenance
631 Supervision & Engineering -$ -$ -$ 632 Structures -$ -$ -$ 633 Station Equipment -$ -$ -$ 634 Overhead Lines -$ -$ -$ 635 Underground Lines -$ -$ -$ 636 Miscellaneous -$ -$ -$ 637 Total Transmission Maintenance -$ -$ -$ 638
639 Wheeling
640 Wheeling -$ -$ -$ 641 Wheeling -$ -$ -$ 642 Total Wheeling -$ -$ -$ 643
644 Total Transmission Labor -$ -$ -$ 645
646 Distribution Labor
647 Distribution Operations
648 Electric Operations 6100000 9,850,945$ 3,321,580$ 13,172,525$ 649 PU Electric Field Operations 6105000 13,340,811$ 2,452,811$ 15,793,621$ 650 Energy Deliv. Engineering 6110000 8,227,098$ 2,797,112$ 11,024,210$ 651 Customer Engineering-GIS 6115000 -$ -$ -$ 652 Underground Lines -$ -$ -$ 653 Street Lighting -$ -$ -$ 654 Metering -$ -$ -$ 655 Customer Installations -$ -$ -$ 656 Miscellaneous -$ -$ -$ 657 Rents -$ -$ -$ 658 Total Distribution Operations 31,418,854$ 8,571,503$ 39,990,356$ 659
660 Distribution Maintenance
661 Supervision & Engineering -$ -$ -$ 662 Structures -$ -$ -$ 663 Stations Equipment -$ -$ -$ 664 Overhead Lines -$ -$ -$ 665 Underground Lines -$ -$ -$ 666 Transformers -$ -$ -$ 667 Street Lighting -$ -$ -$ 668 Metering -$ -$ -$ 669 Miscellaneous -$ -$ -$ 670 Total Distribution Maintenance -$ -$ -$ 671
672 Total Distribution Labor 31,418,854$ 8,571,503$ 39,990,356$ 673
1 2
3 A B C D E F
Functional Unbundling
Line Fiscal Year Test Year Adjusted
No. Item Account/ID 2021 Adjustment Test Year
677
678
679
680
681
682
683
684
685
686
687
688
689
690
691
692
693
694
695
696
697
698
699
700
701
702
703
704
705
706
707
708
709
710
711
712
713
714
715
716
717
718
719
720
721
722
723
724
725
726
727
728
729
730
731
732
733
734
735
736
737
738
739
740
741
742
743
744
745
746
747
748
749
674 Customer Labor
675 Customer Accounting Expense
676 Pub Util Business Support 6004000 1,264,217$ 248,534$ 1,512,751$ 677 Pub Util Admin-Utility Billing 6005000 955,955$ 242,709$ 1,198,664$ 678 Pub Util Admin-Customer Service 6015000 3,607,510$ 818,698$ 4,426,209$ 679 Pub Util Admin-Marketing Service 6020000 1,554,695$ 1,062,765$ 2,617,460$ 680 Miscellaneous -$ -$ -$ 681 Total Customer Accounting Expense 7,382,378$ 2,372,706$ 9,755,084$ 682
683 Customer Service Expense
684 Customer Engineering-GIS -$ -$ -$ 685 Customer Assistance -$ -$ -$ 686 Advertisement / Marketing -$ -$ -$ 687 Miscellaneous -$ -$ -$ 688 Total Customer Service Expense -$ -$ -$ 689
690 Sales Expense
691 Sales Expense -$ -$ -$ 692 Demonstrations & Selling -$ -$ -$ 693 Miscellaneous Sales Expense -$ -$ -$ 694 Total Sales Expense -$ -$ -$ 695
696 Total Customer Labor 7,382,378$ 2,372,706$ 9,755,084$ 697
698 Total Labor Expense excluding A&G 50,504,752$ 13,126,732$ 63,631,485$ 699
700 Administrative & General Labor
701 Pub Util Admin-Management Services 6000000 14,491,264$ (8,974,306)$ 5,516,958$ 702 Pub Util Admin-Field Services 6010000 2,424,716$ 1,207,521$ 3,632,238$ 703 Legislative & Regulator Risk 6025000 -$ 237,381$ 237,381$ 704 Outside Services -$ -$ -$ 705 Property Insurance -$ -$ -$ 706 Injuries and Damages -$ -$ -$ 707 Electric Utility Communication Labor -$ -$ -$ 708 Miscellaneous -$ -$ -$ 709 Rents -$ -$ -$ 710 Transportation Pool General Labor -$ -$ -$ 711 Maintenance of General Plant -$ -$ -$ 712 N/A -$ -$ -$ 713 Total Administrative & General Labor 16,915,980$ (7,529,403)$ 9,386,577$ 714
715 Total Labor Expense 67,420,732$ 5,597,329$ 73,018,062$ 716
717 Allocation Factors
718
719
720 Production
721
722 Transmission
723
724 Distribution
725
726 Customer
727
728 Direct Assign
729
730 Total Gross Plant in Service
731
732 Net Plant in Service
733
734 Revenue Requirement x/ Direct Assignment
735
736 Total Labor
737
738 Revenue Requirement Excluding Transmission
739
740 Rev Req / City
741
742 Administrative and General ALLOCATOR FROM WP-10
743
744 CIP
745
746 Not Applicable
1 2
3 4
5 6
7 8
9 10
11 12
13 14
15 16
17 18
19 20
21 22
23 24
25 26
27 28
29 30
31 32
33 34
35 36
37 38
39 40
41 42
43 44
45 46
47 48
49 50
51 52
53 54
55 56
57 A B C
Functional Unbundling
Line
No. Item Account/ID
1 Production O&M
2 Steam Production Operation
3 Supervision & Engineering 500
4 Fuel (Transportation & Handling) 501
5 Steam Power Fuel - Gas 50110
6 Steam Power Fuel - Oil 50120
7 Steam Power Fuel - Coal 50130
8 Steam Expense 502
9 Electric Expense 505
10 Miscellaneous 506
11 Rent 507
12 Subtotal Steam Production Opeation
13 14 Steam Production Maintenance
15 Supervision & Engineering 510
16 Structures 511
17 Boilers 512
18 Electric Plant 513
19 Miscellaneous Labor 515
20 Subtotal Steam Production Maintenance
21 22 Nuclear Production Operation
23 Supervision & Engineering 517
24 Nuclear Fuel Expense 518
25 Electric Expense - Turbine Generators 523
26 Reserved NA
27 Miscellaneous Power Expenses 524
28 Reserved NA
29 Subtotal Nuclear Production Operation
30 31 Nuclear Production Maintenance
32 Supervision & Engineering 528
33 Reserved NA
34 Reserved NA
35 Reserved NA
36 Miscellaneous Plant 530
37 Subtotal Nuclear Production Maintenance
38 39 Combined Cycle Operation
40 Supervision & Engineering NA
41 Fuel NA
42 Combined Cycle Fuel - Gas NA
43 Combined Cycle Fuel - Oil NA
44 Generation Expense NA
45 Miscellaneous NA
46 Subtotal Combined Cycle Operation
47 48 Combined Cycle Maintenance
49 Supervision & Engineering NA
50 Structures NA
51 Electric Plant NA
52 Miscellaneous Plant NA
53 Subtotal Combined Cycle Maintenance
54 G H I J
Allocation
Factor Production Transmission Distribution
NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ Production 321,200$ -$ -$ NA -$ -$ -$ 321,200$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ Production 541,428$ -$ -$ 541,428$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ -$ -$ -$ 1 2
3 A B C
Functional Unbundling
Line
No. Item Account/ID
58 59
60 61
62 63
64 65
66 67
68 69
70 71
72 73
74 75
76 77
78 79
80 81
82 83
84 85
86 87
88 89
90 91
92 93
94 95
96 97
98 99
100
101
102
103
104
105
106
107
108
109
110
111
112
113
114
115
116
117
118
119
120
121
122
123
124
125
126
127
128
129
130
131
132
133
134
135
55 Other Production
56 Intermountain Power (take or pay) 546
57 Fuel Expense 547
58 Hoover (take or pay) 548
59 Misc. Other Power Generation 549
60 Palo Verde Power (take or pay) 550
61 Deseret Power (take or pay) 552
62 Maint/Generating & Elec. Equip. 553
63 System Load Control 556
64 Other Expenditures 557
65 Purchased Power 555
66 Purchased Power - Energy Direct Assignment 55501
67 Subtotal Other Production
68 69 Total Production O&M
70 71 Fuel & Purchased Power
72 73 Total Production O&M less Fuel & Purchased Power
74 75 Transmission O&M
76 Transmission Operation
77 Supervision & Engineering 560
78 Load Dispatch 561
79 Station Equipment 562
80 Overhead Lines 563
81 Underground Lines 564
82 Miscellaneous 566
83 Rents 567
84 Subtotal Transmission Operation
85 86 Transmission Maintenance
87 Supervision & Engineering 568
88 Structures 569
89 Station Equipment 570
90 Overhead Lines 571
91 Underground Lines 572
92 Miscellaneous 573
93 Subtotal Transmission Maintenance
94 95 Wheeling
96 Transmission Cost Fixed 565
97 Transmission Cost Variable 565
98 Subtotal Wheeling
99 100 Total Transmission O&M
101
102 Distribution O&M
103 Distribution Operations
104 Operation Maintenance and Engineering 580
105 Load Dispatch 581
106 Station Equipment 582
107 Overhead Lines 583
108 Underground Lines 584
109 Street Lighting & Signal Expenses 585
110 Metering 586
111 Customer Installations 587
112 Miscellaneous 588
113 Rents 589
114 Subtotal Distribution Operations
115
116 Distribution Maintenance
117 Supervision 590
118 Structures 591
119 Station Equipment 592
120 Overhead Lines 593
121 Underground Lines 594
122 Transformers 595
123 Street Lighting & Signals 596
124 Metering 597
125 Miscellaneous 598
126 Subtotal Distribution Maintenance
127
128 Total Distribution O&M
129
130 Customer O&M
131 Customer Accounting Expense
132 Supervision 901

G H I J
Allocation
Factor Production Transmission Distribution
Production 9,902,789$ -$ -$ Production 19,294,411$ -$ -$ Production 926,962$ -$ -$ NA -$ -$ -$ Production 4,730,380$ -$ -$ NA -$ -$ -$ Production 4,228,576$ -$ -$ Production 3,650,747$ -$ -$ Production 14,617,013$ -$ -$ Production 119,746,439$ -$ -$ NA -$ -$ -$ 177,097,317$ -$ -$ 177,959,946$ -$ -$
154,600,981$ -$ -$
23,358,965$ -$ -$
NA -$ -$ -$ NA -$ -$ -$ Distribution -$ -$ 72,393$ NA -$ -$ -$ NA -$ -$ -$ Distribution -$ -$ 185,629$ NA -$ -$ -$ -$ -$ 258,023$ NA -$ -$ -$ NA -$ -$ -$ Distribution -$ -$ 115,430$ Distribution -$ -$ 3,415$ NA -$ -$ -$ Distribution -$ -$ 739,297$ -$ -$ 858,143$ Transmission -$ 19,914,764$ -$ Transmission -$ 42,940,708$ -$ -$ 62,855,472$ -$ -$ 62,855,472$ 1,116,166$ Distribution -$ -$ 5,154,971$ Distribution -$ -$ 3,219,260$ Distribution -$ -$ 19,467$ Distribution -$ -$ 91$ Distribution -$ -$ 4,616$ NA -$ -$ -$ Distribution -$ -$ 107,992$ Distribution -$ -$ 136,827$ Distribution -$ -$ 89,726$ NA -$ -$ -$ -$ -$ 8,732,950$ NA -$ -$ -$ Distribution -$ -$ 68,920$ Distribution -$ -$ 1,249,308$ Distribution -$ -$ 7,724,053$ Distribution -$ -$ 2,876,410$ Distribution -$ -$ 78,936$ Distribution -$ -$ 1,226,264$ Distribution -$ -$ 353,651$ Distribution -$ -$ 706,008$ -$ -$ 14,283,549$ -$ -$ 23,016,500$ Customer -$ -$ -$ 1 2
3 A B C
Functional Unbundling
Line
No. Item Account/ID
136
137
138
139
140
141
142
143
144
145
146
147
148
149
150
151
152
153
154
155
156
157
158
159
160
161
162
163
164
165
166
167
168
169
170
171
172
173
174
175
133 Meter Reading 902
134 Customer Records and Collection Expenses 903
135 Reserved NA
136 Uncollectible Accounts 904
137 Miscellaneous 905
138 Subtotal Customer Accounting Expense
139
140 Other Customer Costs
141 Supervision 907
142 Customer Assistance 908
143 Advertisement 909
144 Miscellaneous 910
145 Subotal Other Customer Costs
146
147 Sales Expense
148 Sales Expense - Supervision 911
149 Demonstrations & Selling 912
150 Advertising Expenses 913
151 Miscellaneous Sales Expense 916
152 Subtotal Sales Expense
153
154 Total Customer O&M
155
156 Administrative & General Expense
157 Administrative Salaries & Misc. Labor 920
158 Office Supplies & Expense 921
159 Interdepartmental Charges 922
160 Outside Services 923
161 Property Insurance 924
162 Injuries and Damages 925
163 Employee Pensions and Benefits 926
164 Franchise Requirements 927
165 Compliance & Consultants (Regulatory Commission Expense) 928 166 General Advertising Expense 930
167 Rents 931
168 Miscellaneous General Expenses 933
169 Maintenance of General Plant 932
170 Duplicate Charges - Credit 929
171 Subtotal Administrative & General Expense
172

G H I J
Allocation
Factor Production Transmission Distribution
Customer -$ -$ -$ Customer -$ -$ -$ NA -$ -$ -$ Customer -$ -$ -$ NA -$ -$ -$ -$ -$ -$ NA -$ -$ -$ Customer -$ -$ -$ Customer -$ -$ -$ NA -$ -$ -$ -$ -$ -$ NA -$ -$ -$ Customer -$ -$ -$ Customer -$ -$ -$ NA -$ -$ -$ -$ -$ -$ -$ -$ -$ Total Labor 3,488,734$ -$ 9,326,671$ A&G 260,756$ -$ 338,373$ Total Labor (6,248,053)$ -$ (16,703,346)$ A&G 2,246,125$ -$ 2,914,705$ NA -$ -$ -$ NA -$ -$ -$ Total Labor 5,176,576$ -$ 13,838,893$ NA -$ -$ -$ A&G 3,949$ -$ 5,125$ A&G 774$ -$ 1,004$ Rev. Req. 970,104$ 179,809$ 423,203$ A&G 1,273,426$ -$ 1,652,473$ A&G 53,788$ -$ 69,798$ NA -$ -$ -$ 7,226,180$ 179,809$ 11,866,899$ 1 2
3 A B C
Functional Unbundling
Line
No. Item Account/ID
176
177
178
179
180
181
182
183
184
185
186
187
188
189
190
191
192
193
194
195
196
197
198
199
200
201
202
203
204
205
206
207
208
209
210
211
212
213
214
215
216
217
218
219
220
221
222
223
224
225
226
227
228
229
230
231
232
233
234
235
236
237
238
173 Miscellaneous and Clearing Accounts
174 General Government Charges 701
175 Expenses Transferred from Electric 702
176 IDI Utility Charges 703
177 Removal Expenses 704
178 Taxes 707
179 Stores Expenses 781
180 Transportation Expenses 782
181 Tool and Shop Expenses 783
182 Insurance 788
183 Non-Operating Expenses 790
184 Subtotal Miscellaneous and Clearing Accounts
185
186 Total O&M Expense
187
188 Total O&M Expense less Purchased Power
189
190 Additional Expenses & Deductions
191 Debt Service
192 Generation
193 Transmission
194 Distribution
195 Customer
196 New Debt
197 Total Debt Service
198
199 Taxes and Transfer to General Fund
200 General Fund Transfer
201 Other
202 Other
203 Other
204 Subtotal Taxes and Transfer to General Fund
205
206 Capital Paid from Current Earnings
207 Production
208 Transmission
209 Distribution
210 Customer
211 Street Lighting Capital
212 NA
213 Sutotal Capital Paid from Current Earnings
214
215 Reserves - Additional Cash Requirements Minimum Target 216
217 Total Additional Expenses & Deductions
218
219 Subtotal Revenue Requirement
220
221 Other Income
222 Other Operating Revenue:
223 Uncollectibles
224 Diversion 344400
225 Service Connect Charges - Electric 344410
226 Misc Service Revenues - Electric 344491
227 Misc Operating Revenues - Electric 344492
228 Corona Fees- Rev 344493
229 Cap and Trade Auction 344511
230 REC Sale 344523
231 RA Capacity Sale 344522
232 Low Carbon Fuel Standard Credits 344514
233 Non Energy Receipts ABC Admin OH 344513
234 Subtotal Other Operating Revenue
235

G H I J
Allocation
Factor Production Transmission Distribution
Rev. Req. x Trans 10,541,865$ -$ 4,598,838$ Rev. Req. x Trans 3,111,947$ -$ 1,357,572$ Rev. Req. x Trans 27,625$ -$ 12,051$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ Net Plant 396,414$ -$ 1,190,785$ Net Plant (341,930)$ -$ (1,027,120)$ Net Plant 261,921$ -$ 786,782$ NA -$ -$ -$ 13,997,842$ -$ 6,918,909$ 199,183,968$ 63,035,281$ 42,918,473$
44,582,987$ 63,035,281$ 42,918,473$
Production 18,746,160$ -$ -$ Transmission -$ 3,107,916$ -$ Distribution -$ -$ 27,477,924$ NA -$ -$ -$ CIP 75,924$ -$ 21,106,476$ 18,822,084$ 3,107,916$ 48,584,400$ Rev. Req. 29,345,394$ 5,439,183$ 12,801,788$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ 29,345,394$ 5,439,183$ 12,801,788$ Production 17,623$ -$ -$ Transmission -$ -$ -$ Distribution -$ -$ 4,001,377$ Customer -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ 17,623$ -$ 4,001,377$ Rev. Req. 3,570,740$ 661,838$ 1,557,718$ 51,755,842$ 9,208,938$ 66,945,282$
250,939,809$ 72,244,219$ 109,863,755$
Customer -$ -$ -$ NA -$ -$ -$ Customer -$ -$ -$ Customer -$ -$ -$ Rev. Req. 5,545$ 1,028$ 2,419$ NA -$ -$ -$ Production -$ -$ -$ Rev. Req. -$ -$ -$ Rev. Req. 1,037,821$ 192,361$ 452,744$ Rev. Req. 1,148,560$ 212,886$ 501,054$ Rev. Req. / City 30,026$ 5,565$ 13,099$ 2,221,952$ 411,840$ 969,316$ 1 2
3 A B C
Functional Unbundling
Line
No. Item Account/ID
239
240
241
242
243
244
245
246
247
248
249
250
251
252
253
254
255
256
257
258
259
260
261
262
263
264
265
266
267
268
269
270
271
272
273
274
275
276
277
278
279
280
281
282
283
284
285
236 Other Non-Operating Revenues (Expenses):
237 Gain (Loss) on retirement of utility plant N/A
238 Interest Income N/A
239 Corona Fees - Rev 344493
240 Misc. Settlement Reimbursement 344494
241 Late Payment Penalties 353400
242 Land and Building Rental 373100
243 Other Property Rental 373120
244 Pole Attachments 373125
245 Substation Operation & Maintenance 373126
246 Substation Leasing 373127
247 Communication Services 373128
248 CIS User Fee 373132
249 Refunds and Reimbursements 374000
250 Miscellaneous Receipts 374200
251 Cash Over/Shortage 374207
252 Asset Forfeiture Revenue 374500
253 Bad Debt Recovery 374800
254 Settlement Recovery 374801
255 Settlement Recovery - SONGS 374802
256 Liquidated Damages 374810
257 Sale of Salvage Materials 380030
258 Damage Claim Recoveries 380100
259 Operating Transfer from 650 Fund 985650
260 Utilization Charges 61250000
261 Subtotal Other Non-Operating Revenue
262
263 Wholesale Sales
264
265 Transmission Revenue
266
267 Total Other Income
268
269 Total Retail Revenue Requirement
270 Reconcile to RPU Proforma
271 Adjustment for Cap and Trade Auction
272 Reconciled Total Retail Revenue Requirement
273 Difference from Proforma
274 % Difference from Proforma
275 Current Scenario Scenario 2
276 Revenue from Current Retail Rates - RPU Projections from Proforma 277 Residential
278 Commercial - Flat
279 Commercial - Demand
280 Industrial - TOU
281 Other
282 Total Revenue from Current Retail Rates

