Electric Cost of Service and Rate Design Study

Electric Cost of Service and Rate Design Study

City of Azusa, California

Azusa Light & Water Project No. 98925

3/16/2018

Electric Cost of Service and Rate Design Study

prepared for

City of Azusa, California Azusa Light & Water

Azusa, California

Project No. 98925

3/16/2018

prepared by

Burns & McDonnell Engineering Company, Inc. Azusa, California

COPYRIGHT © 2018 BURNS & McDONNELL ENGINEERING COMPANY, INC.

9400 Ward Parkway • Kansas City, MO 64114-3319 Tel: 816 333-9400 • Fax: 816 333-3690 • www.burnsmcd.com

March 16, 2018

Mr. Yarek Lehr

Acting Director of Utilities

Azusa Light & Water

729 N. Azusa Avenue

Azusa, California 91702

Re: Report on the 2017 Electric Cost of Service and Rate Design Study

Dear Mr. Lehr:

Burns & McDonnell is pleased to present this report on the Electric Cost of Service and Rate Design

Study (the Study) completed on behalf of the City of Azusa, California (the City) for the Azusa Light &

Water (AL&W).

This report presents the results of the Study, including proposed retail electric rate modifications. The

report also provides an explanation of the analyses performed to develop the five-year financial forecast,

the test year revenue requirement, and the allocated, unbundled cost-of-service for each of AL&W’s

electric rate classifications. It describes, in detail, the data, assumptions, and methodology used in

completing the Study. The report also provides Burns & McDonnell’s recommendations for AL&W for

retail electric rates.

Throughout each phase of the Study, Burns & McDonnell worked closely with AL&W staff to gather the

utility staff’s opinions and input. We greatly appreciate the opportunity to work with the City, AL&W

and its staff. We specifically wish to thank you, Yarek, for your guidance and input throughout the Study

process. Please contact us with any questions or comments you may have regarding this report.

Sincerely,

Burns & McDonnell

Ted J. Kelly Sara Ruckman

Senior Project Manager Project Analyst

TJK/sr

Electric Cost of Service and Rate Design Study Table of Contents

TOC-1 Burns & McDonnell

TABLE OF CONTENTS

Page No.

1.0 EXECUTIVE SUMMARY ................................................................................... 1-1 1.1 Overview .............................................................................................................. 1-1 1.2 Study Scope ......................................................................................................... 1-1 1.3 Revenue Requirements Analysis ......................................................................... 1-1

1.4 Cost-of-Service Analysis ..................................................................................... 1-2 1.5 Rate Analysis ....................................................................................................... 1-3 1.6 Recommendations ................................................................................................ 1-4

2.0 INTRODUCTION ............................................................................................... 2-1 2.1 Overview .............................................................................................................. 2-1

2.1.1 Current Rate Classifications ................................................................. 2-1 2.2 Study Scope ......................................................................................................... 2-1

2.3 Method of Analysis .............................................................................................. 2-2

3.0 REVENUE REQUIREMENTS ANALYSIS ........................................................ 3-1 3.1 Overview .............................................................................................................. 3-1

3.1.1 Customer Accounts ............................................................................... 3-1 3.1.2 Energy Requirements ............................................................................ 3-1

3.1.3 Peak Demand ........................................................................................ 3-2 3.2 Financial Forecast ................................................................................................ 3-2

3.2.1 Operating Revenues .............................................................................. 3-3 3.2.2 Operating Expenses .............................................................................. 3-3

3.2.3 Capital Improvement Expenditures ...................................................... 3-5 3.2.4 Debt Service .......................................................................................... 3-5

3.2.5 Projected Cash Flow ............................................................................. 3-6 3.2.6 Projected Revenue Requirements ......................................................... 3-8

4.0 COST-OF-SERVICE ANALYSIS ...................................................................... 4-1 4.1 Overview .............................................................................................................. 4-1 4.2 Revenue Requirement Unbundling ...................................................................... 4-1