G H I J
Allocation
Factor Production Transmission Distribution
Distribution -$ -$ -$ Rev. Req. -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ Rev. Req. 1,673,787$ 310,237$ 730,181$ Rev. Req. 42,843$ 7,941$ 18,690$ Distribution -$ -$ 268,470$ NA -$ -$ -$ NA -$ -$ -$ Distribution -$ -$ 113,460$ NA -$ -$ -$ Distribution -$ -$ 10,535$ Rev. Req. 238,501$ 44,206$ 104,045$ Rev. Req. -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ Rev. Req. -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ Rev. Req. 20,869$ 3,868$ 9,104$ Rev. Req. -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ 1,975,999$ 366,252$ 1,254,484$ Production -$ -$ -$ Transmission -$ 25,732,402$ -$ 4,197,951$ 26,510,494$ 2,223,800$
246,741,858$ 45,733,725$ 107,639,955$
1 2
3 A B C
Functional Unbundling
Line
No. Item Account/ID
286
287
288
289
290
291
292
293
294
295
296
297
298
299
300
301
302
303
304
305
306
307
308
309
310
311
312
313
314
315
316
317
318
319
320
321
322
323
324
325
326
327
328
329
330
331
332
333
334
335
336
337
338
339
340
341
283
284 PLANT IN SERVICE
285
286 Gross Plant in Service
287 Intangible Plant
288 Organization 301
289 Franchises and Consents 302
290 Misc. Intangible Plant 303
291 Misc. Computer Software 3030
292 Subtotal Intangible Plant
293
294 Production Plant
295 Steam Production
296 Land and Land Rights 310
297 Structures & Improvements 311
298 Boiler Plant Equipment 312
299 Engines and Engine Generators 313
300 Turbo-Generator Units 314
301 Accessory Electric Equipment 315
302 Misc. Power Plant Equipment 316
303 Subtotal Steam Produciton
304
305 Hydraulic Production
306 Land and Land Rights 330
307 Structures & Improvements 331
308 Reservoirs, Dams and Water Ways 332
309 Water Wheel, Turbine and Generator 333
310 Accessory Electric Equipment 334
311 Misc. Power Plant Equipment 335
312 Roads, Railroads and Bridges 336
313 Subtotal Hydraulic Production
314
315 Combustion Turbine & Other Production
316 Land and Land Rights 340
317 Structures & Improvements 341
318 Fuel Holders, Prod, & Acc. 342
319 Prime Movers 343
320 Generators & Other Production 344
321 Accessory Electric Equipment 345
322 Misc. Production Plant 2000
323 Subtotal Combustion Turbine & Other Production
324
325 Total Production Plant
326
327 Transmission Plant
328 Land and Land Rights 350
329 Reserved 351
330 Structures & Improvements 352
331 Station Equipment - System 353
332 Towers and Fixtures 354
333 Poles and Fixtures 355
334 Overhead Conductor 356
335 Underground Conductor 357
336 Underground Conduit 358
337 Misc. Transmission Plant 359
338 Subtotal Transmission Plant

G H I J
Allocation
Factor Production Transmission Distribution
NA -$ -$ -$ NA -$ -$ -$ Net Plant 8,151,448$ -$ 24,486,080$ NA -$ -$ -$ 8,151,448$ -$ 24,486,080$ Production 17,142$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ 17,142$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ -$ -$ -$ Production 1,038,596$ -$ -$ Production 703,469$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ Production 268,544,986$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ 270,287,051$ -$ -$ 278,455,641$ -$ 24,486,080$ Distribution -$ -$ 2,683,037$ NA -$ -$ -$ Distribution -$ -$ 971,062$ Distribution -$ -$ 4,790,451$ Distribution -$ -$ 3,567,512$ Distribution -$ -$ 22,928,628$ Distribution -$ -$ 8,716,136$ Distribution -$ -$ 5,748,846$ Distribution -$ -$ 2,356,742$ NA -$ -$ -$ -$ -$ 51,762,414$ 1 2
3 A B C
Functional Unbundling
Line
No. Item Account/ID
342
343
344
345
346
347
348
349
350
351
352
353
354
355
356
357
358
359
360
361
362
363
364
365
366
367
368
369
370
371
372
373
374
375
376
377
378
379
380
381
382
383
384
385
386
387
388
389
390
391
392
393
394
395
396
397
398
399
400
401
402
403
404
405
406
407
408
339
340 Distribution Plant
341 Land and Land Rights 360
342 Structures & Improvements 361
343 Station Equipment 362
344 Misc. Plant 363
345 Towers and Fixtures 364
346 Overhead Conductor 365
347 Undgeround Conduit 366
348 Underground Conductor 367
349 Line Transformers 368
350 Services 369
351 Meters 370
352 Inst. on Customer Premises 371
353 Street Light / Signal System 373
354 Total Distribution Plant
355
356 Subtotal Plant Before General
357
358 General Plant
359 Land and Land Rights 389
360 Structures & Improvements 390
361 Structures & Improvements - Other 3900
362 Office Furniture & Equipment 391
363 Info System Computers 3910
364 Transportation Equipment 392
365 Stores Equipment 393
366 Tools, Shop & Garage Equipment 394
367 Laboratory Equipment 395
368 Power Operated Equipment 396
369 Communication Equipment 397
370 Miscellaneous Equipment 398
371 Other Tangible Property 399
372 Subtotal General Plant
373
374 Total Gross Plant in Service
375
376
377 Accumulated Depreciation
378 Intangible Plant
379 Organization 301
380 Franchises and Consents 302
381 Misc. Intangible Plant 303
382 Misc. Computer Software 3030
383 Subtotal Intangible Plant
384
385 Production Plant
386 Steam Production
387 Land and Land Rights 310
388 Structures & Improvements 311
389 Boiler Plant Equipment 312
390 Engines and Engine Generators 313
391 Turbo-Generator Units 314
392 Accessory Electric Equipment 315
393 Misc. Power Plant Equipment 316
394 Subtotal Steam Produciton
395
396 Hydraulic Production
397 Land and Land Rights 330
398 Structures & Improvements 331
399 Reservoirs, Dams and Water Ways 332
400 Water Wheel, Turbine and Generator 333
401 Accessory Electric Equipment 334
402 Misc. Power Plant Equipment 335
403 Roads, Railroads and Bridges 336
404 Subtotal Hydraulic Production
405

G H I J
Allocation
Factor Production Transmission Distribution
Distribution -$ -$ 41,183,402$ Distribution -$ -$ 15,397,298$ Distribution -$ -$ 160,729,872$ NA -$ -$ -$ Distribution -$ -$ 44,909,055$ Distribution -$ -$ 45,300,634$ Distribution -$ -$ 131,830,676$ Distribution -$ -$ 137,105,611$ Distribution -$ -$ 63,370,705$ Distribution -$ -$ 29,359,860$ Distribution -$ -$ 21,963,893$ Distribution -$ -$ 851,584$ Distribution -$ -$ 55,987,877$ -$ -$ 747,990,468$ 278,455,641$ -$ 824,238,961$ Net Plant 2,027,929$ -$ 6,091,682$ Net Plant 17,261,298$ -$ 51,851,098$ NA -$ -$ -$ Net Plant 2,203,344$ -$ 6,618,611$ NA -$ -$ -$ Net Plant 3,174,192$ -$ 9,534,934$ Net Plant 11,370$ -$ 34,153$ Net Plant 102,634$ -$ 308,300$ Net Plant 203,456$ -$ 611,161$ Net Plant 420,228$ -$ 1,262,319$ Net Plant 5,721,356$ -$ 17,186,342$ Net Plant 292,335$ -$ 878,145$ Net Plant 4,731$ -$ 14,213$ 31,422,873$ -$ 94,390,958$ 309,878,514$ -$ 918,629,919$ NA -$ -$ -$ NA -$ -$ -$ Net Plant 8,151,448$ -$ 24,486,080$ NA -$ -$ -$ 8,151,448$ -$ 24,486,080$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ -$ -$ -$ 1 2
3 A B C
Functional Unbundling
Line
No. Item Account/ID
409
410
411
412
413
414
415
416
417
418
419
420
421
422
423
424
425
426
427
428
429
430
431
432
433
434
435
436
437
438
439
440
441
442
443
444
445
446
447
448
449
450
451
452
453
454
455
456
457
458
459
460
461
462
463
464
465
466
467
468
469
470
406 Combustion Turbine & Other Production
407 Land and Land Rights 340
408 Structures & Improvements 341
409 Fuel Holders, Prod, & Acc. 342
410 Prime Movers 343
411 Generators & Other Production 344
412 Accessory Electric Equipment 345
413 Misc. Production Plant 2000
414 Subtotal Combustion Turbine & Other Production
415
416 Total Production Plant
417
418 Transmission Plant
419 Land and Land Rights 350
420 Reserved 351
421 Structures & Improvements 352
422 Station Equipment - System 353
423 Towers and Fixtures 354
424 Poles and Fixtures 355
425 Overhead Conductor 356
426 Underground Conductor 357
427 Underground Conduit 358
428 Misc. Transmission Plant 359
429 Subtotal Transmission Plant
430
431 Distribution Plant
432 Land and Land Rights 360
433 Structures & Improvements 361
434 Station Equipment 362
435 Misc. Plant 363
436 Towers and Fixtures 364
437 Overhead Conductor 365
438 Undgeround Conduit 366
439 Underground Conductor 367
440 Line Transformers 368
441 Services 369
442 Meters 370
443 Inst. on Customer Premises 371
444 Street Light / Signal System 373
445 Total Distribution Plant
446
447 Subtotal Plant Before General
448
449 General Plant
450 Land and Land Rights 389
451 Structures & Improvements 390
452 Structures & Improvements - Other 3900
453 Office Furniture & Equipment 391
454 Info System Computers 3910
455 Transportation Equipment 392
456 Stores Equipment 393
457 Tools, Shop & Garage Equipment 394
458 Laboratory Equipment 395
459 Power Operated Equipment 396
460 Communication Equipment 397
461 Miscellaneous Equipment 398
462 Other Tangible Property 399
463 Subtotal General Plant
464
465 Total Accumulated Depreciation
466
467

G H I J
Allocation
Factor Production Transmission Distribution
NA -$ -$ -$ Production 155,300$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ Production 111,722,271$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ 111,877,570$ -$ -$ 120,029,018$ -$ 24,486,080$ NA -$ -$ -$ NA -$ -$ -$ Distribution -$ -$ 710,957$ Distribution -$ -$ 4,522,181$ Distribution -$ -$ 1,251,520$ Distribution -$ -$ 8,164,974$ Distribution -$ -$ 3,637,134$ Distribution -$ -$ 1,856,873$ Distribution -$ -$ 1,257,665$ NA -$ -$ -$ -$ -$ 21,401,303$ NA -$ -$ -$ Distribution -$ -$ 4,266,581$ Distribution -$ -$ 56,848,424$ NA -$ -$ -$ Distribution -$ -$ 18,346,185$ Distribution -$ -$ 24,052,960$ Distribution -$ -$ 37,896,415$ Distribution -$ -$ 68,490,579$ Distribution -$ -$ 33,474,633$ Distribution -$ -$ 15,070,839$ Distribution -$ -$ 7,206,731$ Distribution -$ -$ 762,056$ Distribution -$ -$ 36,039,497$ -$ -$ 302,454,899$ 120,029,018$ -$ 348,342,282$ NA -$ -$ -$ Net Plant 4,062,642$ -$ 12,203,743$ NA -$ -$ -$ Net Plant 1,639,616$ -$ 4,925,231$ NA -$ -$ -$ Net Plant 2,564,873$ -$ 7,704,605$ Net Plant 11,370$ -$ 34,153$ Net Plant 88,246$ -$ 265,082$ Net Plant 203,456$ -$ 611,161$ Net Plant 369,851$ -$ 1,110,992$ Net Plant 4,279,791$ -$ 12,856,036$ Net Plant 267,190$ -$ 802,611$ Net Plant 1,577$ -$ 4,738$ 13,488,612$ -$ 40,518,353$ 133,517,631$ -$ 388,860,635$ 1 2
3 A B C
Functional Unbundling
Line
No. Item Account/ID
471
472
473
474
475
476
477
478
479
480
481
482
483
484
485
486
487
488
489
490
491
492
493
494
495
496
497
498
499
500
501
502
503
504
505
506
507
508
509
510
511
512
513
514
515
516
517
518
519
520
521
522
523
524
525
526
527
528
529
530
531
532
533
534
535
536
537
538
539
540
541
542
468 Net Plant in Service
469 Intangible Plant
470 Organization 301
471 Franchises and Consents 302
472 Misc. Intangible Plant 303
473 Misc. Computer Software 3030
474 Subtotal Intangible Plant
475
476 Production Plant
477 Steam Production
478 Land and Land Rights 310
479 Structures & Improvements 311
480 Boiler Plant Equipment 312
481 Engines and Engine Generators 313
482 Turbo-Generator Units 314
483 Accessory Electric Equipment 315
484 Misc. Power Plant Equipment 316
485 Subtotal Steam Produciton
486
487 Hydraulic Production
488 Land and Land Rights 330
489 Structures & Improvements 331
490 Reservoirs, Dams and Water Ways 332
491 Water Wheel, Turbine and Generator 333
492 Accessory Electric Equipment 334
493 Misc. Power Plant Equipment 335
494 Roads, Railroads and Bridges 336
495 Subtotal Hydraulic Production
496
497 Combustion Turbine & Other Production
498 Land and Land Rights 340
499 Structures & Improvements 341
500 Fuel Holders, Prod, & Acc. 342
501 Prime Movers 343
502 Generators & Other Production 344
503 Accessory Electric Equipment 345
504 Misc. Production Plant 2000
505 Subtotal Combustion Turbine & Other Production
506
507 Total Production Plant
508
509 Transmission Plant
510 Land and Land Rights 350
511 Reserved 351
512 Structures & Improvements 352
513 Station Equipment - System 353
514 Towers and Fixtures 354
515 Poles and Fixtures 355
516 Overhead Conductor 356
517 Underground Conductor 357
518 Underground Conduit 358
519 Misc. Transmission Plant 359
520 Subtotal Transmission Plant
521
522 Distribution Plant
523 Land and Land Rights 360
524 Structures & Improvements 361
525 Station Equipment 362
526 Misc. Plant 363
527 Towers and Fixtures 364
528 Overhead Conductor 365
529 Undgeround Conduit 366
530 Underground Conductor 367
531 Line Transformers 368
532 Services 369
533 Meters 370
534 Inst. on Customer Premises 371
535 Street Light / Signal System 373
536 Total Distribution Plant
537
538 Subtotal Plant Before General
539

G H I J
Allocation
Factor Production Transmission Distribution
NA -$ -$ -$ NA -$ -$ -$ Net Plant 4,817,894$ -$ 14,472,440$ NA -$ -$ -$ 4,817,894$ -$ 14,472,440$ Production 17,142$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ 17,142$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ -$ -$ -$ Production 1,038,596$ -$ -$ Production 548,169$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ Production 156,822,716$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ 158,409,481$ -$ -$ 163,244,517$ -$ 14,472,440$ Distribution -$ -$ 2,683,037$ NA -$ -$ -$ Distribution -$ -$ 260,105$ Distribution -$ -$ 268,270$ Distribution -$ -$ 2,315,992$ Distribution -$ -$ 14,763,654$ Distribution -$ -$ 5,079,002$ Distribution -$ -$ 3,891,973$ Distribution -$ -$ 1,099,077$ NA -$ -$ -$ -$ -$ 30,361,110$ Distribution -$ -$ 41,183,402$ Distribution -$ -$ 11,130,717$ Distribution -$ -$ 103,881,448$ NA -$ -$ -$ Distribution -$ -$ 26,562,871$ Distribution -$ -$ 21,247,674$ Distribution -$ -$ 93,934,261$ Distribution -$ -$ 68,615,032$ Distribution -$ -$ 29,896,072$ Distribution -$ -$ 14,289,021$ Distribution -$ -$ 14,757,162$ Distribution -$ -$ 89,528$ Distribution -$ -$ 19,948,380$ -$ -$ 445,535,569$ 163,244,517$ -$ 490,369,119$ 1 2
3 A B C
Functional Unbundling
Line
No. Item Account/ID
543
544
545
546
547
548
549
550
551
552
553
554
555
556
557
558
559
560
561
562
563
564
565
566
567
568
569
570
571
572
573
574
575
576
577
578
579
580
581
582
583
584
585
586
587
588
589
590
591
592
593
594
595
596
597
598
599
600
601
602
603
604
605
606
607
608
609
610
611
612
540 General Plant
541 Land and Land Rights 389
542 Structures & Improvements 390
543 Structures & Improvements - Other 3900
544 Office Furniture & Equipment 391
545 Info System Computers 3910
546 Transportation Equipment 392
547 Stores Equipment 393
548 Tools, Shop & Garage Equipment 394
549 Laboratory Equipment 395
550 Power Operated Equipment 396
551 Communication Equipment 397
552 Miscellaneous Equipment 398
553 Other Tangible Property 399
554 Subtotal General Plant
555
556 Total Net Plant in Service
557
558
559 Labor
560
561 Production Labor
562 Steam Production Operation
563 Supervision & Engineering
564 Fuel (Transportation & Handling)
565 Steam Expense
566 Electric Expense
567 Miscellaneous
568 Rent
569 Total Steam Production Operation
570
571 Steam Production Maintenance
572 Supervision & Engineering
573 Structures
574 Boilers
575 Electric Plant
576 Miscellaneous Labor
577 Total Steam Production Maintenance
578
579 Hydro Production Operation
580 Supervision & Engineering
581 Water for Power
582 Hydraulic Expense
583 Electric Expense
584 Miscellaneous
585 Rent
586 Total Hydro Production Operation
587
588 Hydro Production Maintenance
589 Supervision & Engineering
590 Structures
591 Reservoirs & Dams
592 Electric Plant
593 Miscellaneous Plant
594 Total Hydro Production Maintenance
595
596 Combined Cycle Operation
597 Labor
598 Fuel Handling
599 Generation Expense
600 Miscellaneous Plant
601 Total Combined Cycle Operation
602
603 Combined Cycle Maintenance
604 Supervision & Engineering
605 Structures
606 Electric Plant
607 Miscellaneous Plant
608 Total Combined Cycle Maintenance
609

G H I J
Allocation
Factor Production Transmission Distribution
Net Plant 2,027,929$ -$ 6,091,682$ Net Plant 13,198,656$ -$ 39,647,355$ NA -$ -$ -$ Net Plant 563,728$ -$ 1,693,379$ NA -$ -$ -$ Net Plant 609,319$ -$ 1,830,329$ NA -$ -$ -$ Net Plant 14,387$ -$ 43,218$ Net Plant (0)$ -$ (0)$ Net Plant 50,377$ -$ 151,327$ Net Plant 1,441,565$ -$ 4,330,306$ Net Plant 25,145$ -$ 75,533$ Net Plant 3,154$ -$ 9,475$ 17,934,260$ -$ 53,872,605$ 181,178,777$ -$ 544,241,724$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ -$ -$ -$ 1 2
3 A B C
Functional Unbundling
Line
No. Item Account/ID
613
614
615
616
617
618
619
620
621
622
623
624
625
626
627
628
629
630
631
632
633
634
635
636
637
638
639
640
641
642
643
644
645
646
647
648
649
650
651
652
653
654
655
656
657
658
659
660
661
662
663
664
665
666
667
668
669
670
671
672
673
674
675
676
610 Other Production
611 RERC/Acorn Gen. Plant 6120130
612 Clearwater Generating Plant 6120140
613 PU Elec Power Supply Operations 6120000
614 Total Other Production
615
616 Total Production Labor
617
618 Transmission Labor
619 Transmission Operations
620 Supervision & Engineering
621 Load Dispatch
622 Station Equipment
623 Overhead Lines
624 Underground Lines
625 General Labor
626 Miscellaneous
627 Rents
628 Total Transmission Operations
629
630 Transmission Maintenance
631 Supervision & Engineering
632 Structures
633 Station Equipment
634 Overhead Lines
635 Underground Lines
636 Miscellaneous
637 Total Transmission Maintenance
638
639 Wheeling
640 Wheeling
641 Wheeling
642 Total Wheeling
643
644 Total Transmission Labor
645
646 Distribution Labor
647 Distribution Operations
648 Electric Operations 6100000
649 PU Electric Field Operations 6105000
650 Energy Deliv. Engineering 6110000
651 Customer Engineering-GIS 6115000
652 Underground Lines
653 Street Lighting
654 Metering
655 Customer Installations
656 Miscellaneous
657 Rents
658 Total Distribution Operations
659
660 Distribution Maintenance
661 Supervision & Engineering
662 Structures
663 Stations Equipment
664 Overhead Lines
665 Underground Lines
666 Transformers
667 Street Lighting
668 Metering
669 Miscellaneous
670 Total Distribution Maintenance
671
672 Total Distribution Labor
673

G H I J
Allocation
Factor Production Transmission Distribution
Production 3,188,365$ -$ -$ Production 1,012,152$ -$ -$ Production 9,685,528$ -$ -$ 13,886,044$ -$ -$ 13,886,044$ -$ -$
NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ -$ -$ -$ -$ -$ -$ Distribution -$ -$ 13,172,525$ Distribution -$ -$ 15,793,621$ Distribution -$ -$ 11,024,210$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ -$ -$ 39,990,356$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ -$ -$ -$ -$ -$ 39,990,356$ 1 2
3 A B C
Functional Unbundling
Line
No. Item Account/ID
677
678
679
680
681
682
683
684
685
686
687
688
689
690
691
692
693
694
695
696
697
698
699
700
701
702
703
704
705
706
707
708
709
710
711
712
713
714
715
716
717
718
719
720
721
722
723
724
725
726
727
728
729
730
731
732
733
734
735
736
737
738
739
740
741
742
743
744
745
746
747
748
749
674 Customer Labor
675 Customer Accounting Expense
676 Pub Util Business Support 6004000
677 Pub Util Admin-Utility Billing 6005000
678 Pub Util Admin-Customer Service 6015000
679 Pub Util Admin-Marketing Service 6020000
680 Miscellaneous
681 Total Customer Accounting Expense
682
683 Customer Service Expense
684 Customer Engineering-GIS
685 Customer Assistance
686 Advertisement / Marketing
687 Miscellaneous
688 Total Customer Service Expense
689
690 Sales Expense
691 Sales Expense
692 Demonstrations & Selling
693 Miscellaneous Sales Expense
694 Total Sales Expense
695
696 Total Customer Labor
697
698 Total Labor Expense excluding A&G
699
700 Administrative & General Labor
701 Pub Util Admin-Management Services 6000000
702 Pub Util Admin-Field Services 6010000
703 Legislative & Regulator Risk 6025000
704 Outside Services
705 Property Insurance
706 Injuries and Damages
707 Electric Utility Communication Labor
708 Miscellaneous
709 Rents
710 Transportation Pool General Labor
711 Maintenance of General Plant
712 N/A
713 Total Administrative & General Labor
714
715 Total Labor Expense
716
717 Allocation Factors
718
719
720 Production
721
722 Transmission
723
724 Distribution
725
726 Customer
727
728 Direct Assign
729
730 Total Gross Plant in Service
731
732 Net Plant in Service
733
734 Revenue Requirement x/ Direct Assignment
735
736 Total Labor
737
738 Revenue Requirement Excluding Transmission
739
740 Rev Req / City
741
742 Administrative and General
743
744 CIP
745
746 Not Applicable

G H I J
Allocation
Factor Production Transmission Distribution
Customer -$ -$ -$ Customer -$ -$ -$ Customer -$ -$ -$ Customer -$ -$ -$ NA -$ -$ -$ -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ -$ -$ -$ -$ -$ -$ 13,886,044$ -$ 39,990,356$ A&G 1,998,637$ -$ 2,593,550$ Customer -$ -$ -$ A&G 85,996$ -$ 111,594$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ NA -$ -$ -$ 2,084,634$ -$ 2,705,144$ 15,970,678$ -$ 42,695,500$ 1 0 0
Production 100% 0% 0%
0 1 0
Transmission 0% 100% 0%
0 0 1
Distribution 0% 0% 100%
0 0 0
Customer 0% 0% 0%
0 0 0
Direct Assign 0% 0% 0%
309,878,514$ -$ 918,629,919$ Gross Plant 25% 0% 75%
181,178,777$ -$ 544,241,724$ Net Plant 25% 0% 75%
246,741,858$ 45,733,725$ 107,639,955$ Rev. Req. 60% 11% 26%
15,970,678$ -$ 42,695,500$ Total Labor 22% 0% 58%
246,741,858$ 0 107,639,955$
Rev. Req. x Trans 67% 0% 29%
30,026$ 5,565$ 13,099$ Rev. Req. / City 4% 1% 2%
A&G 36% 0% 47%
CIP 0% 0% 100%
0 0 0
NA 0% 0% 0%
1 2
3 4
5 6
7 8
9 10
11 12
13 14
15 16
17 18
19 20
21 22
23 24
25 26
27 28
29 30
31 32
33 34
35 36
37 38
39 40
41 42
43 44
45 46
47 48
49 50
51 52
53 54
55 56
57 A B C
Functional Unbundling
Line
No. Item Account/ID
1 Production O&M
2 Steam Production Operation
3 Supervision & Engineering 500
4 Fuel (Transportation & Handling) 501
5 Steam Power Fuel - Gas 50110
6 Steam Power Fuel - Oil 50120
7 Steam Power Fuel - Coal 50130
8 Steam Expense 502
9 Electric Expense 505
10 Miscellaneous 506
11 Rent 507
12 Subtotal Steam Production Opeation
13 14 Steam Production Maintenance
15 Supervision & Engineering 510
16 Structures 511
17 Boilers 512
18 Electric Plant 513
19 Miscellaneous Labor 515
20 Subtotal Steam Production Maintenance
21 22 Nuclear Production Operation
23 Supervision & Engineering 517
24 Nuclear Fuel Expense 518
25 Electric Expense - Turbine Generators 523
26 Reserved NA
27 Miscellaneous Power Expenses 524
28 Reserved NA
29 Subtotal Nuclear Production Operation
30 31 Nuclear Production Maintenance
32 Supervision & Engineering 528
33 Reserved NA
34 Reserved NA
35 Reserved NA
36 Miscellaneous Plant 530
37 Subtotal Nuclear Production Maintenance
38 39 Combined Cycle Operation
40 Supervision & Engineering NA
41 Fuel NA
42 Combined Cycle Fuel - Gas NA
43 Combined Cycle Fuel - Oil NA
44 Generation Expense NA
45 Miscellaneous NA
46 Subtotal Combined Cycle Operation
47 48 Combined Cycle Maintenance
49 Supervision & Engineering NA
50 Structures NA
51 Electric Plant NA
52 Miscellaneous Plant NA
53 Subtotal Combined Cycle Maintenance
54 K L M N
Check
Customer Direct Assign Total OK
-$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ 321,200$ OK -$ -$ -$ OK -$ -$ 321,200$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ 541,428$ OK -$ -$ 541,428$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK 1 2
3 A B C
Functional Unbundling
Line
No. Item Account/ID
58 59
60 61
62 63
64 65
66 67
68 69
70 71
72 73
74 75
76 77
78 79
80 81
82 83
84 85
86 87
88 89
90 91
92 93
94 95
96 97
98 99
100
101
102
103
104
105
106
107
108
109
110
111
112
113
114
115
116
117
118
119
120
121
122
123
124
125
126
127
128
129
130
131
132
133
134
135
55 Other Production
56 Intermountain Power (take or pay) 546
57 Fuel Expense 547
58 Hoover (take or pay) 548
59 Misc. Other Power Generation 549
60 Palo Verde Power (take or pay) 550
61 Deseret Power (take or pay) 552
62 Maint/Generating & Elec. Equip. 553
63 System Load Control 556
64 Other Expenditures 557
65 Purchased Power 555
66 Purchased Power - Energy Direct Assignment 55501
67 Subtotal Other Production
68 69 Total Production O&M
70 71 Fuel & Purchased Power
72 73 Total Production O&M less Fuel & Purchased Power
74 75 Transmission O&M
76 Transmission Operation
77 Supervision & Engineering 560
78 Load Dispatch 561
79 Station Equipment 562
80 Overhead Lines 563
81 Underground Lines 564
82 Miscellaneous 566
83 Rents 567
84 Subtotal Transmission Operation
85 86 Transmission Maintenance
87 Supervision & Engineering 568
88 Structures 569
89 Station Equipment 570
90 Overhead Lines 571
91 Underground Lines 572
92 Miscellaneous 573
93 Subtotal Transmission Maintenance
94 95 Wheeling
96 Transmission Cost Fixed 565
97 Transmission Cost Variable 565
98 Subtotal Wheeling
99 100 Total Transmission O&M
101
102 Distribution O&M
103 Distribution Operations
104 Operation Maintenance and Engineering 580
105 Load Dispatch 581
106 Station Equipment 582
107 Overhead Lines 583
108 Underground Lines 584
109 Street Lighting & Signal Expenses 585
110 Metering 586
111 Customer Installations 587
112 Miscellaneous 588
113 Rents 589
114 Subtotal Distribution Operations
115
116 Distribution Maintenance
117 Supervision 590
118 Structures 591
119 Station Equipment 592
120 Overhead Lines 593
121 Underground Lines 594
122 Transformers 595
123 Street Lighting & Signals 596
124 Metering 597
125 Miscellaneous 598
126 Subtotal Distribution Maintenance
127
128 Total Distribution O&M
129
130 Customer O&M
131 Customer Accounting Expense
132 Supervision 901

K L M N
Check
Customer Direct Assign Total OK
-$ -$ 9,902,789$ OK -$ -$ 19,294,411$ OK -$ -$ 926,962$ OK -$ -$ -$ OK -$ -$ 4,730,380$ OK -$ -$ -$ OK -$ -$ 4,228,576$ OK -$ -$ 3,650,747$ OK -$ -$ 14,617,013$ OK -$ -$ 119,746,439$ OK -$ -$ -$ OK -$ -$ 177,097,317$ OK -$ -$ 177,959,946$ OK -$ -$ 154,600,981$ OK -$ -$ 23,358,965$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ 72,393$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ 185,629$ OK -$ -$ -$ OK -$ -$ 258,023$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ 115,430$ OK -$ -$ 3,415$ OK -$ -$ -$ OK -$ -$ 739,297$ OK -$ -$ 858,143$ OK -$ -$ 19,914,764$ OK -$ -$ 42,940,708$ OK -$ -$ 62,855,472$ OK -$ -$ 63,971,638$ OK OK
-$ -$ 5,154,971$ OK -$ -$ 3,219,260$ OK -$ -$ 19,467$ OK -$ -$ 91$ OK -$ -$ 4,616$ OK -$ -$ -$ OK -$ -$ 107,992$ OK -$ -$ 136,827$ OK -$ -$ 89,726$ OK -$ -$ -$ OK -$ -$ 8,732,950$ OK -$ -$ -$ OK -$ -$ 68,920$ OK -$ -$ 1,249,308$ OK -$ -$ 7,724,053$ OK -$ -$ 2,876,410$ OK -$ -$ 78,936$ OK -$ -$ 1,226,264$ OK -$ -$ 353,651$ OK -$ -$ 706,008$ OK -$ -$ 14,283,549$ OK -$ -$ 23,016,500$ OK 243,880$ -$ 243,880$ OK 1 2
3 A B C
Functional Unbundling
Line
No. Item Account/ID
136
137
138
139
140
141
142
143
144
145
146
147
148
149
150
151
152
153
154
155
156
157
158
159
160
161
162
163
164
165
166
167
168
169
170
171
172
173
174
175
133 Meter Reading 902
134 Customer Records and Collection Expenses 903
135 Reserved NA
136 Uncollectible Accounts 904
137 Miscellaneous 905
138 Subtotal Customer Accounting Expense
139
140 Other Customer Costs
141 Supervision 907
142 Customer Assistance 908
143 Advertisement 909
144 Miscellaneous 910
145 Subotal Other Customer Costs
146
147 Sales Expense
148 Sales Expense - Supervision 911
149 Demonstrations & Selling 912
150 Advertising Expenses 913
151 Miscellaneous Sales Expense 916
152 Subtotal Sales Expense
153
154 Total Customer O&M
155
156 Administrative & General Expense
157 Administrative Salaries & Misc. Labor 920
158 Office Supplies & Expense 921
159 Interdepartmental Charges 922
160 Outside Services 923
161 Property Insurance 924
162 Injuries and Damages 925
163 Employee Pensions and Benefits 926
164 Franchise Requirements 927
165 Compliance & Consultants (Regulatory Commission Expense) 928 166 General Advertising Expense 930
167 Rents 931
168 Miscellaneous General Expenses 933
169 Maintenance of General Plant 932
170 Duplicate Charges - Credit 929
171 Subtotal Administrative & General Expense
172

K L M N
Check
Customer Direct Assign Total OK
1,359,936$ -$ 1,359,936$ OK 7,008,132$ -$ 7,008,132$ OK -$ -$ -$ OK 1,240,440$ -$ 1,240,440$ OK -$ -$ -$ OK 9,852,388$ -$ 9,852,388$ OK -$ -$ -$ OK 1,062,674$ -$ 1,062,674$ OK 209,483$ -$ 209,483$ OK -$ -$ -$ OK 1,272,157$ -$ 1,272,157$ OK -$ -$ -$ OK 239,001$ -$ 239,001$ OK 2,962$ -$ 2,962$ OK -$ -$ -$ OK 241,963$ -$ 241,963$ OK 11,366,508$ -$ 11,366,508$ OK 3,135,115$ -$ 15,950,520$ OK 120,652$ -$ 719,781$ OK (5,614,748)$ -$ (28,566,148)$ OK 1,039,284$ -$ 6,200,114$ OK -$ -$ -$ OK -$ -$ -$ OK 4,651,876$ -$ 23,667,345$ OK -$ -$ -$ OK 1,827$ -$ 10,902$ OK 358$ -$ 2,137$ OK 57,417$ (3,530)$ 1,627,004$ OK 589,215$ -$ 3,515,115$ OK 24,888$ -$ 148,473$ OK -$ -$ -$ OK 4,005,885$ (3,530)$ 23,275,243$ OK 1 2
3 A B C
Functional Unbundling
Line
No. Item Account/ID
176
177
178
179
180
181
182
183
184
185
186
187
188
189
190
191
192
193
194
195
196
197
198
199
200
201
202
203
204
205
206
207
208
209
210
211
212
213
214
215
216
217
218
219
220
221
222
223
224
225
226
227
228
229
230
231
232
233
234
235
236
237
238
173 Miscellaneous and Clearing Accounts
174 General Government Charges 701
175 Expenses Transferred from Electric 702
176 IDI Utility Charges 703
177 Removal Expenses 704
178 Taxes 707
179 Stores Expenses 781
180 Transportation Expenses 782
181 Tool and Shop Expenses 783
182 Insurance 788
183 Non-Operating Expenses 790
184 Subtotal Miscellaneous and Clearing Accounts
185
186 Total O&M Expense
187
188 Total O&M Expense less Purchased Power
189
190 Additional Expenses & Deductions
191 Debt Service
192 Generation
193 Transmission
194 Distribution
195 Customer
196 New Debt
197 Total Debt Service
198
199 Taxes and Transfer to General Fund
200 General Fund Transfer
201 Other
202 Other
203 Other
204 Subtotal Taxes and Transfer to General Fund
205
206 Capital Paid from Current Earnings
207 Production
208 Transmission
209 Distribution
210 Customer
211 Street Lighting Capital
212 NA
213 Sutotal Capital Paid from Current Earnings
214
215 Reserves - Additional Cash Requirements Minimum Target 216
217 Total Additional Expenses & Deductions
218
219 Subtotal Revenue Requirement
220
221 Other Income
222 Other Operating Revenue:
223 Uncollectibles
224 Diversion 344400
225 Service Connect Charges - Electric 344410
226 Misc Service Revenues - Electric 344491
227 Misc Operating Revenues - Electric 344492
228 Corona Fees- Rev 344493
229 Cap and Trade Auction 344511
230 REC Sale 344523
231 RA Capacity Sale 344522
232 Low Carbon Fuel Standard Credits 344514
233 Non Energy Receipts ABC Admin OH 344513
234 Subtotal Other Operating Revenue
235

K L M N
Check
Customer Direct Assign Total OK
623,938$ (38,364)$ 15,726,277$ OK 184,186$ (11,325)$ 4,642,379$ OK 1,635$ (101)$ 41,211$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ 1,587,199$ OK -$ -$ (1,369,050)$ OK -$ -$ 1,048,703$ OK -$ -$ -$ OK 809,758$ (49,789)$ 21,676,719$ OK 16,182,151$ (53,320)$ 321,266,553$ OK 16,182,151$ (53,320)$ 166,665,572$ OK -$ -$ 18,746,160$ OK -$ -$ 3,107,916$ OK -$ -$ 27,477,924$ OK -$ -$ -$ OK -$ -$ 21,182,400$ OK -$ -$ 70,514,400$ OK 1,736,856$ (106,793)$ 49,216,427$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK 1,736,856$ (106,793)$ 49,216,427$ OK -$ -$ 17,623$ OK -$ -$ -$ OK -$ -$ 4,001,377$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ 4,019,000$ OK 211,340$ (12,995)$ 5,988,642$ OK 1,948,196$ (119,788)$ 129,738,469$ OK 18,130,347$ (173,108)$ 451,005,022$ OK -$ -$ -$ OK -$ -$ -$ OK 868,460$ -$ 868,460$ OK 2,409,600$ -$ 2,409,600$ OK 328$ (20)$ 9,300$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK 61,425$ (3,777)$ 1,740,574$ OK 67,979$ (4,180)$ 1,926,300$ OK 1,777$ 740,000$ 790,467$ OK 3,409,570$ 732,023$ 7,744,701$ OK 1 2
3 A B C
Functional Unbundling
Line
No. Item Account/ID
239
240
241
242
243
244
245
246
247
248
249
250
251
252
253
254
255
256
257
258
259
260
261
262
263
264
265
266
267
268
269
270
271
272
273
274
275
276
277
278
279
280
281
282
283
284
285
236 Other Non-Operating Revenues (Expenses):
237 Gain (Loss) on retirement of utility plant N/A
238 Interest Income N/A
239 Corona Fees - Rev 344493
240 Misc. Settlement Reimbursement 344494
241 Late Payment Penalties 353400
242 Land and Building Rental 373100
243 Other Property Rental 373120
244 Pole Attachments 373125
245 Substation Operation & Maintenance 373126
246 Substation Leasing 373127
247 Communication Services 373128
248 CIS User Fee 373132
249 Refunds and Reimbursements 374000
250 Miscellaneous Receipts 374200
251 Cash Over/Shortage 374207
252 Asset Forfeiture Revenue 374500
253 Bad Debt Recovery 374800
254 Settlement Recovery 374801
255 Settlement Recovery - SONGS 374802
256 Liquidated Damages 374810
257 Sale of Salvage Materials 380030
258 Damage Claim Recoveries 380100
259 Operating Transfer from 650 Fund 985650
260 Utilization Charges 61250000
261 Subtotal Other Non-Operating Revenue
262
263 Wholesale Sales
264
265 Transmission Revenue
266
267 Total Other Income
268
269 Total Retail Revenue Requirement
270 Reconcile to RPU Proforma
271 Adjustment for Cap and Trade Auction
272 Reconciled Total Retail Revenue Requirement
273 Difference from Proforma
274 % Difference from Proforma
275 Current Scenario Scenario 2
276 Revenue from Current Retail Rates - RPU Projections from Proforma 277 Residential
278 Commercial - Flat
279 Commercial - Demand
280 Industrial - TOU
281 Other
282 Total Revenue from Current Retail Rates

K L M N
Check
Customer Direct Assign Total OK
-$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK 99,066$ (6,091)$ 2,807,180$ OK 2,536$ (156)$ 71,853$ OK -$ -$ 268,470$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ 113,460$ OK -$ -$ -$ OK -$ -$ 10,535$ OK 14,116$ (868)$ 400,000$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK 1,235$ (76)$ 35,000$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK 116,953$ (7,191)$ 3,706,497$ OK -$ -$ -$ OK -$ -$ 25,732,402$ OK 3,526,523$ 724,832$ 37,183,600$ OK 14,603,824$ (897,940)$ 413,821,422$ OK 1 2
3 A B C
Functional Unbundling
Line
No. Item Account/ID
286
287
288
289
290
291
292
293
294
295
296
297
298
299
300
301
302
303
304
305
306
307
308
309
310
311
312
313
314
315
316
317
318
319
320
321
322
323
324
325
326
327
328
329
330
331
332
333
334
335
336
337
338
339
340
341
283
284 PLANT IN SERVICE
285
286 Gross Plant in Service
287 Intangible Plant
288 Organization 301
289 Franchises and Consents 302
290 Misc. Intangible Plant 303
291 Misc. Computer Software 3030
292 Subtotal Intangible Plant
293
294 Production Plant
295 Steam Production
296 Land and Land Rights 310
297 Structures & Improvements 311
298 Boiler Plant Equipment 312
299 Engines and Engine Generators 313
300 Turbo-Generator Units 314
301 Accessory Electric Equipment 315
302 Misc. Power Plant Equipment 316
303 Subtotal Steam Produciton
304
305 Hydraulic Production
306 Land and Land Rights 330
307 Structures & Improvements 331
308 Reservoirs, Dams and Water Ways 332
309 Water Wheel, Turbine and Generator 333
310 Accessory Electric Equipment 334
311 Misc. Power Plant Equipment 335
312 Roads, Railroads and Bridges 336
313 Subtotal Hydraulic Production
314
315 Combustion Turbine & Other Production
316 Land and Land Rights 340
317 Structures & Improvements 341
318 Fuel Holders, Prod, & Acc. 342
319 Prime Movers 343
320 Generators & Other Production 344
321 Accessory Electric Equipment 345
322 Misc. Production Plant 2000
323 Subtotal Combustion Turbine & Other Production
324
325 Total Production Plant
326
327 Transmission Plant
328 Land and Land Rights 350
329 Reserved 351
330 Structures & Improvements 352
331 Station Equipment - System 353
332 Towers and Fixtures 354
333 Poles and Fixtures 355
334 Overhead Conductor 356
335 Underground Conductor 357
336 Underground Conduit 358
337 Misc. Transmission Plant 359
338 Subtotal Transmission Plant