4.2.1 Functionalization................................................................................... 4-1

4.2.2 Revenue Requirement Classification .................................................... 4-2 4.2.3 Revenue Requirement Allocation ......................................................... 4-2

4.3 Cost-of-Service Summary .................................................................................... 4-6

5.0 RATE ANALYSIS .............................................................................................. 5-1 5.1 Overview .............................................................................................................. 5-1

5.1.1 Rate Analysis Objectives ...................................................................... 5-1 5.2 Rate Classifications .............................................................................................. 5-1

5.2.1 Existing Rate Schedules ........................................................................ 5-2 5.2.2 Proposed Rate Schedules ...................................................................... 5-6



6.0 SUMMARY & RECOMMENDATIONS .............................................................. 6-1 6.1 Summary .............................................................................................................. 6-1

6.2 Recommendations ................................................................................................ 6-1



LIST OF TABLES

Page No.

Table 1-1: Test Year Base Rate Revenue Requirement........................................................... 1-2 Table 1-2: Cost-of-Service Summary ...................................................................................... 1-3 Table 1-3: Current Rate Classes and Structures ...................................................................... 1-3 Table 3-1: Projected Customer Accounts ................................................................................ 3-1

Table 3-2: Projected Energy Sales ........................................................................................... 3-2 Table 3-3: Projected System Load ........................................................................................... 3-2 Table 3-4: Projected Base Rate Revenue at Current Rates ...................................................... 3-3 Table 3-5: Purchased Power Expenses .................................................................................... 3-4 Table 3-6: Projected O&M Expenses ...................................................................................... 3-4

Table 3-7: Projected Capital Improvements ............................................................................ 3-5 Table 3-8: Projected Debt Obligations .................................................................................... 3-6

Table 3-9: Base Rate Revenues ............................................................................................... 3-7 Table 3-10: Cash Flow ............................................................................................................... 3-8

Table 3-12: Projected Revenue Requirements ........................................................................... 3-9 Table 4-1: Revenue Requirement Unbundled Assignment Summary ..................................... 4-3 Table 4-2: Allocation Factors by Type .................................................................................... 4-4

Table 4-3: Functional Cost Allocation Summary .................................................................... 4-6 Table 4-4: Cost-of-Service Summary ...................................................................................... 4-7

Table 5-1: Current Rate Classes and Structures ...................................................................... 5-2 Table 5-2: Existing Residential Service Electric Rates ........................................................... 5-3 Table 5-3: Existing Small Business Electric Rates .................................................................. 5-3

Table 5-4: Existing Medium Business Electric Rates ............................................................. 5-3

Table 5-5: Existing Large Business TOU Electric Rates ........................................................ 5-4 Table 5-6: Existing Municipal Accounts Electric Rates .......................................................... 5-4 Table 5-7: Existing Street Lighting and Outdoor Lighting Electric Rates .............................. 5-5

Table 5-8: Proposed Residential Service Electric Rates .......................................................... 5-6 Table 5-9: Proposed Small Business Electric Rates ................................................................ 5-6 Table 5-10: Proposed Medium Business Electric Rates ............................................................ 5-7

Table 5-11: Proposed Large Business TOU Electric Rates ....................................................... 5-7

Electric Cost of Service and Rate Design Study List of Abbreviations

i Burns & McDonnell

LIST OF ABBREVIATIONS

Abbreviation Term/Phrase/Name

AMI Advanced Metering Infrastructure

Burns & McDonnell Burns & McDonnell Engineering Company, Inc.