K L M N
Check
Customer Direct Assign Total OK
-$ -$ -$ OK -$ -$ -$ OK -$ -$ 32,637,528$ OK -$ -$ -$ OK -$ -$ 32,637,528$ OK -$ -$ 17,142$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ 17,142$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ 1,038,596$ OK -$ -$ 703,469$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ 268,544,986$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ 270,287,051$ OK -$ -$ 302,941,722$ OK -$ -$ 2,683,037$ OK -$ -$ -$ OK -$ -$ 971,062$ OK -$ -$ 4,790,451$ OK -$ -$ 3,567,512$ OK -$ -$ 22,928,628$ OK -$ -$ 8,716,136$ OK -$ -$ 5,748,846$ OK -$ -$ 2,356,742$ OK -$ -$ -$ OK -$ -$ 51,762,414$ OK 1 2
3 A B C
Functional Unbundling
Line
No. Item Account/ID
342
343
344
345
346
347
348
349
350
351
352
353
354
355
356
357
358
359
360
361
362
363
364
365
366
367
368
369
370
371
372
373
374
375
376
377
378
379
380
381
382
383
384
385
386
387
388
389
390
391
392
393
394
395
396
397
398
399
400
401
402
403
404
405
406
407
408
339
340 Distribution Plant
341 Land and Land Rights 360
342 Structures & Improvements 361
343 Station Equipment 362
344 Misc. Plant 363
345 Towers and Fixtures 364
346 Overhead Conductor 365
347 Undgeround Conduit 366
348 Underground Conductor 367
349 Line Transformers 368
350 Services 369
351 Meters 370
352 Inst. on Customer Premises 371
353 Street Light / Signal System 373
354 Total Distribution Plant
355
356 Subtotal Plant Before General
357
358 General Plant
359 Land and Land Rights 389
360 Structures & Improvements 390
361 Structures & Improvements - Other 3900
362 Office Furniture & Equipment 391
363 Info System Computers 3910
364 Transportation Equipment 392
365 Stores Equipment 393
366 Tools, Shop & Garage Equipment 394
367 Laboratory Equipment 395
368 Power Operated Equipment 396
369 Communication Equipment 397
370 Miscellaneous Equipment 398
371 Other Tangible Property 399
372 Subtotal General Plant
373
374 Total Gross Plant in Service
375
376
377 Accumulated Depreciation
378 Intangible Plant
379 Organization 301
380 Franchises and Consents 302
381 Misc. Intangible Plant 303
382 Misc. Computer Software 3030
383 Subtotal Intangible Plant
384
385 Production Plant
386 Steam Production
387 Land and Land Rights 310
388 Structures & Improvements 311
389 Boiler Plant Equipment 312
390 Engines and Engine Generators 313
391 Turbo-Generator Units 314
392 Accessory Electric Equipment 315
393 Misc. Power Plant Equipment 316
394 Subtotal Steam Produciton
395
396 Hydraulic Production
397 Land and Land Rights 330
398 Structures & Improvements 331
399 Reservoirs, Dams and Water Ways 332
400 Water Wheel, Turbine and Generator 333
401 Accessory Electric Equipment 334
402 Misc. Power Plant Equipment 335
403 Roads, Railroads and Bridges 336
404 Subtotal Hydraulic Production
405

K L M N
Check
Customer Direct Assign Total OK
-$ -$ 41,183,402$ OK -$ -$ 15,397,298$ OK -$ -$ 160,729,872$ OK -$ -$ -$ OK -$ -$ 44,909,055$ OK -$ -$ 45,300,634$ OK -$ -$ 131,830,676$ OK -$ -$ 137,105,611$ OK -$ -$ 63,370,705$ OK -$ -$ 29,359,860$ OK -$ -$ 21,963,893$ OK -$ -$ 851,584$ OK -$ -$ 55,987,877$ OK -$ -$ 747,990,468$ OK -$ -$ 1,102,694,603$ OK -$ -$ 8,119,611$ OK -$ -$ 69,112,396$ OK -$ -$ -$ OK -$ -$ 8,821,955$ OK -$ -$ -$ OK -$ -$ 12,709,126$ OK -$ -$ 45,523$ OK -$ -$ 410,934$ OK -$ -$ 814,618$ OK -$ -$ 1,682,546$ OK -$ -$ 22,907,698$ OK -$ -$ 1,170,480$ OK -$ -$ 18,944$ OK -$ -$ 125,813,830$ OK -$ -$ 1,228,508,433$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ 32,637,528$ OK -$ -$ -$ OK -$ -$ 32,637,528$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK 1 2
3 A B C
Functional Unbundling
Line
No. Item Account/ID
409
410
411
412
413
414
415
416
417
418
419
420
421
422
423
424
425
426
427
428
429
430
431
432
433
434
435
436
437
438
439
440
441
442
443
444
445
446
447
448
449
450
451
452
453
454
455
456
457
458
459
460
461
462
463
464
465
466
467
468
469
470
406 Combustion Turbine & Other Production
407 Land and Land Rights 340
408 Structures & Improvements 341
409 Fuel Holders, Prod, & Acc. 342
410 Prime Movers 343
411 Generators & Other Production 344
412 Accessory Electric Equipment 345
413 Misc. Production Plant 2000
414 Subtotal Combustion Turbine & Other Production
415
416 Total Production Plant
417
418 Transmission Plant
419 Land and Land Rights 350
420 Reserved 351
421 Structures & Improvements 352
422 Station Equipment - System 353
423 Towers and Fixtures 354
424 Poles and Fixtures 355
425 Overhead Conductor 356
426 Underground Conductor 357
427 Underground Conduit 358
428 Misc. Transmission Plant 359
429 Subtotal Transmission Plant
430
431 Distribution Plant
432 Land and Land Rights 360
433 Structures & Improvements 361
434 Station Equipment 362
435 Misc. Plant 363
436 Towers and Fixtures 364
437 Overhead Conductor 365
438 Undgeround Conduit 366
439 Underground Conductor 367
440 Line Transformers 368
441 Services 369
442 Meters 370
443 Inst. on Customer Premises 371
444 Street Light / Signal System 373
445 Total Distribution Plant
446
447 Subtotal Plant Before General
448
449 General Plant
450 Land and Land Rights 389
451 Structures & Improvements 390
452 Structures & Improvements - Other 3900
453 Office Furniture & Equipment 391
454 Info System Computers 3910
455 Transportation Equipment 392
456 Stores Equipment 393
457 Tools, Shop & Garage Equipment 394
458 Laboratory Equipment 395
459 Power Operated Equipment 396
460 Communication Equipment 397
461 Miscellaneous Equipment 398
462 Other Tangible Property 399
463 Subtotal General Plant
464
465 Total Accumulated Depreciation
466
467

K L M N
Check
Customer Direct Assign Total OK
-$ -$ -$ OK -$ -$ 155,300$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ 111,722,271$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ 111,877,570$ OK -$ -$ 144,515,099$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ 710,957$ OK -$ -$ 4,522,181$ OK -$ -$ 1,251,520$ OK -$ -$ 8,164,974$ OK -$ -$ 3,637,134$ OK -$ -$ 1,856,873$ OK -$ -$ 1,257,665$ OK -$ -$ -$ OK -$ -$ 21,401,303$ OK -$ -$ -$ OK -$ -$ 4,266,581$ OK -$ -$ 56,848,424$ OK -$ -$ -$ OK -$ -$ 18,346,185$ OK -$ -$ 24,052,960$ OK -$ -$ 37,896,415$ OK -$ -$ 68,490,579$ OK -$ -$ 33,474,633$ OK -$ -$ 15,070,839$ OK -$ -$ 7,206,731$ OK -$ -$ 762,056$ OK -$ -$ 36,039,497$ OK -$ -$ 302,454,899$ OK -$ -$ 468,371,301$ OK -$ -$ -$ OK -$ -$ 16,266,385$ OK -$ -$ -$ OK -$ -$ 6,564,847$ OK -$ -$ -$ OK -$ -$ 10,269,478$ OK -$ -$ 45,523$ OK -$ -$ 353,329$ OK -$ -$ 814,618$ OK -$ -$ 1,480,842$ OK -$ -$ 17,135,827$ OK -$ -$ 1,069,802$ OK -$ -$ 6,315$ OK -$ -$ 54,006,965$ OK -$ -$ 522,378,266$ OK 1 2
3 A B C
Functional Unbundling
Line
No. Item Account/ID
471
472
473
474
475
476
477
478
479
480
481
482
483
484
485
486
487
488
489
490
491
492
493
494
495
496
497
498
499
500
501
502
503
504
505
506
507
508
509
510
511
512
513
514
515
516
517
518
519
520
521
522
523
524
525
526
527
528
529
530
531
532
533
534
535
536
537
538
539
540
541
542
468 Net Plant in Service
469 Intangible Plant
470 Organization 301
471 Franchises and Consents 302
472 Misc. Intangible Plant 303
473 Misc. Computer Software 3030
474 Subtotal Intangible Plant
475
476 Production Plant
477 Steam Production
478 Land and Land Rights 310
479 Structures & Improvements 311
480 Boiler Plant Equipment 312
481 Engines and Engine Generators 313
482 Turbo-Generator Units 314
483 Accessory Electric Equipment 315
484 Misc. Power Plant Equipment 316
485 Subtotal Steam Produciton
486
487 Hydraulic Production
488 Land and Land Rights 330
489 Structures & Improvements 331
490 Reservoirs, Dams and Water Ways 332
491 Water Wheel, Turbine and Generator 333
492 Accessory Electric Equipment 334
493 Misc. Power Plant Equipment 335
494 Roads, Railroads and Bridges 336
495 Subtotal Hydraulic Production
496
497 Combustion Turbine & Other Production
498 Land and Land Rights 340
499 Structures & Improvements 341
500 Fuel Holders, Prod, & Acc. 342
501 Prime Movers 343
502 Generators & Other Production 344
503 Accessory Electric Equipment 345
504 Misc. Production Plant 2000
505 Subtotal Combustion Turbine & Other Production
506
507 Total Production Plant
508
509 Transmission Plant
510 Land and Land Rights 350
511 Reserved 351
512 Structures & Improvements 352
513 Station Equipment - System 353
514 Towers and Fixtures 354
515 Poles and Fixtures 355
516 Overhead Conductor 356
517 Underground Conductor 357
518 Underground Conduit 358
519 Misc. Transmission Plant 359
520 Subtotal Transmission Plant
521
522 Distribution Plant
523 Land and Land Rights 360
524 Structures & Improvements 361
525 Station Equipment 362
526 Misc. Plant 363
527 Towers and Fixtures 364
528 Overhead Conductor 365
529 Undgeround Conduit 366
530 Underground Conductor 367
531 Line Transformers 368
532 Services 369
533 Meters 370
534 Inst. on Customer Premises 371
535 Street Light / Signal System 373
536 Total Distribution Plant
537
538 Subtotal Plant Before General
539

K L M N
Check
Customer Direct Assign Total OK
-$ -$ -$ OK -$ -$ -$ OK -$ -$ 19,290,334$ OK -$ -$ -$ OK -$ -$ 19,290,334$ OK -$ -$ 17,142$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ 17,142$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ 1,038,596$ OK -$ -$ 548,169$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ 156,822,716$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ 158,409,481$ OK -$ -$ 177,716,957$ OK -$ -$ 2,683,037$ OK -$ -$ -$ OK -$ -$ 260,105$ OK -$ -$ 268,270$ OK -$ -$ 2,315,992$ OK -$ -$ 14,763,654$ OK -$ -$ 5,079,002$ OK -$ -$ 3,891,973$ OK -$ -$ 1,099,077$ OK -$ -$ -$ OK -$ -$ 30,361,110$ OK -$ -$ 41,183,402$ OK -$ -$ 11,130,717$ OK -$ -$ 103,881,448$ OK -$ -$ -$ OK -$ -$ 26,562,871$ OK -$ -$ 21,247,674$ OK -$ -$ 93,934,261$ OK -$ -$ 68,615,032$ OK -$ -$ 29,896,072$ OK -$ -$ 14,289,021$ OK -$ -$ 14,757,162$ OK -$ -$ 89,528$ OK -$ -$ 19,948,380$ OK -$ -$ 445,535,569$ OK -$ -$ 653,613,636$ OK 1 2
3 A B C
Functional Unbundling
Line
No. Item Account/ID
543
544
545
546
547
548
549
550
551
552
553
554
555
556
557
558
559
560
561
562
563
564
565
566
567
568
569
570
571
572
573
574
575
576
577
578
579
580
581
582
583
584
585
586
587
588
589
590
591
592
593
594
595
596
597
598
599
600
601
602
603
604
605
606
607
608
609
610
611
612
540 General Plant
541 Land and Land Rights 389
542 Structures & Improvements 390
543 Structures & Improvements - Other 3900
544 Office Furniture & Equipment 391
545 Info System Computers 3910
546 Transportation Equipment 392
547 Stores Equipment 393
548 Tools, Shop & Garage Equipment 394
549 Laboratory Equipment 395
550 Power Operated Equipment 396
551 Communication Equipment 397
552 Miscellaneous Equipment 398
553 Other Tangible Property 399
554 Subtotal General Plant
555
556 Total Net Plant in Service
557
558
559 Labor
560
561 Production Labor
562 Steam Production Operation
563 Supervision & Engineering
564 Fuel (Transportation & Handling)
565 Steam Expense
566 Electric Expense
567 Miscellaneous
568 Rent
569 Total Steam Production Operation
570
571 Steam Production Maintenance
572 Supervision & Engineering
573 Structures
574 Boilers
575 Electric Plant
576 Miscellaneous Labor
577 Total Steam Production Maintenance
578
579 Hydro Production Operation
580 Supervision & Engineering
581 Water for Power
582 Hydraulic Expense
583 Electric Expense
584 Miscellaneous
585 Rent
586 Total Hydro Production Operation
587
588 Hydro Production Maintenance
589 Supervision & Engineering
590 Structures
591 Reservoirs & Dams
592 Electric Plant
593 Miscellaneous Plant
594 Total Hydro Production Maintenance
595
596 Combined Cycle Operation
597 Labor
598 Fuel Handling
599 Generation Expense
600 Miscellaneous Plant
601 Total Combined Cycle Operation
602
603 Combined Cycle Maintenance
604 Supervision & Engineering
605 Structures
606 Electric Plant
607 Miscellaneous Plant
608 Total Combined Cycle Maintenance
609

K L M N
Check
Customer Direct Assign Total OK
-$ -$ 8,119,611$ OK -$ -$ 52,846,011$ OK -$ -$ -$ OK -$ -$ 2,257,107$ OK -$ -$ -$ OK -$ -$ 2,439,648$ OK -$ -$ -$ OK -$ -$ 57,605$ OK -$ -$ (0)$ OK -$ -$ 201,704$ OK -$ -$ 5,771,871$ OK -$ -$ 100,678$ OK -$ -$ 12,629$ OK -$ -$ 71,806,865$ OK -$ -$ 725,420,501$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK 1 2
3 A B C
Functional Unbundling
Line
No. Item Account/ID
613
614
615
616
617
618
619
620
621
622
623
624
625
626
627
628
629
630
631
632
633
634
635
636
637
638
639
640
641
642
643
644
645
646
647
648
649
650
651
652
653
654
655
656
657
658
659
660
661
662
663
664
665
666
667
668
669
670
671
672
673
674
675
676
610 Other Production
611 RERC/Acorn Gen. Plant 6120130
612 Clearwater Generating Plant 6120140
613 PU Elec Power Supply Operations 6120000
614 Total Other Production
615
616 Total Production Labor
617
618 Transmission Labor
619 Transmission Operations
620 Supervision & Engineering
621 Load Dispatch
622 Station Equipment
623 Overhead Lines
624 Underground Lines
625 General Labor
626 Miscellaneous
627 Rents
628 Total Transmission Operations
629
630 Transmission Maintenance
631 Supervision & Engineering
632 Structures
633 Station Equipment
634 Overhead Lines
635 Underground Lines
636 Miscellaneous
637 Total Transmission Maintenance
638
639 Wheeling
640 Wheeling
641 Wheeling
642 Total Wheeling
643
644 Total Transmission Labor
645
646 Distribution Labor
647 Distribution Operations
648 Electric Operations 6100000
649 PU Electric Field Operations 6105000
650 Energy Deliv. Engineering 6110000
651 Customer Engineering-GIS 6115000
652 Underground Lines
653 Street Lighting
654 Metering
655 Customer Installations
656 Miscellaneous
657 Rents
658 Total Distribution Operations
659
660 Distribution Maintenance
661 Supervision & Engineering
662 Structures
663 Stations Equipment
664 Overhead Lines
665 Underground Lines
666 Transformers
667 Street Lighting
668 Metering
669 Miscellaneous
670 Total Distribution Maintenance
671
672 Total Distribution Labor
673

K L M N
Check
Customer Direct Assign Total OK
-$ -$ 3,188,365$ OK -$ -$ 1,012,152$ OK -$ -$ 9,685,528$ OK -$ -$ 13,886,044$ OK -$ -$ 13,886,044$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ 13,172,525$ OK -$ -$ 15,793,621$ OK -$ -$ 11,024,210$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ 39,990,356$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ 39,990,356$ OK 1 2
3 A B C
Functional Unbundling
Line
No. Item Account/ID
677
678
679
680
681
682
683
684
685
686
687
688
689
690
691
692
693
694
695
696
697
698
699
700
701
702
703
704
705
706
707
708
709
710
711
712
713
714
715
716
717
718
719
720
721
722
723
724
725
726
727
728
729
730
731
732
733
734
735
736
737
738
739
740
741
742
743
744
745
746
747
748
749
674 Customer Labor
675 Customer Accounting Expense
676 Pub Util Business Support 6004000
677 Pub Util Admin-Utility Billing 6005000
678 Pub Util Admin-Customer Service 6015000
679 Pub Util Admin-Marketing Service 6020000
680 Miscellaneous
681 Total Customer Accounting Expense
682
683 Customer Service Expense
684 Customer Engineering-GIS
685 Customer Assistance
686 Advertisement / Marketing
687 Miscellaneous
688 Total Customer Service Expense
689
690 Sales Expense
691 Sales Expense
692 Demonstrations & Selling
693 Miscellaneous Sales Expense
694 Total Sales Expense
695
696 Total Customer Labor
697
698 Total Labor Expense excluding A&G
699
700 Administrative & General Labor
701 Pub Util Admin-Management Services 6000000
702 Pub Util Admin-Field Services 6010000
703 Legislative & Regulator Risk 6025000
704 Outside Services
705 Property Insurance
706 Injuries and Damages
707 Electric Utility Communication Labor
708 Miscellaneous
709 Rents
710 Transportation Pool General Labor
711 Maintenance of General Plant
712 N/A
713 Total Administrative & General Labor
714
715 Total Labor Expense
716
717 Allocation Factors
718
719
720 Production
721
722 Transmission
723
724 Distribution
725
726 Customer
727
728 Direct Assign
729
730 Total Gross Plant in Service
731
732 Net Plant in Service
733
734 Revenue Requirement x/ Direct Assignment
735
736 Total Labor
737
738 Revenue Requirement Excluding Transmission
739
740 Rev Req / City
741
742 Administrative and General
743
744 CIP
745
746 Not Applicable

K L M N
Check
Customer Direct Assign Total OK
1,512,751$ -$ 1,512,751$ OK 1,198,664$ -$ 1,198,664$ OK 4,426,209$ -$ 4,426,209$ OK 2,617,460$ -$ 2,617,460$ OK -$ -$ -$ OK 9,755,084$ -$ 9,755,084$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK 9,755,084$ -$ 9,755,084$ OK 9,755,084$ -$ 63,631,485$ OK 924,771$ -$ 5,516,958$ OK 3,632,238$ -$ 3,632,238$ OK 39,791$ -$ 237,381$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK -$ -$ -$ OK 4,596,799$ -$ 9,386,577$ OK 14,351,883$ -$ 73,018,062$ OK 0 0 1
0% 0% 100%
0 0 1
0% 0% 100%
0 0 1
0% 0% 100%
1 0 1
100% 0% 100%
0 1 1
0% 100% 100%
-$ -$ 1,228,508,433$ 0% 0% 100%
-$ -$ 725,420,501$ 0% 0% 100%
14,603,824$ (897,940)$ 413,821,422$ 4% 0% 100%
14,351,883$ -$ 73,018,062$ 20% 0% 100%
14,603,824$ (897,940)$ 368,087,697$ 4% 0% 100%
1,777$ 740,000$ 790,467$ 0% 94% 100%
17% 0% 100%
0% 0% 100%
0 0 0
0% 0% 0%
Line Adjusted Allocation
No. Item Account/ID Test Year Factor
1 Production O&M
2 Steam Production Operation
3 Supervision & Engineering 500 -$ NA 4 Fuel (Transportation & Handling) 501 -$ NA 5 Steam Power Fuel - Gas 50110 -$ NA 6 Steam Power Fuel - Oil 50120 -$ NA 7 Steam Power Fuel - Coal 50130 -$ NA 8 Steam Expense 502 -$ NA 9 Electric Expense 505 -$ NA 10 Miscellaneous 506 -$ NA 11 Rent 507 -$ NA
12 Subtotal Steam Production Opeation -$
13 14 Steam Production Maintenance
15 Supervision & Engineering 510 -$ NA 16 Structures 511 -$ NA 17 Boilers 512 -$ NA
18 Electric Plant 513 -$ NA 19 Miscellaneous Labor 515 -$ NA 20 Subtotal Steam Production Maintenance -$
21 22 Nuclear Production Operation
23 Supervision & Engineering 517 -$ NA 24 Nuclear Fuel Expense 518 -$ NA 25 Electric Expense - Turbine Generators 523 -$ NA 26 Reserved NA -$ NA
27 Miscellaneous Power Expenses 524 321,200$ Baseload 28 Reserved NA -$ NA
29 Subtotal Nuclear Production Operation 321,200$
30 31 Nuclear Production Maintenance
32 Supervision & Engineering 528 -$ NA 33 Reserved NA -$ NA
34 Reserved NA -$ NA
35 Reserved NA -$ NA
36 Miscellaneous Plant 530 541,428$ Baseload 37 Subtotal Nuclear Production Maintenance 541,428$
38 39 Combined Cycle Operation
40 Supervision & Engineering NA -$ NA 41 Fuel NA -$ NA
42 Combined Cycle Fuel - Gas NA -$ NA 43 Combined Cycle Fuel - Oil NA -$ NA 44 Generation Expense NA -$ NA 45 Miscellaneous NA -$ NA 46 Subtotal Combined Cycle Operation -$
47 48 Combined Cycle Maintenance
49 Supervision & Engineering NA -$ NA 50 Structures NA -$ NA 51 Electric Plant NA -$ NA 52 Miscellaneous Plant NA -$ NA 53 Subtotal Combined Cycle Maintenance -$
54 55 Other Production
56 Intermountain Power (take or pay) 546 9,902,789$ Purchased Power 57 Fuel Expense 547 19,294,411$ Fuel & Energy 58 Hoover (take or pay) 548 926,962$ Purchased Power 59 Misc. Other Power Generation 549 -$ NA 60 Palo Verde Power (take or pay) 550 4,730,380$ Purchased Power 61 Deseret Power (take or pay) 552 -$ NA 62 Maint/Generating & Elec. Equip. 553 4,228,576$ Baseload 63 System Load Control 556 3,650,747$ Baseload 64 Other Expenditures 557 14,617,013$ Baseload 65 Purchased Power 555 119,746,439$ Fuel & Energy 66 Purchased Power - Energy Direct Assignment 55501 -$ NA 67 Subtotal Other Production 177,097,317$
68 69 Total Production O&M 177,959,946$
70 71 Fuel & Purchased Power 154,600,981$
72 73 Total Production O&M less Fuel & Purchased Power 23,358,965$ 74 75 Transmission O&M
76 Transmission Operation
77 Supervision & Engineering 560 -$ NA 78 Load Dispatch 561 -$ NA 79 Station Equipment 562 -$ NA 80 Overhead Lines 563 -$ NA 81 Underground Lines 564 -$ NA 82 Miscellaneous 566 -$ NA 83 Rents 567 -$ NA
84 Subtotal Transmission Operation -$
85 86 Transmission Maintenance
87 Supervision & Engineering 568 -$ NA 88 Structures 569 -$ NA 89 Station Equipment 570 -$ NA 90 Overhead Lines 571 -$ NA 91 Underground Lines 572 -$ NA 92 Miscellaneous 573 -$ NA 93 Subtotal Transmission Maintenance -$
94 95 Wheeling
96 Transmission Cost Fixed 565 -$ NA 97 Transmission Cost Variable 565 -$ NA 98 Subtotal Wheeling -$
99 100 Total Transmission O&M -$
101
102 Distribution O&M
103 Distribution Operations
Production

Line Adjusted Allocation
No. Item Account/ID Test Year Factor
Production
104 Operation Maintenance and Engineering 580 -$ NA 105 Load Dispatch 581 -$ NA 106 Station Equipment 582 -$ NA 107 Overhead Lines 583 -$ NA 108 Underground Lines 584 -$ NA 109 Street Lighting & Signal Expenses 585 -$ NA 110 Metering 586 -$ NA 111 Customer Installations 587 -$ NA 112 Miscellaneous 588 -$ NA 113 Rents 589 -$ NA
114 Subtotal Distribution Operations -$
115
116 Distribution Maintenance
117 Supervision 590 -$ NA 118 Structures 591 -$ NA 119 Station Equipment 592 -$ NA 120 Overhead Lines 593 -$ NA 121 Underground Lines 594 -$ NA 122 Transformers 595 -$ NA 123 Street Lighting & Signals 596 -$ NA 124 Metering 597 -$ NA 125 Miscellaneous 598 -$ NA 126 Subtotal Distribution Maintenance -$
127
128 Total Distribution O&M -$
129
130 Customer O&M
131 Customer Accounting Expense
132 Supervision 901 -$ NA 133 Meter Reading 902 -$ NA 134 Customer Records and Collection Expenses 903 -$ NA 135 Reserved NA -$ NA
136 Uncollectible Accounts 904 -$ NA 137 Miscellaneous 905 -$ NA 138 Subtotal Customer Accounting Expense -$
139
140 Other Customer Costs
141 Supervision 907 -$ NA 142 Customer Assistance 908 -$ NA 143 Advertisement 909 -$ NA 144 Miscellaneous 910 -$ NA 145 Subotal Other Customer Costs -$
146
147 Sales Expense
148 Sales Expense - Supervision 911 -$ NA 149 Demonstrations & Selling 912 -$ NA 150 Advertising Expenses 913 -$ NA 151 Miscellaneous Sales Expense 916 -$ NA 152 Subtotal Sales Expense -$
153
154 Total Customer O&M -$
155
156 Administrative & General Expense
157 Administrative Salaries & Misc. Labor 920 3,488,734$ Baseload 158 Office Supplies & Expense 921 260,756$ Baseload 159 Interdepartmental Charges 922 (6,248,053)$ Baseload 160 Outside Services 923 2,246,125$ Baseload 161 Property Insurance 924 -$ NA 162 Injuries and Damages 925 -$ NA 163 Employee Pensions and Benefits 926 5,176,576$ Baseload 164 Franchise Requirements 927 -$ NA 165 Compliance & Consultants (Regulatory Commission Expense)928 3,949$ Baseload 166 General Advertising Expense 930 774$ Baseload 167 Rents 931 970,104$ Baseload
168 Miscellaneous General Expenses 933 1,273,426$ Baseload 169 Maintenance of General Plant 932 53,788$ Baseload 170 Duplicate Charges - Credit 929 -$ NA 171 Subtotal Administrative & General Expense 7,226,180$ 172
173 Miscellaneous and Clearing Accounts
174 General Government Charges 701 10,541,865$ Baseload 175 Expenses Transferred from Electric 702 3,111,947$ Baseload 176 IDI Utility Charges 703 27,625$ Baseload 177 Removal Expenses 704 -$ NA 178 Taxes 707 -$ NA
179 Stores Expenses 781 -$ NA 180 Transportation Expenses 782 396,414$ Baseload 181 Tool and Shop Expenses 783 (341,930)$ Baseload 182 Insurance 788 261,921$ Baseload 183 Non-Operating Expenses 790 -$ NA 184 Subtotal Miscellaneous and Clearing Accounts 13,997,842$ 185
186 Total O&M Expense 199,183,968$
187
188 Total O&M Expense less Purchased Power 44,582,987$
189
190 Additional Expenses & Deductions
191 Debt Service
192 Generation 18,746,160$ Baseload
193 Transmission -$ NA 194 Distribution -$ NA 195 Customer -$ NA
196 New Debt 75,924$ Rev. Req
197 Total Debt Service 18,822,084$
198
199 Taxes and Transfer to General Fund
200 General Fund Transfer 29,345,394$ Rev. Req 201 Other -$ NA
202 Other -$ NA
203 Other -$ NA
204 Subtotal Taxes and Transfer to General Fund 29,345,394$ 205
206 Capital Paid from Current Earnings
Line Adjusted Allocation
No. Item Account/ID Test Year Factor
Production
207 Production 17,623$ Rev. Req
208 Transmission -$ NA 209 Distribution -$ Rev. Req 210 Customer -$ NA
211 Street Lighting Capital -$ NA 212 NA -$ NA
213 Sutotal Capital Paid from Current Earnings 17,623$
214
215 Reserves - Additional Cash Requirements 3,570,740$ Baseload 216
217 Total Additional Expenses & Deductions 51,755,842$
218
219 Subtotal Revenue Requirement 250,939,809$
220
221 Other Income
222 Other Operating Revenue:
223 Uncollectibles -$ NA 224 Diversion 344400 -$ NA 225 Service Connect Charges - Electric 344410 -$ NA 226 Misc Service Revenues - Electric 344491 -$ NA 227 Misc Operating Revenues - Electric 344492 5,545$ Baseload 228 Corona Fees- Rev 344493 -$ NA Cap and Trade Auction 344511 -$ Fuel & Energy 229 REC Sale 344523 -$ NA 230 RA Capacity Sale 344522 1,037,821$ Baseload 231 Low Carbon Fuel Standard Credits 344514 1,148,560$ Rev. Req 232 Non Energy Receipts ABC Admin OH 344513 30,026$ Baseload 233 Subtotal Other Operating Revenue 2,221,952$
234
235 Other Non-Operating Revenues (Expenses):
236 Gain (Loss) on retirement of utility plant -$ NA 237 Interest Income -$ Baseload 238 Corona Fees - Rev 344493 -$ NA 239 Misc. Settlement Reimbursement 344494 -$ NA 240 Late Payment Penalties 353400 -$ NA 241 Land and Building Rental 373100 1,673,787$ Baseload 242 Other Property Rental 373120 42,843$ Baseload 243 Pole Attachments 373125 -$ NA 244 Substation Operation & Maintenance 373126 -$ NA 245 Substation Leasing 373127 -$ NA 246 Communication Services 373128 -$ NA 247 CIS User Fee 373132 -$ NA 248 Refunds and Reimbursements 374000 -$ NA 249 Miscellaneous Receipts 374200 238,501$ Baseload 250 Cash Over/Shortage 374207 -$ Baseload 251 Asset Forfeiture Revenue 374500 -$ NA 252 Bad Debt Recovery 374800 -$ NA 253 Settlement Recovery 374801 -$ Baseload 254 Settlement Recovery - SONGS 374802 -$ NA 255 Liquidated Damages 374810 -$ NA 256 Sale of Salvage Materials 380030 20,869$ Baseload 257 Damage Claim Recoveries 380100 -$ Baseload 258 Operating Transfer from 650 Fund 985650 -$ NA 259 Utilization Charges 61250000 -$ NA 260 Subtotal Other Non-Operating Revenue 1,975,999$
261
262 Wholesale Sales -$ Baseload 263
264 Transmission Revenue -$ Baseload 265
266 Total Other Income 4,197,951$
267
268 Total Retail Revenue Requirement 246,741,858$
269
270
271
272
273
274
275
276
277
278
279
280
281
282
283 PLANT IN SERVICE
284
285 Gross Plant in Service
286 Intangible Plant
287 Organization 301 -$ NA 288 Franchises and Consents 302 -$ NA 289 Misc. Intangible Plant 303 8,151,448$ Baseload 290 Misc. Computer Software 3030 -$ NA 291 Subtotal Intangible Plant 8,151,448$
292
293 Production Plant
294 Steam Production
295 Land and Land Rights 310 17,142$ Baseload 296 Structures & Improvements 311 -$ NA 297 Boiler Plant Equipment 312 -$ NA 298 Engines and Engine Generators 313 -$ NA 299 Turbo-Generator Units 314 -$ NA 300 Accessory Electric Equipment 315 -$ NA 301 Misc. Power Plant Equipment 316 -$ NA 302 Subtotal Steam Produciton 17,142$
303
304 Hydraulic Production
305 Land and Land Rights 330 -$ NA 306 Structures & Improvements 331 -$ NA 307 Reservoirs, Dams and Water Ways 332 -$ NA 308 Water Wheel, Turbine and Generator 333 -$ NA Line Adjusted Allocation
No. Item Account/ID Test Year Factor
Production
309 Accessory Electric Equipment 334 -$ NA 310 Misc. Power Plant Equipment 335 -$ NA 311 Roads, Railroads and Bridges 336 -$ NA 312 Subtotal Hydraulic Production -$
313
314 Combustion Turbine & Other Production
315 Land and Land Rights 340 1,038,596$ Baseload 316 Structures & Improvements 341 703,469$ Baseload 317 Fuel Holders, Prod, & Acc. 342 -$ NA 318 Prime Movers 343 -$ NA 319 Generators & Other Production 344 268,544,986$ Baseload 320 Accessory Electric Equipment 345 -$ NA 321 Misc. Production Plant 2000 -$ NA 322 Subtotal Combustion Turbine & Other Production 270,287,051$ 323
324 Total Production Plant 278,455,641$
325
326 Transmission Plant
327 Land and Land Rights 350 -$ NA 328 Reserved 351 -$ NA 329 Structures & Improvements 352 -$ NA 330 Station Equipment - System 353 -$ NA 331 Towers and Fixtures 354 -$ NA 332 Poles and Fixtures 355 -$ NA 333 Overhead Conductor 356 -$ NA 334 Underground Conductor 357 -$ NA 335 Underground Conduit 358 -$ NA 336 Misc. Transmission Plant 359 -$ NA 337 Subtotal Transmission Plant -$
338
339 Distribution Plant
340 Land and Land Rights 360 -$ NA 341 Structures & Improvements 361 -$ NA 342 Station Equipment 362 -$ NA 343 Misc. Plant 363 -$ NA 344 Towers and Fixtures 364 -$ NA 345 Overhead Conductor 365 -$ NA 346 Undgeround Conduit 366 -$ NA 347 Underground Conductor 367 -$ NA 348 Line Transformers 368 -$ NA 349 Services 369 -$ NA 350 Meters 370 -$ NA
351 Inst. on Customer Premises 371 -$ NA 352 Street Light / Signal System 373 -$ NA 353 Total Distribution Plant -$
354
355 Subtotal Plant Before General 278,455,641$
356
357 General Plant
358 Land and Land Rights 389 2,027,929$ Total Gross Plant 359 Structures & Improvements 390 17,261,298$ Total Gross Plant 360 Structures & Improvements - Other 3900 -$ NA 361 Office Furniture & Equipment 391 2,203,344$ Total Gross Plant 362 Info System Computers 3910 -$ NA 363 Transportation Equipment 392 3,174,192$ Total Gross Plant 364 Stores Equipment 393 11,370$ Total Gross Plant 365 Tools, Shop & Garage Equipment 394 102,634$ Total Gross Plant 366 Laboratory Equipment 395 203,456$ Total Gross Plant 367 Power Operated Equipment 396 420,228$ Total Gross Plant 368 Communication Equipment 397 5,721,356$ Total Gross Plant 369 Miscellaneous Equipment 398 292,335$ Total Gross Plant 370 Other Tangible Property 399 4,731$ Total Gross Plant 371 Subtotal General Plant 31,422,873$
372
373 Total Gross Plant in Service 309,878,514$
374
375
376 Accumulated Depreciation
377 Intangible Plant
378 Organization 301 -$ NA 379 Franchises and Consents 302 -$ NA 380 Misc. Intangible Plant 303 8,151,448$ Baseload 381 Misc. Computer Software 3030 -$ NA 382 Subtotal Intangible Plant 8,151,448$
383
384 Production Plant
385 Steam Production
386 Land and Land Rights 310 -$ NA 387 Structures & Improvements 311 -$ NA 388 Boiler Plant Equipment 312 -$ NA 389 Engines and Engine Generators 313 -$ NA 390 Turbo-Generator Units 314 -$ NA 391 Accessory Electric Equipment 315 -$ NA 392 Misc. Power Plant Equipment 316 -$ NA 393 Subtotal Steam Produciton -$
394
395 Hydraulic Production
396 Land and Land Rights 330 -$ NA 397 Structures & Improvements 331 -$ NA 398 Reservoirs, Dams and Water Ways 332 -$ NA 399 Water Wheel, Turbine and Generator 333 -$ NA 400 Accessory Electric Equipment 334 -$ NA 401 Misc. Power Plant Equipment 335 -$ NA 402 Roads, Railroads and Bridges 336 -$ NA 403 Subtotal Hydraulic Production -$
404
405 Combustion Turbine & Other Production
406 Land and Land Rights 340 -$ NA 407 Structures & Improvements 341 155,300$ Baseload 408 Fuel Holders, Prod, & Acc. 342 -$ NA 409 Prime Movers 343 -$ NA 410 Generators & Other Production 344 111,722,271$ Baseload 411 Accessory Electric Equipment 345 -$ NA Line Adjusted Allocation
No. Item Account/ID Test Year Factor
Production
412 Misc. Production Plant 2000 -$ NA 413 Subtotal Combustion Turbine & Other Production 111,877,570$ 414
415 Total Production Plant 120,029,018$
416
417 Transmission Plant
418 Land and Land Rights 350 -$ NA 419 Reserved 351 -$ NA 420 Structures & Improvements 352 -$ NA 421 Station Equipment - System 353 -$ NA 422 Towers and Fixtures 354 -$ NA 423 Poles and Fixtures 355 -$ NA 424 Overhead Conductor 356 -$ NA 425 Underground Conductor 357 -$ NA 426 Underground Conduit 358 -$ NA 427 Misc. Transmission Plant 359 -$ NA 428 Subtotal Transmission Plant -$
429
430 Distribution Plant
431 Land and Land Rights 360 -$ NA 432 Structures & Improvements 361 -$ NA 433 Station Equipment 362 -$ NA 434 Misc. Plant 363 -$ NA 435 Towers and Fixtures 364 -$ NA 436 Overhead Conductor 365 -$ NA 437 Undgeround Conduit 366 -$ NA 438 Underground Conductor 367 -$ NA 439 Line Transformers 368 -$ NA 440 Services 369 -$ NA 441 Meters 370 -$ NA
442 Inst. on Customer Premises 371 -$ NA 443 Street Light / Signal System 373 -$ NA 444 Total Distribution Plant -$
445
446 Subtotal Plant Before General 120,029,018$
447
448 General Plant
449 Land and Land Rights 389 -$ NA 450 Structures & Improvements 390 4,062,642$ Total Gross Plant 451 Structures & Improvements - Other 3900 -$ NA 452 Office Furniture & Equipment 391 1,639,616$ Total Gross Plant 453 Info System Computers 3910 -$ NA 454 Transportation Equipment 392 2,564,873$ Total Gross Plant 455 Stores Equipment 393 11,370$ Total Gross Plant 456 Tools, Shop & Garage Equipment 394 88,246$ Total Gross Plant 457 Laboratory Equipment 395 203,456$ Total Gross Plant 458 Power Operated Equipment 396 369,851$ Total Gross Plant 459 Communication Equipment 397 4,279,791$ Total Gross Plant 460 Miscellaneous Equipment 398 267,190$ Total Gross Plant 461 Other Tangible Property 399 1,577$ Total Gross Plant 462 Subtotal General Plant 13,488,612$
463
464 Total Accumulated Depreciation 133,517,631$
465
466
467 Net Plant in Service
468 Intangible Plant
469 Organization 301 -$ NA 470 Franchises and Consents 302 -$ NA 471 Misc. Intangible Plant 303 4,817,894$ Baseload 472 Misc. Computer Software 3030 -$ NA 473 Subtotal Intangible Plant 4,817,894$
474
475 Production Plant
476 Steam Production
477 Land and Land Rights 310 17,142$ Baseload 478 Structures & Improvements 311 -$ NA 479 Boiler Plant Equipment 312 -$ NA 480 Engines and Engine Generators 313 -$ NA 481 Turbo-Generator Units 314 -$ NA 482 Accessory Electric Equipment 315 -$ NA 483 Misc. Power Plant Equipment 316 -$ NA 484 Subtotal Steam Produciton 17,142$
485
486 Hydraulic Production
487 Land and Land Rights 330 -$ NA 488 Structures & Improvements 331 -$ NA 489 Reservoirs, Dams and Water Ways 332 -$ NA 490 Water Wheel, Turbine and Generator 333 -$ NA 491 Accessory Electric Equipment 334 -$ NA 492 Misc. Power Plant Equipment 335 -$ NA 493 Roads, Railroads and Bridges 336 -$ NA 494 Subtotal Hydraulic Production -$
495
496 Combustion Turbine & Other Production
497 Land and Land Rights 340 1,038,596$ Baseload 498 Structures & Improvements 341 548,169$ Baseload 499 Fuel Holders, Prod, & Acc. 342 -$ NA 500 Prime Movers 343 -$ NA 501 Generators & Other Production 344 156,822,716$ Baseload 502 Accessory Electric Equipment 345 -$ NA 503 Misc. Production Plant 2000 -$ NA 504 Subtotal Combustion Turbine & Other Production 158,409,481$ 505
506 Total Production Plant 163,244,517$
507
508 Transmission Plant
509 Land and Land Rights 350 -$ NA 510 Reserved 351 -$ NA 511 Structures & Improvements 352 -$ NA 512 Station Equipment - System 353 -$ NA 513 Towers and Fixtures 354 -$ NA 514 Poles and Fixtures 355 -$ NA 515 Overhead Conductor 356 -$ NA Line Adjusted Allocation
No. Item Account/ID Test Year Factor
Production
516 Underground Conductor 357 -$ NA 517 Underground Conduit 358 -$ NA 518 Misc. Transmission Plant 359 -$ NA 519 Subtotal Transmission Plant -$
520
521 Distribution Plant
522 Land and Land Rights 360 -$ NA 523 Structures & Improvements 361 -$ NA 524 Station Equipment 362 -$ NA 525 Misc. Plant 363 -$ NA 526 Towers and Fixtures 364 -$ NA 527 Overhead Conductor 365 -$ NA 528 Undgeround Conduit 366 -$ NA 529 Underground Conductor 367 -$ NA 530 Line Transformers 368 -$ NA 531 Services 369 -$ NA 532 Meters 370 -$ NA
533 Inst. on Customer Premises 371 -$ NA 534 Street Light / Signal System 373 -$ NA 535 Total Distribution Plant -$
536
537 Subtotal Plant Before General 163,244,517$
538
539 General Plant
540 Land and Land Rights 389 2,027,929$ Total Gross Plant 541 Structures & Improvements 390 13,198,656$ Total Gross Plant 542 Structures & Improvements - Other 3900 -$ NA 543 Office Furniture & Equipment 391 563,728$ Total Gross Plant 544 Info System Computers 3910 -$ NA 545 Transportation Equipment 392 609,319$ Total Gross Plant 546 Stores Equipment 393 -$ Total Gross Plant 547 Tools, Shop & Garage Equipment 394 14,387$ Total Gross Plant 548 Laboratory Equipment 395 (0)$ Total Gross Plant 549 Power Operated Equipment 396 50,377$ Total Gross Plant 550 Communication Equipment 397 1,441,565$ Total Gross Plant 551 Miscellaneous Equipment 398 25,145$ Total Gross Plant 552 Other Tangible Property 399 3,154$ Total Gross Plant 553 Subtotal General Plant 17,934,260$
554
555 Total Net Plant in Service 181,178,777$
556
557
558 Labor
559
560 Production Labor
561 Steam Production Operation
562 Supervision & Engineering -$ NA 563 Fuel (Transportation & Handling) -$ NA 564 Steam Expense -$ NA 565 Electric Expense -$ NA 566 Miscellaneous -$ NA 567 Rent -$ NA
568 Total Steam Production Operation -$
569
570 Steam Production Maintenance
571 Supervision & Engineering -$ NA 572 Structures -$ NA
573 Boilers -$ NA
574 Electric Plant -$ NA 575 Miscellaneous Labor -$ NA 576 Total Steam Production Maintenance -$
577
578 Hydro Production Operation
579 Supervision & Engineering -$ NA 580 Water for Power -$ NA 581 Hydraulic Expense -$ NA 582 Electric Expense -$ NA 583 Miscellaneous -$ NA 584 Rent -$ NA
585 Total Hydro Production Operation -$
586
587 Hydro Production Maintenance
588 Supervision & Engineering -$ NA 589 Structures -$ NA
590 Reservoirs & Dams -$ NA 591 Electric Plant -$ NA 592 Miscellaneous Plant -$ NA 593 Total Hydro Production Maintenance -$
594
595 Combined Cycle Operation
596 Labor -$ NA
597 Fuel Handling -$ NA 598 Generation Expense -$ NA 599 Miscellaneous Plant -$ NA 600 Total Combined Cycle Operation -$
601
602 Combined Cycle Maintenance
603 Supervision & Engineering -$ NA 604 Structures -$ NA
605 Electric Plant -$ NA 606 Miscellaneous Plant -$ NA 607 Total Combined Cycle Maintenance -$
608
609 Other Production
610 RERC/Acorn Gen. Plant 6120130 3,188,365$ Baseload 611 Clearwater Generating Plant 6120140 1,012,152$ Baseload 612 PU Elec Power Supply Operations 6120000 9,685,528$ Baseload 613 Total Other Production 13,886,044$
614
615 Total Production Labor 13,886,044$
616
617 Transmission Labor
618 Transmission Operations
619 Supervision & Engineering -$ NA Line Adjusted Allocation
No. Item Account/ID Test Year Factor
Production
620 Load Dispatch -$ NA 621 Station Equipment -$ NA 622 Overhead Lines -$ NA 623 Underground Lines -$ NA 624 General Labor -$ NA 625 Miscellaneous -$ NA 626 Rents -$ NA
627 Total Transmission Operations -$
628
629 Transmission Maintenance
630 Supervision & Engineering -$ NA 631 Structures -$ NA
632 Station Equipment -$ NA 633 Overhead Lines -$ NA 634 Underground Lines -$ NA 635 Miscellaneous -$ NA 636 Total Transmission Maintenance -$
637
638 Wheeling
639 Wheeling -$ NA
640 Wheeling -$ NA
641 Total Wheeling -$
642
643 Total Transmission Labor -$
644
645 Distribution Labor
646 Distribution Operations