CIP Capital Improvement Plan

City City of Azusa, California

FARECAL Financing Authority for Resource Efficiency of California

FY Fiscal Year

kW kilowatt

kWh kilowatt-hour

AL&W Azusa Light & Water

MW megawatt

MWh megawatt-hour

NEM Net Energy Metering

O&M Operating & Maintenance Expense

Study Electric Cost of Service and Rate Design Study

TOU Time-of-Use

WH/SH Water and/or Space Heat

Electric Cost of Service and Rate Design Study List of Abbreviations

ii Burns & McDonnell

STATEMENT OF LIMITATIONS

In preparation of the Electric Cost of Service and Rate Design Study (the Study), Burns & McDonnell has

relied upon information obtained from the City of Azusa, California (the City) WEB portal and provided

by the electric division of Azusa Light & Water (AL&W). The information included various analyses,

computer-generated information and reports, audited financial reports, and other financial and statistical

information, as well as other documents such as operating budgets and current retail electric rate

schedules. In addition, input to key assumptions regarding expected future levels of revenue, sales, and

expenditures was provided by AL&W staff to Burns & McDonnell. While Burns & McDonnell has no

reason to believe that the information provided, and upon which Burns & McDonnell has relied, is

inaccurate or incomplete in any material respect, Burns & McDonnell has not independently verified such

information and cannot guarantee its accuracy or completeness.

Estimates and projections prepared by Burns & McDonnell relating to performance and costs are based

on Burns & McDonnell’s experience, qualifications, and judgment as a professional consultant. Since

Burns & McDonnell has no control over weather, cost and availability of labor, material and equipment,

labor productivity, contractors’ procedures and methods, unavoidable delays, economic conditions,

government regulations and laws (including interpretation thereof), competitive bidding, and market

conditions or other factors affecting such estimates or projections, Burns & McDonnell does not

guarantee the accuracy of its estimates or predictions.

For this report, Burns & McDonnell utilized unaudited actuals for fiscal year (FY) 2017 since the audit is

not yet available.

Revision History

Revision Issue Date Author Reviewer Description

0 8-Nov-2017 Kelly Ruckman Initial Draft

1 4-Jan-2018 Judy Tran Initial Draft Edits

1 14-Feb-2018 Yarek Lehr Initial Draft Edits

2 13-Mar-2018 Kelly Ruckman Final Draft

1.0 – EXECUTIVE SUMMARY

Electric Cost of Service and Rate Design Study Executive Summary

1-1 Burns & McDonnell

1.0 EXECUTIVE SUMMARY

1.1 Overview

To evaluate the adequacy of revenue requirements and to develop recommendations for a financial plan

and prepare appropriate rate adjustments and design, Azusa Light & Water (AL&W) retained Burns &

McDonnell to prepare a comprehensive Electric Cost of Service and Rate Design Study (the Study). This

report provides a review and the results of the Study, which included a revenue requirements analysis, a

cost-of-service analysis, and the development of electric rate modification recommendations. The Study

provides the basis for updated electric rates and develops updated unbundled rates for customer service,

power supply and power delivery. The report describes the development of the five-year financial forecast

used to illustrate the financial effects of new customers and load on the system.

1.2 Study Scope

This cost-of-service and rate analysis was conducted to address the ongoing changes taking place in the

electric industry. AL&W’s directive was to conduct a study that, when completed, meets the following

goals:

• Provide a five-year financial forecast

• Allocate costs to customer classes following industry guidelines

• Prepare revisions or recommendations to current rates, as needed

• Prepare and provide a financial forecast and rate analysis model for future use by AL&W

1.3 Revenue Requirements Analysis

The first phase of the Study completed for AL&W was the determination of the test year net revenue

requirement. This net revenue requirement was used as the basis for the subsequent phases of the project,

namely the cost-of-service and rate analyses. In order to calculate the test year net revenue requirement, a

five-year financial forecast was developed to project the results from the electric operations of AL&W.

The financial forecast is modeled on a fiscal year (FY) basis of July 1 through June 30.