647 Electric Operations 6100000 -$ NA 648 PU Electric Field Operations 6105000 -$ NA 649 Energy Deliv. Engineering 6110000 -$ NA 650 Customer Engineering-GIS 6115000 -$ NA 651 Underground Lines -$ NA 652 Street Lighting -$ NA 653 Metering -$ NA
654 Customer Installations -$ NA 655 Miscellaneous -$ NA 656 Rents -$ NA
657 Total Distribution Operations -$
658
659 Distribution Maintenance
660 Supervision & Engineering -$ NA 661 Structures -$ NA
662 Stations Equipment -$ NA 663 Overhead Lines -$ NA 664 Underground Lines -$ NA 665 Transformers -$ NA 666 Street Lighting -$ NA 667 Metering -$ NA
668 Miscellaneous -$ NA 669 Total Distribution Maintenance -$
670
671 Total Distribution Labor -$
672
673 Customer Labor
674 Customer Accounting Expense
675 Pub Util Business Support 6004000 -$ NA 676 Pub Util Admin-Utility Billing 6005000 -$ NA 677 Pub Util Admin-Customer Service 6015000 -$ NA 678 Pub Util Admin-Marketing Service 6020000 -$ NA 679 Miscellaneous -$ NA 680 Total Customer Accounting Expense -$
681
682 Customer Service Expense
683 Customer Engineering-GIS -$ NA 684 Customer Assistance -$ NA 685 Advertisement / Marketing -$ NA 686 Miscellaneous -$ NA 687 Total Customer Service Expense -$
688
689 Sales Expense
690 Sales Expense -$ NA 691 Demonstrations & Selling -$ NA 692 Miscellaneous Sales Expense -$ NA 693 Total Sales Expense -$
694
695 Total Customer Labor -$
696
697 Total Labor Expense excluding A&G 13,886,044$
698
699 Administrative & General Labor
700 Pub Util Admin-Management Services 6000000 1,998,637$ Baseload 701 Pub Util Admin-Field Services 6010000 -$ Baseload 702 Legislative & Regulator Risk 6025000 85,996$ Baseload 703 Outside Services -$ NA 704 Property Insurance -$ NA 705 Injuries and Damages -$ NA 706 Electric Utility Communication Labor -$ NA 707 Miscellaneous -$ NA 708 Rents -$ NA
709 Transportation Pool General Labor -$ NA 710 Maintenance of General Plant -$ NA 711 N/A -$ NA
712 Total Administrative & General Labor 2,084,634$
713
714 Total Labor Expense 15,970,678$
715
716 Allocation Factors
717
718
719 Baseload Baseload
720
721 Fuel & Energy Fuel & Energy
722
Line Adjusted Allocation
No. Item Account/ID Test Year Factor
Production
723 Direct Assign Direct Assign
724
725 Purchased Power - WP-7A Purchased Power
726
727 Revenue Requirement Rev. Req
728
729 Gross Plant w/o General Gross Plant x/General
730
731 Gross General Plant Gross General Plant
732
733 Gross Steam Plant Gross Steam Plant
734
735 Gross CT Plant Gross CT Plant
736
737 Total Gross Plant Total Gross Plant
738
739 Total Net Plant Total Net Plant
740
741 Labor Excluding A&G Labor x/A&G
742
743 Total Labor Total Labor
744
745 CIP CIP
746
747 NA NA
748
749
Line
No. Item Account/ID
1 Production O&M
2 Steam Production Operation
3 Supervision & Engineering 500
4 Fuel (Transportation & Handling) 501
5 Steam Power Fuel - Gas 50110
6 Steam Power Fuel - Oil 50120
7 Steam Power Fuel - Coal 50130
8 Steam Expense 502
9 Electric Expense 505
10 Miscellaneous 506
11 Rent 507
12 Subtotal Steam Production Opeation
13 14 Steam Production Maintenance
15 Supervision & Engineering 510
16 Structures 511
17 Boilers 512
18 Electric Plant 513
19 Miscellaneous Labor 515
20 Subtotal Steam Production Maintenance
21 22 Nuclear Production Operation
23 Supervision & Engineering 517
24 Nuclear Fuel Expense 518
25 Electric Expense - Turbine Generators 523
26 Reserved NA
27 Miscellaneous Power Expenses 524
28 Reserved NA
29 Subtotal Nuclear Production Operation
30 31 Nuclear Production Maintenance
32 Supervision & Engineering 528
33 Reserved NA
34 Reserved NA
35 Reserved NA
36 Miscellaneous Plant 530
37 Subtotal Nuclear Production Maintenance
38 39 Combined Cycle Operation
40 Supervision & Engineering NA
41 Fuel NA
42 Combined Cycle Fuel - Gas NA
43 Combined Cycle Fuel - Oil NA
44 Generation Expense NA
45 Miscellaneous NA
46 Subtotal Combined Cycle Operation
47 48 Combined Cycle Maintenance
49 Supervision & Engineering NA
50 Structures NA
51 Electric Plant NA
52 Miscellaneous Plant NA
53 Subtotal Combined Cycle Maintenance
54 55 Other Production
56 Intermountain Power (take or pay) 546
57 Fuel Expense 547
58 Hoover (take or pay) 548
59 Misc. Other Power Generation 549
60 Palo Verde Power (take or pay) 550
61 Deseret Power (take or pay) 552
62 Maint/Generating & Elec. Equip. 553
63 System Load Control 556
64 Other Expenditures 557
65 Purchased Power 555
66 Purchased Power - Energy Direct Assignment 55501
67 Subtotal Other Production
68 69 Total Production O&M
70 71 Fuel & Purchased Power
72 73 Total Production O&M less Fuel & Purchased Power
74 75 Transmission O&M
76 Transmission Operation
77 Supervision & Engineering 560
78 Load Dispatch 561
79 Station Equipment 562
80 Overhead Lines 563
81 Underground Lines 564
82 Miscellaneous 566
83 Rents 567
84 Subtotal Transmission Operation
85 86 Transmission Maintenance
87 Supervision & Engineering 568
88 Structures 569
89 Station Equipment 570
90 Overhead Lines 571
91 Underground Lines 572
92 Miscellaneous 573
93 Subtotal Transmission Maintenance
94 95 Wheeling
96 Transmission Cost Fixed 565
97 Transmission Cost Variable 565
98 Subtotal Wheeling
99 100 Total Transmission O&M
101
102 Distribution O&M
103 Distribution Operations
Production
Demand Related Energy Related
Production Demand Blank Fuel & Energy Blank
-$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 321,200$ -$ -$ -$ -$ -$ -$ -$ 321,200$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 541,428$ -$ -$ -$ 541,428$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 3,304,682$ -$ 6,598,107$ -$ -$ -$ 19,294,411$ -$ 309,339$ -$ 617,624$ -$ -$ -$ -$ -$ 1,578,586$ -$ 3,151,794$ -$ -$ -$ -$ -$ 4,228,576$ -$ -$ -$ 3,650,747$ -$ -$ -$ 14,617,013$ -$ -$ -$ -$ -$ 119,746,439$ -$ -$ -$ -$ -$ 27,688,942$ -$ 149,408,375$ -$ 28,551,571$ -$ 149,408,375$ -$ 5,192,606$ -$ 149,408,375$ -$ 23,358,965$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ Line
No. Item Account/ID
Production
104 Operation Maintenance and Engineering 580
105 Load Dispatch 581
106 Station Equipment 582
107 Overhead Lines 583
108 Underground Lines 584
109 Street Lighting & Signal Expenses 585
110 Metering 586
111 Customer Installations 587
112 Miscellaneous 588
113 Rents 589
114 Subtotal Distribution Operations
115
116 Distribution Maintenance
117 Supervision 590
118 Structures 591
119 Station Equipment 592
120 Overhead Lines 593
121 Underground Lines 594
122 Transformers 595
123 Street Lighting & Signals 596
124 Metering 597
125 Miscellaneous 598
126 Subtotal Distribution Maintenance
127
128 Total Distribution O&M
129
130 Customer O&M
131 Customer Accounting Expense
132 Supervision 901
133 Meter Reading 902
134 Customer Records and Collection Expenses 903
135 Reserved NA
136 Uncollectible Accounts 904
137 Miscellaneous 905
138 Subtotal Customer Accounting Expense
139
140 Other Customer Costs
141 Supervision 907
142 Customer Assistance 908
143 Advertisement 909
144 Miscellaneous 910
145 Subotal Other Customer Costs
146
147 Sales Expense
148 Sales Expense - Supervision 911
149 Demonstrations & Selling 912
150 Advertising Expenses 913
151 Miscellaneous Sales Expense 916
152 Subtotal Sales Expense
153
154 Total Customer O&M
155
156 Administrative & General Expense
157 Administrative Salaries & Misc. Labor 920
158 Office Supplies & Expense 921
159 Interdepartmental Charges 922
160 Outside Services 923
161 Property Insurance 924
162 Injuries and Damages 925
163 Employee Pensions and Benefits 926
164 Franchise Requirements 927
165 Compliance & Consultants (Regulatory Commission Expense)928 166 General Advertising Expense 930
167 Rents 931
168 Miscellaneous General Expenses 933
169 Maintenance of General Plant 932
170 Duplicate Charges - Credit 929
171 Subtotal Administrative & General Expense
172
173 Miscellaneous and Clearing Accounts
174 General Government Charges 701
175 Expenses Transferred from Electric 702
176 IDI Utility Charges 703
177 Removal Expenses 704
178 Taxes 707
179 Stores Expenses 781
180 Transportation Expenses 782
181 Tool and Shop Expenses 783
182 Insurance 788
183 Non-Operating Expenses 790
184 Subtotal Miscellaneous and Clearing Accounts
185
186 Total O&M Expense
187
188 Total O&M Expense less Purchased Power
189
190 Additional Expenses & Deductions
191 Debt Service
192 Generation
193 Transmission
194 Distribution
195 Customer
196 New Debt
197 Total Debt Service
198
199 Taxes and Transfer to General Fund
200 General Fund Transfer
201 Other
202 Other
203 Other
204 Subtotal Taxes and Transfer to General Fund
205
206 Capital Paid from Current Earnings
Demand Related Energy Related
Production Demand Blank Fuel & Energy Blank
-$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 3,488,734$ -$ -$ -$ 260,756$ -$ -$ -$ (6,248,053)$ -$ -$ -$ 2,246,125$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 5,176,576$ -$ -$ -$ -$ -$ -$ -$ 3,949$ -$ -$ -$ 774$ -$ -$ -$ 970,104$ -$ -$ -$ 1,273,426$ -$ -$ -$ 53,788$ -$ -$ -$ -$ -$ -$ -$ 7,226,180$ -$ -$ -$ 10,541,865$ -$ -$ -$ 3,111,947$ -$ -$ -$ 27,625$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 396,414$ -$ -$ -$ (341,930)$ -$ -$ -$ 261,921$ -$ -$ -$ -$ -$ -$ -$ 13,997,842$ -$ -$ -$ 49,775,593$ -$ 149,408,375$ -$ 44,582,987$ -$ -$ -$ 18,746,160$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 23,996$ -$ 51,928$ -$ 18,770,156$ -$ 51,928$ -$ 9,274,815$ -$ 20,070,579$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 9,274,815$ -$ 20,070,579$ -$ Line
No. Item Account/ID
Production
207 Production
208 Transmission
209 Distribution
210 Customer
211 Street Lighting Capital
212 NA
213 Sutotal Capital Paid from Current Earnings
214
215 Reserves - Additional Cash Requirements
216
217 Total Additional Expenses & Deductions
218
219 Subtotal Revenue Requirement
220
221 Other Income
222 Other Operating Revenue:
223 Uncollectibles
224 Diversion 344400
225 Service Connect Charges - Electric 344410
226 Misc Service Revenues - Electric 344491
227 Misc Operating Revenues - Electric 344492
228 Corona Fees- Rev 344493
Cap and Trade Auction 344511
229 REC Sale 344523
230 RA Capacity Sale 344522
231 Low Carbon Fuel Standard Credits 344514
232 Non Energy Receipts ABC Admin OH 344513
233 Subtotal Other Operating Revenue
234
235 Other Non-Operating Revenues (Expenses):
236 Gain (Loss) on retirement of utility plant
237 Interest Income
238 Corona Fees - Rev 344493
239 Misc. Settlement Reimbursement 344494
240 Late Payment Penalties 353400
241 Land and Building Rental 373100
242 Other Property Rental 373120
243 Pole Attachments 373125
244 Substation Operation & Maintenance 373126
245 Substation Leasing 373127
246 Communication Services 373128
247 CIS User Fee 373132
248 Refunds and Reimbursements 374000
249 Miscellaneous Receipts 374200
250 Cash Over/Shortage 374207
251 Asset Forfeiture Revenue 374500
252 Bad Debt Recovery 374800
253 Settlement Recovery 374801
254 Settlement Recovery - SONGS 374802
255 Liquidated Damages 374810
256 Sale of Salvage Materials 380030
257 Damage Claim Recoveries 380100
258 Operating Transfer from 650 Fund 985650
259 Utilization Charges 61250000
260 Subtotal Other Non-Operating Revenue
261
262 Wholesale Sales
263
264 Transmission Revenue
265
266 Total Other Income
267
268 Total Retail Revenue Requirement
269
270
271
272
273
274
275
276
277
278
279
280
281
282
283 PLANT IN SERVICE
284
285 Gross Plant in Service
286 Intangible Plant
287 Organization 301
288 Franchises and Consents 302
289 Misc. Intangible Plant 303
290 Misc. Computer Software 3030
291 Subtotal Intangible Plant
292
293 Production Plant
294 Steam Production
295 Land and Land Rights 310
296 Structures & Improvements 311
297 Boiler Plant Equipment 312
298 Engines and Engine Generators 313
299 Turbo-Generator Units 314
300 Accessory Electric Equipment 315
301 Misc. Power Plant Equipment 316
302 Subtotal Steam Produciton
303
304 Hydraulic Production
305 Land and Land Rights 330
306 Structures & Improvements 331
307 Reservoirs, Dams and Water Ways 332
308 Water Wheel, Turbine and Generator 333
Demand Related Energy Related
Production Demand Blank Fuel & Energy Blank
5,570$ -$ 12,053$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 5,570$ -$ 12,053$ -$ 3,570,740$ -$ -$ -$ 31,621,281$ 20,134,560$ 81,396,874$ 169,542,935$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 5,545$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 1,037,821$ -$ -$ -$ 363,010$ -$ 785,550$ -$ 30,026$ -$ -$ -$ 1,436,402$ -$ 785,550$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 1,673,787$ -$ -$ -$ 42,843$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 238,501$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 20,869$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 1,975,999$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 3,412,401$ -$ 785,550$ -$ 77,984,473$ -$ 168,757,386$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 8,151,448$ -$ -$ -$ -$ -$ -$ -$ 8,151,448$ -$ -$ -$ 17,142$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 17,142$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ Line
No. Item Account/ID
Production
309 Accessory Electric Equipment 334
310 Misc. Power Plant Equipment 335
311 Roads, Railroads and Bridges 336
312 Subtotal Hydraulic Production
313
314 Combustion Turbine & Other Production
315 Land and Land Rights 340
316 Structures & Improvements 341
317 Fuel Holders, Prod, & Acc. 342
318 Prime Movers 343
319 Generators & Other Production 344
320 Accessory Electric Equipment 345
321 Misc. Production Plant 2000
322 Subtotal Combustion Turbine & Other Production
323
324 Total Production Plant
325
326 Transmission Plant
327 Land and Land Rights 350
328 Reserved 351
329 Structures & Improvements 352
330 Station Equipment - System 353
331 Towers and Fixtures 354
332 Poles and Fixtures 355
333 Overhead Conductor 356
334 Underground Conductor 357
335 Underground Conduit 358
336 Misc. Transmission Plant 359
337 Subtotal Transmission Plant
338
339 Distribution Plant
340 Land and Land Rights 360
341 Structures & Improvements 361
342 Station Equipment 362
343 Misc. Plant 363
344 Towers and Fixtures 364
345 Overhead Conductor 365
346 Undgeround Conduit 366
347 Underground Conductor 367
348 Line Transformers 368
349 Services 369
350 Meters 370
351 Inst. on Customer Premises 371
352 Street Light / Signal System 373
353 Total Distribution Plant
354
355 Subtotal Plant Before General
356
357 General Plant
358 Land and Land Rights 389
359 Structures & Improvements 390
360 Structures & Improvements - Other 3900
361 Office Furniture & Equipment 391
362 Info System Computers 3910
363 Transportation Equipment 392
364 Stores Equipment 393
365 Tools, Shop & Garage Equipment 394
366 Laboratory Equipment 395
367 Power Operated Equipment 396
368 Communication Equipment 397
369 Miscellaneous Equipment 398
370 Other Tangible Property 399
371 Subtotal General Plant
372
373 Total Gross Plant in Service
374
375
376 Accumulated Depreciation
377 Intangible Plant
378 Organization 301
379 Franchises and Consents 302
380 Misc. Intangible Plant 303
381 Misc. Computer Software 3030
382 Subtotal Intangible Plant
383
384 Production Plant
385 Steam Production
386 Land and Land Rights 310
387 Structures & Improvements 311
388 Boiler Plant Equipment 312
389 Engines and Engine Generators 313
390 Turbo-Generator Units 314
391 Accessory Electric Equipment 315
392 Misc. Power Plant Equipment 316
393 Subtotal Steam Produciton
394
395 Hydraulic Production
396 Land and Land Rights 330
397 Structures & Improvements 331
398 Reservoirs, Dams and Water Ways 332
399 Water Wheel, Turbine and Generator 333
400 Accessory Electric Equipment 334
401 Misc. Power Plant Equipment 335
402 Roads, Railroads and Bridges 336
403 Subtotal Hydraulic Production
404
405 Combustion Turbine & Other Production
406 Land and Land Rights 340
407 Structures & Improvements 341
408 Fuel Holders, Prod, & Acc. 342
409 Prime Movers 343
410 Generators & Other Production 344
411 Accessory Electric Equipment 345
Demand Related Energy Related
Production Demand Blank Fuel & Energy Blank
-$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 1,038,596$ -$ -$ -$ 703,469$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 268,544,986$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 270,287,051$ -$ -$ -$ 278,455,641$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 278,455,641$ -$ -$ -$ 2,027,929$ -$ -$ -$ 17,261,298$ -$ -$ -$ -$ -$ -$ -$ 2,203,344$ -$ -$ -$ -$ -$ -$ -$ 3,174,192$ -$ -$ -$ 11,370$ -$ -$ -$ 102,634$ -$ -$ -$ 203,456$ -$ -$ -$ 420,228$ -$ -$ -$ 5,721,356$ -$ -$ -$ 292,335$ -$ -$ -$ 4,731$ -$ -$ -$ 31,422,873$ -$ -$ -$ 309,878,514$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 8,151,448$ -$ -$ -$ -$ -$ -$ -$ 8,151,448$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 155,300$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 111,722,271$ -$ -$ -$ -$ -$ -$ -$ Line
No. Item Account/ID
Production
412 Misc. Production Plant 2000
413 Subtotal Combustion Turbine & Other Production
414
415 Total Production Plant
416
417 Transmission Plant
418 Land and Land Rights 350
419 Reserved 351
420 Structures & Improvements 352
421 Station Equipment - System 353
422 Towers and Fixtures 354
423 Poles and Fixtures 355
424 Overhead Conductor 356
425 Underground Conductor 357
426 Underground Conduit 358
427 Misc. Transmission Plant 359
428 Subtotal Transmission Plant
429
430 Distribution Plant
431 Land and Land Rights 360
432 Structures & Improvements 361
433 Station Equipment 362
434 Misc. Plant 363
435 Towers and Fixtures 364
436 Overhead Conductor 365
437 Undgeround Conduit 366
438 Underground Conductor 367
439 Line Transformers 368
440 Services 369
441 Meters 370
442 Inst. on Customer Premises 371
443 Street Light / Signal System 373
444 Total Distribution Plant
445
446 Subtotal Plant Before General
447
448 General Plant
449 Land and Land Rights 389
450 Structures & Improvements 390
451 Structures & Improvements - Other 3900
452 Office Furniture & Equipment 391
453 Info System Computers 3910
454 Transportation Equipment 392
455 Stores Equipment 393
456 Tools, Shop & Garage Equipment 394
457 Laboratory Equipment 395
458 Power Operated Equipment 396
459 Communication Equipment 397