Following the development of the financial forecast, a comparison of annual revenue and revenue

requirements was completed to determine whether sufficient revenue would be available to cover

projected operating and capital expenditures or if revenue adjustments would be required. Based on the

analysis completed and specific discussion regarding rates, Burns & McDonnell recommends AL&W

take no action to raise additional revenue over and above monies generated by current rates. AL&W is



maintaining adequate operating income and operating fund cash balances, meeting debt service coverage

requirements, and generating sufficient rate base returns.

A test year FY 2018 rate revenue and revenue requirement comparison is presented in Table 1-1. The

revenue requirement is equal to the annual cost-of-service minus other revenue. The annual cost-of-

service consists of total operating expenses, non-operating expenses, transfers, capital improvement plan

(CIP), debt service, and net change in operating reserves. The total test year FY 2018 rate revenue

requirement was calculated to be $33.2 million. AL&W desires to maintain a revenue-to-cost ratio of at

least 1.0. For the test year and beyond this minimum requirement is being met.

Table 1-1: Test Year Base Rate Revenue Requirement

1.4 Cost-of-Service Analysis

The development of the cost-of-service analysis followed the revenue requirements analysis. The cost-of-

service analysis included the assignment, or unbundling, of the various costs included in the test year

2018 revenue requirement to AL&W’s functional services. These unbundled cost components of the

revenue requirement were then allocated to the various electric rate classifications to determine cost

recovery requirements. The results of the cost-of-service analysis and the allocation of the test year

revenue requirement to AL&W’s rate classes are summarized in Table 1-2. The results are expressed in

both dollars and ¢/kWh.

Unaudited Actuals Test Year

Fiscal Year July 1 - June 30 2017 2018 2019 2020 2021

Annual Revenue Requirement ($)

Power Supply Expenses 23,408,509$ 18,568,317$ 18,396,300$ 19,347,000$ 20,348,000$

Nonoperating Expenses (FF, PILOT, Transfers, Int. Exp) 4,077,320$ 4,495,375$ 4,630,200$ 4,265,260$ 4,316,300$

Transfers out - Other (Fund 33 to Fund 31) 2,587,217$ 2,807,870$ 2,892,100$ 2,978,900$ 3,068,300$

Transfer to PCA Stabilization Account -$ 2,892,900$ 3,416,063$ 2,442,463$ 1,417,523$

Operating Expenses 7,677,207$ 8,934,301$ 9,931,600$ 9,478,800$ 9,763,200$

Capital Improvement Plan (Cash Financed) 500,000$ 2,965,000$ 5,100,000$ 2,850,000$ 1,100,000$

Debt Service 850,912$ 952,689$ 945,644$ 946,419$ 944,331$

Net Change in Operating Reserves 6,366,951$ 955,843$ (4,477,459)$ (1,429,340)$ (31,288)$

Cost of Service 45,468,117$ 42,572,296$ 40,834,448$ 40,879,501$ 40,926,366$

Less Other Revenues & Income

Misc. Billing Revenue 1,298,587$ 1,448,628$ 1,448,628$ 1,448,628$ 1,448,628$

Sales to Public Authorities (Major Only) 1,376,120$ 1,376,120$ 1,376,120$ 1,376,120$ 1,376,120$

Sales for Resale 4,017,473$ 3,479,486$ 2,000,000$ 2,000,000$ 2,000,000$

Other Operating Revenues 1,113,825$ 1,113,825$ 1,113,825$ 1,113,825$ 1,113,825$

Nonoperating Revenues 818,811$ 818,803$ 818,803$ 818,803$ 818,803$

Power Cost Adjustment Revenues 3,910,300$ 1,185,134$ 698,472$ 514,525$ 321,990$

Interfund Transfers -$ -$ -$ -$ -$

Total Other Revenues & Income 12,535,115$ 9,421,996$ 7,455,848$ 7,271,901$ 7,079,366$

Net Revenue Requirements 32,933,002$ 33,150,300$ 33,378,600$ 33,607,600$ 33,847,000$



Table 1-2: Cost-of-Service Summary

The lines labeled ‘Difference’ in Table 1-2 indicate the extent to which the projected annual revenues

generated from the current rates for each class would either exceed or fall short of the corresponding

revenue requirement. The table shows some cross subsidization between the rate classes, but not to a

significant degree.