460 Miscellaneous Equipment 398
461 Other Tangible Property 399
462 Subtotal General Plant
463
464 Total Accumulated Depreciation
465
466
467 Net Plant in Service
468 Intangible Plant
469 Organization 301
470 Franchises and Consents 302
471 Misc. Intangible Plant 303
472 Misc. Computer Software 3030
473 Subtotal Intangible Plant
474
475 Production Plant
476 Steam Production
477 Land and Land Rights 310
478 Structures & Improvements 311
479 Boiler Plant Equipment 312
480 Engines and Engine Generators 313
481 Turbo-Generator Units 314
482 Accessory Electric Equipment 315
483 Misc. Power Plant Equipment 316
484 Subtotal Steam Produciton
485
486 Hydraulic Production
487 Land and Land Rights 330
488 Structures & Improvements 331
489 Reservoirs, Dams and Water Ways 332
490 Water Wheel, Turbine and Generator 333
491 Accessory Electric Equipment 334
492 Misc. Power Plant Equipment 335
493 Roads, Railroads and Bridges 336
494 Subtotal Hydraulic Production
495
496 Combustion Turbine & Other Production
497 Land and Land Rights 340
498 Structures & Improvements 341
499 Fuel Holders, Prod, & Acc. 342
500 Prime Movers 343
501 Generators & Other Production 344
502 Accessory Electric Equipment 345
503 Misc. Production Plant 2000
504 Subtotal Combustion Turbine & Other Production
505
506 Total Production Plant
507
508 Transmission Plant
509 Land and Land Rights 350
510 Reserved 351
511 Structures & Improvements 352
512 Station Equipment - System 353
513 Towers and Fixtures 354
514 Poles and Fixtures 355
515 Overhead Conductor 356
Demand Related Energy Related
Production Demand Blank Fuel & Energy Blank
-$ -$ -$ -$ 111,877,570$ -$ -$ -$ 120,029,018$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 120,029,018$ -$ -$ -$ -$ -$ -$ -$ 4,062,642$ -$ -$ -$ -$ -$ -$ -$ 1,639,616$ -$ -$ -$ -$ -$ -$ -$ 2,564,873$ -$ -$ -$ 11,370$ -$ -$ -$ 88,246$ -$ -$ -$ 203,456$ -$ -$ -$ 369,851$ -$ -$ -$ 4,279,791$ -$ -$ -$ 267,190$ -$ -$ -$ 1,577$ -$ -$ -$ 13,488,612$ -$ -$ -$ 133,517,631$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 4,817,894$ -$ -$ -$ -$ -$ -$ -$ 4,817,894$ -$ -$ -$ 17,142$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 17,142$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 1,038,596$ -$ -$ -$ 548,169$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 156,822,716$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 158,409,481$ -$ -$ -$ 163,244,517$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ Line
No. Item Account/ID
Production
516 Underground Conductor 357
517 Underground Conduit 358
518 Misc. Transmission Plant 359
519 Subtotal Transmission Plant
520
521 Distribution Plant
522 Land and Land Rights 360
523 Structures & Improvements 361
524 Station Equipment 362
525 Misc. Plant 363
526 Towers and Fixtures 364
527 Overhead Conductor 365
528 Undgeround Conduit 366
529 Underground Conductor 367
530 Line Transformers 368
531 Services 369
532 Meters 370
533 Inst. on Customer Premises 371
534 Street Light / Signal System 373
535 Total Distribution Plant
536
537 Subtotal Plant Before General
538
539 General Plant
540 Land and Land Rights 389
541 Structures & Improvements 390
542 Structures & Improvements - Other 3900
543 Office Furniture & Equipment 391
544 Info System Computers 3910
545 Transportation Equipment 392
546 Stores Equipment 393
547 Tools, Shop & Garage Equipment 394
548 Laboratory Equipment 395
549 Power Operated Equipment 396
550 Communication Equipment 397
551 Miscellaneous Equipment 398
552 Other Tangible Property 399
553 Subtotal General Plant
554
555 Total Net Plant in Service
556
557
558 Labor
559
560 Production Labor
561 Steam Production Operation
562 Supervision & Engineering
563 Fuel (Transportation & Handling)
564 Steam Expense
565 Electric Expense
566 Miscellaneous
567 Rent
568 Total Steam Production Operation
569
570 Steam Production Maintenance
571 Supervision & Engineering
572 Structures
573 Boilers
574 Electric Plant
575 Miscellaneous Labor
576 Total Steam Production Maintenance
577
578 Hydro Production Operation
579 Supervision & Engineering
580 Water for Power
581 Hydraulic Expense
582 Electric Expense
583 Miscellaneous
584 Rent
585 Total Hydro Production Operation
586
587 Hydro Production Maintenance
588 Supervision & Engineering
589 Structures
590 Reservoirs & Dams
591 Electric Plant
592 Miscellaneous Plant
593 Total Hydro Production Maintenance
594
595 Combined Cycle Operation
596 Labor
597 Fuel Handling
598 Generation Expense
599 Miscellaneous Plant
600 Total Combined Cycle Operation
601
602 Combined Cycle Maintenance
603 Supervision & Engineering
604 Structures
605 Electric Plant
606 Miscellaneous Plant
607 Total Combined Cycle Maintenance
608
609 Other Production
610 RERC/Acorn Gen. Plant 6120130
611 Clearwater Generating Plant 6120140
612 PU Elec Power Supply Operations 6120000
613 Total Other Production
614
615 Total Production Labor
616
617 Transmission Labor
618 Transmission Operations
619 Supervision & Engineering
Demand Related Energy Related
Production Demand Blank Fuel & Energy Blank
-$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 163,244,517$ -$ -$ -$ 2,027,929$ -$ -$ -$ 13,198,656$ -$ -$ -$ -$ -$ -$ -$ 563,728$ -$ -$ -$ -$ -$ -$ -$ 609,319$ -$ -$ -$ -$ -$ -$ -$ 14,387$ -$ -$ -$ (0)$ -$ -$ -$ 50,377$ -$ -$ -$ 1,441,565$ -$ -$ -$ 25,145$ -$ -$ -$ 3,154$ -$ -$ -$ 17,934,260$ -$ -$ -$ 181,178,777$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 3,188,365$ -$ -$ -$ 1,012,152$ -$ -$ -$ 9,685,528$ -$ -$ -$ 13,886,044$ -$ -$ -$ 13,886,044$ -$ -$ -$ -$ -$ -$ -$ Line
No. Item Account/ID
Production
620 Load Dispatch
621 Station Equipment
622 Overhead Lines
623 Underground Lines
624 General Labor
625 Miscellaneous
626 Rents
627 Total Transmission Operations
628
629 Transmission Maintenance
630 Supervision & Engineering
631 Structures
632 Station Equipment
633 Overhead Lines
634 Underground Lines
635 Miscellaneous
636 Total Transmission Maintenance
637
638 Wheeling
639 Wheeling
640 Wheeling
641 Total Wheeling
642
643 Total Transmission Labor
644
645 Distribution Labor
646 Distribution Operations
647 Electric Operations 6100000
648 PU Electric Field Operations 6105000
649 Energy Deliv. Engineering 6110000
650 Customer Engineering-GIS 6115000
651 Underground Lines
652 Street Lighting
653 Metering
654 Customer Installations
655 Miscellaneous
656 Rents
657 Total Distribution Operations
658
659 Distribution Maintenance
660 Supervision & Engineering
661 Structures
662 Stations Equipment
663 Overhead Lines
664 Underground Lines
665 Transformers
666 Street Lighting
667 Metering
668 Miscellaneous
669 Total Distribution Maintenance
670
671 Total Distribution Labor
672
673 Customer Labor
674 Customer Accounting Expense
675 Pub Util Business Support 6004000
676 Pub Util Admin-Utility Billing 6005000
677 Pub Util Admin-Customer Service 6015000
678 Pub Util Admin-Marketing Service 6020000
679 Miscellaneous
680 Total Customer Accounting Expense
681
682 Customer Service Expense
683 Customer Engineering-GIS
684 Customer Assistance
685 Advertisement / Marketing
686 Miscellaneous
687 Total Customer Service Expense
688
689 Sales Expense
690 Sales Expense
691 Demonstrations & Selling
692 Miscellaneous Sales Expense
693 Total Sales Expense
694
695 Total Customer Labor
696
697 Total Labor Expense excluding A&G
698
699 Administrative & General Labor
700 Pub Util Admin-Management Services 6000000
701 Pub Util Admin-Field Services 6010000
702 Legislative & Regulator Risk 6025000
703 Outside Services
704 Property Insurance
705 Injuries and Damages
706 Electric Utility Communication Labor
707 Miscellaneous
708 Rents
709 Transportation Pool General Labor
710 Maintenance of General Plant
711 N/A
712 Total Administrative & General Labor
713
714 Total Labor Expense
715
716 Allocation Factors
717
718
719 Baseload
720
721 Fuel & Energy
722
Demand Related Energy Related
Production Demand Blank Fuel & Energy Blank
-$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 13,886,044$ -$ -$ -$ 1,998,637$ -$ -$ -$ -$ -$ -$ -$ 85,996$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 2,084,634$ -$ 15,970,678$ -$ -$ -$ 1 0 0 0
100% 0% 0% 0%
0 0 1 0
0% 0% 100% 0%
0 0 0 0
Line
No. Item Account/ID
Production
723 Direct Assign
724
725 Purchased Power - WP-7A
726
727 Revenue Requirement
728
729 Gross Plant w/o General
730
731 Gross General Plant
732
733 Gross Steam Plant
734
735 Gross CT Plant
736
737 Total Gross Plant
738
739 Total Net Plant
740
741 Labor Excluding A&G
742
743 Total Labor
744
745 CIP
746
747 NA
748
749
Demand Related Energy Related
Production Demand Blank Fuel & Energy Blank
0% 0% 0% 0%
53,805,363.08$ -$ 107,427,454.77$ -$ 33% 0% 67% 0%
77,984,473$ -$ 168,757,386$ -$ 32% 0% 68% 0%
278,455,641$ -$ -$ -$ 100% 0% 0% 0%
31,422,873$ -$ -$ -$ 100% 0% 0% 0%
0 0 0 0
0% 0% 0% 0%
0 0 0 0
0% 0% 0% 0%
309,878,514$ -$ -$ -$ 100% 0% 0% 0%
181,178,777$ -$ -$ -$ 100% 0% 0% 0%
13,886,044$ -$ -$ -$ 100% 0% 0% 0%
15,970,678$ -$ -$ -$ 100% 0% 0% 0%
5,570$ -$ 12,053$ -$ 32% 0% 68% 0%
0 0 0 0
0% 0% 0% 0%
Line
No. Item Account/ID
1 Production O&M
2 Steam Production Operation
3 Supervision & Engineering 500
4 Fuel (Transportation & Handling) 501
5 Steam Power Fuel - Gas 50110
6 Steam Power Fuel - Oil 50120
7 Steam Power Fuel - Coal 50130
8 Steam Expense 502
9 Electric Expense 505
10 Miscellaneous 506
11 Rent 507
12 Subtotal Steam Production Opeation
13 14 Steam Production Maintenance
15 Supervision & Engineering 510
16 Structures 511
17 Boilers 512
18 Electric Plant 513
19 Miscellaneous Labor 515
20 Subtotal Steam Production Maintenance
21 22 Nuclear Production Operation
23 Supervision & Engineering 517
24 Nuclear Fuel Expense 518
25 Electric Expense - Turbine Generators 523
26 Reserved NA
27 Miscellaneous Power Expenses 524
28 Reserved NA
29 Subtotal Nuclear Production Operation
30 31 Nuclear Production Maintenance
32 Supervision & Engineering 528
33 Reserved NA
34 Reserved NA
35 Reserved NA
36 Miscellaneous Plant 530
37 Subtotal Nuclear Production Maintenance
38 39 Combined Cycle Operation
40 Supervision & Engineering NA
41 Fuel NA
42 Combined Cycle Fuel - Gas NA
43 Combined Cycle Fuel - Oil NA
44 Generation Expense NA
45 Miscellaneous NA
46 Subtotal Combined Cycle Operation
47 48 Combined Cycle Maintenance
49 Supervision & Engineering NA
50 Structures NA
51 Electric Plant NA
52 Miscellaneous Plant NA
53 Subtotal Combined Cycle Maintenance
54 55 Other Production
56 Intermountain Power (take or pay) 546
57 Fuel Expense 547
58 Hoover (take or pay) 548
59 Misc. Other Power Generation 549
60 Palo Verde Power (take or pay) 550
61 Deseret Power (take or pay) 552
62 Maint/Generating & Elec. Equip. 553
63 System Load Control 556
64 Other Expenditures 557
65 Purchased Power 555
66 Purchased Power - Energy Direct Assignment 55501
67 Subtotal Other Production
68 69 Total Production O&M
70 71 Fuel & Purchased Power
72 73 Total Production O&M less Fuel & Purchased Power
74 75 Transmission O&M
76 Transmission Operation
77 Supervision & Engineering 560
78 Load Dispatch 561
79 Station Equipment 562
80 Overhead Lines 563
81 Underground Lines 564
82 Miscellaneous 566
83 Rents 567
84 Subtotal Transmission Operation
85 86 Transmission Maintenance
87 Supervision & Engineering 568
88 Structures 569
89 Station Equipment 570
90 Overhead Lines 571
91 Underground Lines 572
92 Miscellaneous 573
93 Subtotal Transmission Maintenance
94 95 Wheeling
96 Transmission Cost Fixed 565
97 Transmission Cost Variable 565
98 Subtotal Wheeling
99 100 Total Transmission O&M
101
102 Distribution O&M
103 Distribution Operations
Production
Direct Assignment Check Check
Direct Assignment Blank Total OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ 321,200$ OK OK -$ -$ -$ OK OK -$ -$ 321,200$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ 541,428$ OK OK -$ -$ 541,428$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
-$ -$ 9,902,789$ OK OK -$ -$ 19,294,411$ OK OK -$ -$ 926,962$ OK OK -$ -$ -$ OK OK -$ -$ 4,730,380$ OK OK -$ -$ -$ OK OK -$ -$ 4,228,576$ OK OK -$ -$ 3,650,747$ OK OK -$ -$ 14,617,013$ OK OK -$ -$ 119,746,439$ OK OK -$ -$ -$ OK OK -$ -$ 177,097,317$ OK OK -$ -$ 177,959,946$ OK OK -$ -$ 154,600,981$ OK OK -$ -$ 23,358,965$ OK OK OK OK
OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
OK OK
Line
No. Item Account/ID
Production
104 Operation Maintenance and Engineering 580
105 Load Dispatch 581
106 Station Equipment 582
107 Overhead Lines 583
108 Underground Lines 584
109 Street Lighting & Signal Expenses 585
110 Metering 586
111 Customer Installations 587
112 Miscellaneous 588
113 Rents 589
114 Subtotal Distribution Operations
115
116 Distribution Maintenance
117 Supervision 590
118 Structures 591
119 Station Equipment 592
120 Overhead Lines 593
121 Underground Lines 594
122 Transformers 595
123 Street Lighting & Signals 596
124 Metering 597
125 Miscellaneous 598
126 Subtotal Distribution Maintenance
127
128 Total Distribution O&M
129
130 Customer O&M
131 Customer Accounting Expense
132 Supervision 901
133 Meter Reading 902
134 Customer Records and Collection Expenses 903
135 Reserved NA
136 Uncollectible Accounts 904
137 Miscellaneous 905
138 Subtotal Customer Accounting Expense
139
140 Other Customer Costs
141 Supervision 907
142 Customer Assistance 908
143 Advertisement 909
144 Miscellaneous 910
145 Subotal Other Customer Costs
146
147 Sales Expense
148 Sales Expense - Supervision 911
149 Demonstrations & Selling 912
150 Advertising Expenses 913
151 Miscellaneous Sales Expense 916
152 Subtotal Sales Expense
153
154 Total Customer O&M
155
156 Administrative & General Expense
157 Administrative Salaries & Misc. Labor 920
158 Office Supplies & Expense 921
159 Interdepartmental Charges 922
160 Outside Services 923
161 Property Insurance 924
162 Injuries and Damages 925
163 Employee Pensions and Benefits 926
164 Franchise Requirements 927
165 Compliance & Consultants (Regulatory Commission Expense)928 166 General Advertising Expense 930
167 Rents 931
168 Miscellaneous General Expenses 933
169 Maintenance of General Plant 932
170 Duplicate Charges - Credit 929
171 Subtotal Administrative & General Expense
172
173 Miscellaneous and Clearing Accounts
174 General Government Charges 701
175 Expenses Transferred from Electric 702
176 IDI Utility Charges 703
177 Removal Expenses 704
178 Taxes 707
179 Stores Expenses 781
180 Transportation Expenses 782
181 Tool and Shop Expenses 783
182 Insurance 788
183 Non-Operating Expenses 790
184 Subtotal Miscellaneous and Clearing Accounts
185
186 Total O&M Expense
187
188 Total O&M Expense less Purchased Power
189
190 Additional Expenses & Deductions
191 Debt Service
192 Generation
193 Transmission
194 Distribution
195 Customer
196 New Debt
197 Total Debt Service
198
199 Taxes and Transfer to General Fund
200 General Fund Transfer
201 Other
202 Other
203 Other
204 Subtotal Taxes and Transfer to General Fund
205
206 Capital Paid from Current Earnings
Direct Assignment Check Check
Direct Assignment Blank Total OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
-$ -$ 3,488,734$ OK OK -$ -$ 260,756$ OK OK -$ -$ (6,248,053)$ OK OK -$ -$ 2,246,125$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ 5,176,576$ OK OK -$ -$ -$ OK OK -$ -$ 3,949$ OK OK -$ -$ 774$ OK OK -$ -$ 970,104$ OK OK -$ -$ 1,273,426$ OK OK -$ -$ 53,788$ OK OK -$ -$ -$ OK OK -$ -$ 7,226,180$ OK OK OK OK
-$ -$ 10,541,865$ OK OK -$ -$ 3,111,947$ OK OK -$ -$ 27,625$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ 396,414$ OK OK -$ -$ (341,930)$ OK OK -$ -$ 261,921$ OK OK -$ -$ -$ OK OK -$ -$ 13,997,842$ OK OK -$ -$ 199,183,968$ OK OK -$ -$ 44,582,987$ OK OK OK OK
OK OK
-$ -$ 18,746,160$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ 75,924$ OK OK -$ -$ 18,822,084$ OK OK OK OK
-$ -$ 29,345,394$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ 29,345,394$ OK OK OK OK
Line
No. Item Account/ID
Production
207 Production
208 Transmission
209 Distribution
210 Customer
211 Street Lighting Capital
212 NA
213 Sutotal Capital Paid from Current Earnings
214
215 Reserves - Additional Cash Requirements
216
217 Total Additional Expenses & Deductions
218
219 Subtotal Revenue Requirement
220
221 Other Income
222 Other Operating Revenue:
223 Uncollectibles
224 Diversion 344400
225 Service Connect Charges - Electric 344410
226 Misc Service Revenues - Electric 344491
227 Misc Operating Revenues - Electric 344492
228 Corona Fees- Rev 344493
Cap and Trade Auction 344511
229 REC Sale 344523
230 RA Capacity Sale 344522
231 Low Carbon Fuel Standard Credits 344514
232 Non Energy Receipts ABC Admin OH 344513
233 Subtotal Other Operating Revenue
234
235 Other Non-Operating Revenues (Expenses):
236 Gain (Loss) on retirement of utility plant
237 Interest Income
238 Corona Fees - Rev 344493
239 Misc. Settlement Reimbursement 344494
240 Late Payment Penalties 353400
241 Land and Building Rental 373100
242 Other Property Rental 373120
243 Pole Attachments 373125
244 Substation Operation & Maintenance 373126
245 Substation Leasing 373127
246 Communication Services 373128
247 CIS User Fee 373132
248 Refunds and Reimbursements 374000
249 Miscellaneous Receipts 374200
250 Cash Over/Shortage 374207
251 Asset Forfeiture Revenue 374500
252 Bad Debt Recovery 374800
253 Settlement Recovery 374801
254 Settlement Recovery - SONGS 374802
255 Liquidated Damages 374810
256 Sale of Salvage Materials 380030
257 Damage Claim Recoveries 380100
258 Operating Transfer from 650 Fund 985650
259 Utilization Charges 61250000
260 Subtotal Other Non-Operating Revenue
261
262 Wholesale Sales
263
264 Transmission Revenue
265
266 Total Other Income
267
268 Total Retail Revenue Requirement
269
270
271
272
273
274
275
276
277
278
279
280
281
282
283 PLANT IN SERVICE
284
285 Gross Plant in Service
286 Intangible Plant
287 Organization 301
288 Franchises and Consents 302
289 Misc. Intangible Plant 303
290 Misc. Computer Software 3030
291 Subtotal Intangible Plant
292
293 Production Plant
294 Steam Production
295 Land and Land Rights 310
296 Structures & Improvements 311
297 Boiler Plant Equipment 312
298 Engines and Engine Generators 313
299 Turbo-Generator Units 314
300 Accessory Electric Equipment 315
301 Misc. Power Plant Equipment 316