1.5 Rate Analysis

The final phase of the Study completed for AL&W was the rate analysis. As previously discussed, the

financial forecast indicated that AL&W is on sound financial footing and the periodic rate adjustment

approach employed to date should sufficiently support the financial health of the utility moving forward.

Minimal base rate adjustments are recommended for the utility such as increasing the customer charge, or

fixed portion of the rate, and decreasing the energy portion of the rate. A summary of the rate schedule

components for each classification is provided below.

Table 1-3: Current Rate Classes and Structures

Total

System

Small

business (G-1)

Medium

business (G-2)

Large business

(T.O.U.)

Street Lights

(SL-1, SL-2,

SL-3)

Outdoor

Lights (SL-2,

OL)

Municipal

Accounts

(MS)

Residential

(D, WH/SH)

Comparison of Revenues ($)

Energy Sales - kWh 269,123,473 20,564,666 54,928,246 90,769,909 37,605 94,012 11,992,834 90,736,200

Revenue Requirement 33,150,300$ 2,659,428$ 6,175,517$ 9,214,196$ 10,300$ 17,300$ 1,444,820$ 13,628,739$

Revenue Generated By Existing Rates 33,150,300$ 3,111,000$ 6,950,300$ 10,145,800$ 10,300$ 17,300$ 1,342,500$ 11,573,100$

Difference -$ (451,572)$ (774,783)$ (931,604)$ -$ -$ 102,320$ 2,055,639$

Revenue Adjustment Required 0.00% -14.52% -11.15% -9.18% 0.00% 0.00% 7.62% 17.76%

Comparison of Revenues ($/kWh)

Revenue Requirement 0.1287$ 0.1351$ 0.1174$ 0.1060$ 0.2861$ 0.1922$ 0.1258$ 0.1569$

Revenue Generated By Existing Rates 0.1287$ 0.1580$ 0.1322$ 0.1168$ 0.2861$ 0.1922$ 0.1169$ 0.1332$

Difference -$ (0.0229)$ (0.0147)$ (0.0107)$ -$ -$ 0.0089$ 0.0237$

Revenue Adjustment Required 0.00% -14.52% -11.15% -9.18% 0.00% 0.00% 7.62% 17.76%

Basic/Cust

Charge

Energy Usage

ChargeDemand Charge

Minimum Monthly

Charge

Small Business (G-1) X X

Medium Business (G-2) X X X

Large Busienss (GL) X X X

Large Business (TOU + D) X X X

Street Lights (SL-1) X

Street Lights & Outdoor Lights (SL-2) X

Street Lights Customer Owned (SL-3) X

Outdoor Lights (OL) X

Municipal Accounts (MS) X X

Residential (D) X X

Residential (WH/SH) X X



1.6 Recommendations

Burns & McDonnell recommends a number of actions be taken by AL&W based on the analyses

conducted during the Study. The Study recommendations are presented herein.

• Based on the analysis completed and specific discussion regarding rates, Burns & McDonnell

recommends AL&W take no action to raise additional revenue over and above monies generated

by current rates.

• Burns & McDonnell recommends adjustments be made to rate structures by increasing the fixed

charge portion of the rate and lowering the energy charge portion of the rate. These adjustments

are revenue neutral for the system.

• AL&W should consider reassessing the PCA to more closely reflect reductions in power supply

costs. One approach may be to reassess the PCA base rate and adjust it if significantly different

than one currently used.

• AL&W should consider implementing the recommended time of use (TOU) seasonal rate

adjustments to more accurately reflect time-based power supply costs incurred by the system.

• AL&W may consider devising a modified TOU rate, and offer it as an option, whereby energy

component of the rate would be closely linked to the ISO wholesale energy prices in the Los

Angeles Basin.