302 Subtotal Steam Produciton
303
304 Hydraulic Production
305 Land and Land Rights 330
306 Structures & Improvements 331
307 Reservoirs, Dams and Water Ways 332
308 Water Wheel, Turbine and Generator 333
Direct Assignment Check Check
Direct Assignment Blank Total OK OK
-$ -$ 17,623$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ 17,623$ OK OK -$ -$ 3,570,740$ OK OK -$ 51,755,842$ OK OK -$ 250,939,809$ OK OK OK OK
OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ 5,545$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ 1,037,821$ OK OK -$ -$ 1,148,560$ OK OK -$ -$ 30,026$ OK OK -$ -$ 2,221,952$ OK OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ 1,673,787$ OK OK -$ -$ 42,843$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ 238,501$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ 20,869$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ 1,975,999$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ 4,197,951$ OK OK -$ -$ 246,741,858$ OK OK OK OK
OK OK
OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ 8,151,448$ OK OK -$ -$ -$ OK OK -$ -$ 8,151,448$ OK OK OK OK
OK OK
-$ -$ 17,142$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ 17,142$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK Line
No. Item Account/ID
Production
309 Accessory Electric Equipment 334
310 Misc. Power Plant Equipment 335
311 Roads, Railroads and Bridges 336
312 Subtotal Hydraulic Production
313
314 Combustion Turbine & Other Production
315 Land and Land Rights 340
316 Structures & Improvements 341
317 Fuel Holders, Prod, & Acc. 342
318 Prime Movers 343
319 Generators & Other Production 344
320 Accessory Electric Equipment 345
321 Misc. Production Plant 2000
322 Subtotal Combustion Turbine & Other Production
323
324 Total Production Plant
325
326 Transmission Plant
327 Land and Land Rights 350
328 Reserved 351
329 Structures & Improvements 352
330 Station Equipment - System 353
331 Towers and Fixtures 354
332 Poles and Fixtures 355
333 Overhead Conductor 356
334 Underground Conductor 357
335 Underground Conduit 358
336 Misc. Transmission Plant 359
337 Subtotal Transmission Plant
338
339 Distribution Plant
340 Land and Land Rights 360
341 Structures & Improvements 361
342 Station Equipment 362
343 Misc. Plant 363
344 Towers and Fixtures 364
345 Overhead Conductor 365
346 Undgeround Conduit 366
347 Underground Conductor 367
348 Line Transformers 368
349 Services 369
350 Meters 370
351 Inst. on Customer Premises 371
352 Street Light / Signal System 373
353 Total Distribution Plant
354
355 Subtotal Plant Before General
356
357 General Plant
358 Land and Land Rights 389
359 Structures & Improvements 390
360 Structures & Improvements - Other 3900
361 Office Furniture & Equipment 391
362 Info System Computers 3910
363 Transportation Equipment 392
364 Stores Equipment 393
365 Tools, Shop & Garage Equipment 394
366 Laboratory Equipment 395
367 Power Operated Equipment 396
368 Communication Equipment 397
369 Miscellaneous Equipment 398
370 Other Tangible Property 399
371 Subtotal General Plant
372
373 Total Gross Plant in Service
374
375
376 Accumulated Depreciation
377 Intangible Plant
378 Organization 301
379 Franchises and Consents 302
380 Misc. Intangible Plant 303
381 Misc. Computer Software 3030
382 Subtotal Intangible Plant
383
384 Production Plant
385 Steam Production
386 Land and Land Rights 310
387 Structures & Improvements 311
388 Boiler Plant Equipment 312
389 Engines and Engine Generators 313
390 Turbo-Generator Units 314
391 Accessory Electric Equipment 315
392 Misc. Power Plant Equipment 316
393 Subtotal Steam Produciton
394
395 Hydraulic Production
396 Land and Land Rights 330
397 Structures & Improvements 331
398 Reservoirs, Dams and Water Ways 332
399 Water Wheel, Turbine and Generator 333
400 Accessory Electric Equipment 334
401 Misc. Power Plant Equipment 335
402 Roads, Railroads and Bridges 336
403 Subtotal Hydraulic Production
404
405 Combustion Turbine & Other Production
406 Land and Land Rights 340
407 Structures & Improvements 341
408 Fuel Holders, Prod, & Acc. 342
409 Prime Movers 343
410 Generators & Other Production 344
411 Accessory Electric Equipment 345
Direct Assignment Check Check
Direct Assignment Blank Total OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
-$ -$ 1,038,596$ OK OK -$ -$ 703,469$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ 268,544,986$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ 270,287,051$ OK OK -$ -$ 278,455,641$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ 278,455,641$ OK OK OK OK
-$ -$ 2,027,929$ OK OK -$ -$ 17,261,298$ OK OK -$ -$ -$ OK OK -$ -$ 2,203,344$ OK OK -$ -$ -$ OK OK -$ -$ 3,174,192$ OK OK -$ -$ 11,370$ OK OK -$ -$ 102,634$ OK OK -$ -$ 203,456$ OK OK -$ -$ 420,228$ OK OK -$ -$ 5,721,356$ OK OK -$ -$ 292,335$ OK OK -$ -$ 4,731$ OK OK -$ -$ 31,422,873$ OK OK -$ -$ 309,878,514$ OK OK OK OK
OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ 8,151,448$ OK OK -$ -$ -$ OK OK -$ -$ 8,151,448$ OK OK OK OK
OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ 155,300$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ 111,722,271$ OK OK -$ -$ -$ OK OK Line
No. Item Account/ID
Production
412 Misc. Production Plant 2000
413 Subtotal Combustion Turbine & Other Production
414
415 Total Production Plant
416
417 Transmission Plant
418 Land and Land Rights 350
419 Reserved 351
420 Structures & Improvements 352
421 Station Equipment - System 353
422 Towers and Fixtures 354
423 Poles and Fixtures 355
424 Overhead Conductor 356
425 Underground Conductor 357
426 Underground Conduit 358
427 Misc. Transmission Plant 359
428 Subtotal Transmission Plant
429
430 Distribution Plant
431 Land and Land Rights 360
432 Structures & Improvements 361
433 Station Equipment 362
434 Misc. Plant 363
435 Towers and Fixtures 364
436 Overhead Conductor 365
437 Undgeround Conduit 366
438 Underground Conductor 367
439 Line Transformers 368
440 Services 369
441 Meters 370
442 Inst. on Customer Premises 371
443 Street Light / Signal System 373
444 Total Distribution Plant
445
446 Subtotal Plant Before General
447
448 General Plant
449 Land and Land Rights 389
450 Structures & Improvements 390
451 Structures & Improvements - Other 3900
452 Office Furniture & Equipment 391
453 Info System Computers 3910
454 Transportation Equipment 392
455 Stores Equipment 393
456 Tools, Shop & Garage Equipment 394
457 Laboratory Equipment 395
458 Power Operated Equipment 396
459 Communication Equipment 397
460 Miscellaneous Equipment 398
461 Other Tangible Property 399
462 Subtotal General Plant
463
464 Total Accumulated Depreciation
465
466
467 Net Plant in Service
468 Intangible Plant
469 Organization 301
470 Franchises and Consents 302
471 Misc. Intangible Plant 303
472 Misc. Computer Software 3030
473 Subtotal Intangible Plant
474
475 Production Plant
476 Steam Production
477 Land and Land Rights 310
478 Structures & Improvements 311
479 Boiler Plant Equipment 312
480 Engines and Engine Generators 313
481 Turbo-Generator Units 314
482 Accessory Electric Equipment 315
483 Misc. Power Plant Equipment 316
484 Subtotal Steam Produciton
485
486 Hydraulic Production
487 Land and Land Rights 330
488 Structures & Improvements 331
489 Reservoirs, Dams and Water Ways 332
490 Water Wheel, Turbine and Generator 333
491 Accessory Electric Equipment 334
492 Misc. Power Plant Equipment 335
493 Roads, Railroads and Bridges 336
494 Subtotal Hydraulic Production
495
496 Combustion Turbine & Other Production
497 Land and Land Rights 340
498 Structures & Improvements 341
499 Fuel Holders, Prod, & Acc. 342
500 Prime Movers 343
501 Generators & Other Production 344
502 Accessory Electric Equipment 345
503 Misc. Production Plant 2000
504 Subtotal Combustion Turbine & Other Production
505
506 Total Production Plant
507
508 Transmission Plant
509 Land and Land Rights 350
510 Reserved 351
511 Structures & Improvements 352
512 Station Equipment - System 353
513 Towers and Fixtures 354
514 Poles and Fixtures 355
515 Overhead Conductor 356
Direct Assignment Check Check
Direct Assignment Blank Total OK OK
-$ -$ -$ OK OK -$ -$ 111,877,570$ OK OK -$ -$ 120,029,018$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ 120,029,018$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ 4,062,642$ OK OK -$ -$ -$ OK OK -$ -$ 1,639,616$ OK OK -$ -$ -$ OK OK -$ -$ 2,564,873$ OK OK -$ -$ 11,370$ OK OK -$ -$ 88,246$ OK OK -$ -$ 203,456$ OK OK -$ -$ 369,851$ OK OK -$ -$ 4,279,791$ OK OK -$ -$ 267,190$ OK OK -$ -$ 1,577$ OK OK -$ -$ 13,488,612$ OK OK -$ -$ 133,517,631$ OK OK OK OK
OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ 4,817,894$ OK OK -$ -$ -$ OK OK -$ -$ 4,817,894$ OK OK OK OK
OK OK
-$ -$ 17,142$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ 17,142$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
-$ -$ 1,038,596$ OK OK -$ -$ 548,169$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ 156,822,716$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ 158,409,481$ OK OK -$ -$ 163,244,517$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK Line
No. Item Account/ID
Production
516 Underground Conductor 357
517 Underground Conduit 358
518 Misc. Transmission Plant 359
519 Subtotal Transmission Plant
520
521 Distribution Plant
522 Land and Land Rights 360
523 Structures & Improvements 361
524 Station Equipment 362
525 Misc. Plant 363
526 Towers and Fixtures 364
527 Overhead Conductor 365
528 Undgeround Conduit 366
529 Underground Conductor 367
530 Line Transformers 368
531 Services 369
532 Meters 370
533 Inst. on Customer Premises 371
534 Street Light / Signal System 373
535 Total Distribution Plant
536
537 Subtotal Plant Before General
538
539 General Plant
540 Land and Land Rights 389
541 Structures & Improvements 390
542 Structures & Improvements - Other 3900
543 Office Furniture & Equipment 391
544 Info System Computers 3910
545 Transportation Equipment 392
546 Stores Equipment 393
547 Tools, Shop & Garage Equipment 394
548 Laboratory Equipment 395
549 Power Operated Equipment 396
550 Communication Equipment 397
551 Miscellaneous Equipment 398
552 Other Tangible Property 399
553 Subtotal General Plant
554
555 Total Net Plant in Service
556
557
558 Labor
559
560 Production Labor
561 Steam Production Operation
562 Supervision & Engineering
563 Fuel (Transportation & Handling)
564 Steam Expense
565 Electric Expense
566 Miscellaneous
567 Rent
568 Total Steam Production Operation
569
570 Steam Production Maintenance
571 Supervision & Engineering
572 Structures
573 Boilers
574 Electric Plant
575 Miscellaneous Labor
576 Total Steam Production Maintenance
577
578 Hydro Production Operation
579 Supervision & Engineering
580 Water for Power
581 Hydraulic Expense
582 Electric Expense
583 Miscellaneous
584 Rent
585 Total Hydro Production Operation
586
587 Hydro Production Maintenance
588 Supervision & Engineering
589 Structures
590 Reservoirs & Dams
591 Electric Plant
592 Miscellaneous Plant
593 Total Hydro Production Maintenance
594
595 Combined Cycle Operation
596 Labor
597 Fuel Handling
598 Generation Expense
599 Miscellaneous Plant
600 Total Combined Cycle Operation
601
602 Combined Cycle Maintenance
603 Supervision & Engineering
604 Structures
605 Electric Plant
606 Miscellaneous Plant
607 Total Combined Cycle Maintenance
608
609 Other Production
610 RERC/Acorn Gen. Plant 6120130
611 Clearwater Generating Plant 6120140
612 PU Elec Power Supply Operations 6120000
613 Total Other Production
614
615 Total Production Labor
616
617 Transmission Labor
618 Transmission Operations
619 Supervision & Engineering
Direct Assignment Check Check
Direct Assignment Blank Total OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ 163,244,517$ OK OK OK OK
-$ -$ 2,027,929$ OK OK -$ -$ 13,198,656$ OK OK -$ -$ -$ OK OK -$ -$ 563,728$ OK OK -$ -$ -$ OK OK -$ -$ 609,319$ OK OK -$ -$ -$ OK OK -$ -$ 14,387$ OK OK -$ -$ (0)$ OK OK -$ -$ 50,377$ OK OK -$ -$ 1,441,565$ OK OK -$ -$ 25,145$ OK OK -$ -$ 3,154$ OK OK -$ -$ 17,934,260$ OK OK -$ -$ 181,178,777$ OK OK OK OK
OK OK
OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
-$ -$ 3,188,365$ OK OK -$ -$ 1,012,152$ OK OK -$ -$ 9,685,528$ OK OK -$ -$ 13,886,044$ OK OK -$ -$ 13,886,044$ OK OK OK OK
OK OK
-$ -$ -$ OK OK Line
No. Item Account/ID
Production
620 Load Dispatch
621 Station Equipment
622 Overhead Lines
623 Underground Lines
624 General Labor
625 Miscellaneous
626 Rents
627 Total Transmission Operations
628
629 Transmission Maintenance
630 Supervision & Engineering
631 Structures
632 Station Equipment
633 Overhead Lines
634 Underground Lines
635 Miscellaneous
636 Total Transmission Maintenance
637
638 Wheeling
639 Wheeling
640 Wheeling
641 Total Wheeling
642
643 Total Transmission Labor
644
645 Distribution Labor
646 Distribution Operations
647 Electric Operations 6100000
648 PU Electric Field Operations 6105000
649 Energy Deliv. Engineering 6110000
650 Customer Engineering-GIS 6115000
651 Underground Lines
652 Street Lighting
653 Metering
654 Customer Installations
655 Miscellaneous
656 Rents
657 Total Distribution Operations
658
659 Distribution Maintenance
660 Supervision & Engineering
661 Structures
662 Stations Equipment
663 Overhead Lines
664 Underground Lines
665 Transformers
666 Street Lighting
667 Metering
668 Miscellaneous
669 Total Distribution Maintenance
670
671 Total Distribution Labor
672
673 Customer Labor
674 Customer Accounting Expense
675 Pub Util Business Support 6004000
676 Pub Util Admin-Utility Billing 6005000
677 Pub Util Admin-Customer Service 6015000
678 Pub Util Admin-Marketing Service 6020000
679 Miscellaneous
680 Total Customer Accounting Expense
681
682 Customer Service Expense
683 Customer Engineering-GIS
684 Customer Assistance
685 Advertisement / Marketing
686 Miscellaneous
687 Total Customer Service Expense
688
689 Sales Expense
690 Sales Expense
691 Demonstrations & Selling
692 Miscellaneous Sales Expense
693 Total Sales Expense
694
695 Total Customer Labor
696
697 Total Labor Expense excluding A&G
698
699 Administrative & General Labor
700 Pub Util Admin-Management Services 6000000
701 Pub Util Admin-Field Services 6010000
702 Legislative & Regulator Risk 6025000
703 Outside Services
704 Property Insurance
705 Injuries and Damages
706 Electric Utility Communication Labor
707 Miscellaneous
708 Rents
709 Transportation Pool General Labor
710 Maintenance of General Plant
711 N/A
712 Total Administrative & General Labor
713
714 Total Labor Expense
715
716 Allocation Factors
717
718
719 Baseload
720
721 Fuel & Energy
722
Direct Assignment Check Check
Direct Assignment Blank Total OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK OK OK
-$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ 13,886,044$ OK OK OK OK
-$ -$ 1,998,637$ OK OK -$ -$ -$ OK OK -$ -$ 85,996$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ -$ -$ OK OK -$ 2,084,634$ OK OK -$ -$ 15,970,678$ OK OK 0 0 1
0% 0% 100%
0 0 1
0% 0% 100%
1 0 1
Line
No. Item Account/ID
Production
723 Direct Assign
724
725 Purchased Power - WP-7A
726
727 Revenue Requirement
728
729 Gross Plant w/o General
730
731 Gross General Plant
732
733 Gross Steam Plant
734
735 Gross CT Plant
736
737 Total Gross Plant
738
739 Total Net Plant
740
741 Labor Excluding A&G
742
743 Total Labor
744
745 CIP
746
747 NA
748
749
Direct Assignment Check Check
Direct Assignment Blank Total OK OK
100% 0% 100%
0 -$ 161,232,817.85$ 0% 0% 100%
-$ -$ 246,741,858$ 0% 0% 100%
-$ -$ 278,455,641$ 0% 0% 100%
-$ -$ 31,422,873$ 0% 0% 100%
0 0 0
0% 0% 0%
0 0 0
0% 0% 0%
-$ -$ 309,878,514$ 0% 0% 100%
-$ -$ 181,178,777$ 0% 0% 100%
-$ -$ 13,886,044$ 0% 0% 100%
-$ -$ 15,970,678$ 0% 0% 100%
-$ -$ 17,623$ 0% 0% 100%
0 0 0
0% 0% 0%
Transmission
Line Adjusted Allocation
No. Item Account/ID Test Year Factor
1 Production O&M
2 Steam Production Operation
3 Supervision & Engineering 500 -$ NA 4 Fuel (Transportation & Handling) 501 -$ NA 5 Steam Power Fuel - Gas 50110 -$ NA 6 Steam Power Fuel - Oil 50120 -$ NA 7 Steam Power Fuel - Coal 50130 -$ NA 8 Steam Expense 502 -$ NA 9 Electric Expense 505 -$ NA 10 Miscellaneous 506 -$ NA 11 Rent 507 -$ NA
12 Subtotal Steam Production Opeation -$
13 14 Steam Production Maintenance
15 Supervision & Engineering 510 -$ NA 16 Structures 511 -$ NA 17 Boilers 512 -$ NA 18 Electric Plant 513 -$ NA 19 Miscellaneous Labor 515 -$ NA 20 Subtotal Steam Production Maintenance -$
21 22 Nuclear Production Operation
23 Supervision & Engineering 517 -$ NA 24 Nuclear Fuel Expense 518 -$ NA 25 Electric Expense - Turbine Generators 523 -$ NA 26 Reserved NA -$ NA 27 Miscellaneous Power Expenses 524 -$ NA 28 Reserved NA -$ NA 29 Subtotal Nuclear Production Operation -$
30 31 Nuclear Production Maintenance
32 Supervision & Engineering 528 -$ NA 33 Reserved NA -$ NA 34 Reserved NA -$ NA 35 Reserved NA -$ NA 36 Miscellaneous Plant 530 -$ NA 37 Subtotal Nuclear Production Maintenance -$
38 39 Combined Cycle Operation
40 Supervision & Engineering NA -$ NA 41 Fuel NA -$ NA
42 Combined Cycle Fuel - Gas NA -$ NA 43 Combined Cycle Fuel - Oil NA -$ NA 44 Generation Expense NA -$ NA 45 Miscellaneous NA -$ NA 46 Subtotal Combined Cycle Operation -$
47 48 Combined Cycle Maintenance
49 Supervision & Engineering NA -$ NA 50 Structures NA -$ NA 51 Electric Plant NA -$ NA 52 Miscellaneous Plant NA -$ NA 53 Subtotal Combined Cycle Maintenance -$
54 55 Other Production
56 Intermountain Power (take or pay) 546 -$ NA 57 Fuel Expense 547 -$ NA 58 Hoover (take or pay) 548 -$ NA 59 Misc. Other Power Generation 549 -$ NA 60 Palo Verde Power (take or pay) 550 -$ NA 61 Deseret Power (take or pay) 552 -$ NA 62 Maint/Generating & Elec. Equip. 553 -$ NA 63 System Load Control 556 -$ NA 64 Other Expenditures 557 -$ NA 65 Purchased Power 555 -$ NA 66 Purchased Power - Energy Direct Assignment 55501 -$ NA 67 Subtotal Other Production -$
68 69 Total Production O&M -$
70 71 Fuel & Purchased Power -$
72 73 Total Production O&M less Fuel & Purchased Power -$ 74 75 Transmission O&M
76 Transmission Operation
77 Supervision & Engineering 560 -$ NA 78 Load Dispatch 561 -$ NA 79 Station Equipment 562 -$ NA

Riverside City CouncilSeptember 19, 2023

Riverside City Council
September 19, 2023