• Burns & McDonnell recommends consideration of additional rate options once the advanced

metering infrastructure (AMI) program is completed and AL&W has a minimum of one year’s

worth of usage data on the system.

• AL&W should continue to monitor their financial position and revisit a rate analysis in three to

five years; or after the AMI system has been in place for at least one year.

AL&W should monitor its financial position, including adequacy of cost recovery and cash balances on

an on-going basis to help ensure the utility continues to meet its financial requirements. Burns &

McDonnell recommends the reexamination of the utility’s financial plan, costs-of-service, and electric

rates at most every five years.

2.0 – INTRODUCTION

Electric Cost of Service and Rate Design Study Introduction


2.0 INTRODUCTION

2.1 Overview

Azusa Light & Water (AL&W) is a municipally owned and operated electric utility established by the

City of Azusa, California (the City). AL&W provides retail electric services to consumers within the City

and the surrounding areas. The utility presently serves over 16,500 electric customers in its service

territory.

To reevaluate the adequacy of revenue requirements and to develop a financial plan, AL&W retained

Burns & McDonnell to prepare a comprehensive Electric Cost of Service and Rate Design Study (the

Study). This report provides a review and the results of the Study, which included a revenue requirements

analysis, a cost-of-service analysis, and the development of electric rate modification recommendations.

The report describes the development of the five-year financial forecast used to illustrate the financial

effects of new customers and load on the system.

2.1.1 Current Rate Classifications

AL&W customers are charged based on their service application, overall monthly kilowatt-hour (kWh)

energy consumption, and/or kilowatt (kW) demand characteristics. AL&W serves the following customer

classes:

• Small Business – Schedule G-1

• Medium Business – Schedule G-2

• Large Business – Schedule GL

• Large Business – Schedule Time-of-Use (TOU)

• Street Lights – Schedule SL-1, SL-2, SL-3

• Outdoor Lights – Schedule SL-2, OL

• Municipal Accounts – Schedule MS

• Residential – Schedule D, Water and/or Space Heat (WH/SH)

2.2 Study Scope

This cost-of-service and rate analysis was conducted primarily to address changes in the Azusa supply

portfolio and operations resulting from ISO markets/requirements and the ongoing changes and impacts

of renewable energy and climate change regulatory policies taking place in the electric industry. AL&W

directive was to conduct a study that, when completed, meets the following goals:

Electric Cost of Service and Rate Design Study Introduction


• Provide a five-year financial forecast

• Allocate costs to customer classes following industry guidelines

• Prepare recommendations for revision of current rates, if and as needed

• Prepare and provide a financial forecast and rate analysis model for future use by AL&W

2.3 Method of Analysis

The Study completed by Burns & McDonnell consisted of three phases. The first phase was the

development of a financial plan. The financial plan, and the resulting test year net revenue requirement

used in the subsequent phases of the Study, was developed based on a five-year financial forecast of

AL&W’s revenues and expenses. The financial forecast includes projections of known changes in annual

costs such as power cost projections and is based on information provided by AL&W. Other categories of

expenses were forecasted using historical trends or assumed annual rates of inflation. The forecast results

for FY 2018 were used as the test year net revenue requirement from which the cost-of-service analysis

was based. Section 3.0 of this report describes the development of the five-year financial forecast and net

revenue requirement.

The second phase of this Study consisted of the cost-of-service analysis which included the assignment,

or unbundling, of the various costs and margins included in the test year revenue requirement to AL&W’s

functional services (e.g. power supply, distribution, customer service, etc.). These unbundled cost

components of the test year revenue requirement were then allocated to the various electric rate

classifications. The resulting allocated cost-of-service for each rate classification was compared to the

adjusted annual revenues for each class in the FY 2018 test year to assess the projected cost recovery

provided by the existing retail rates. These steps and the corresponding results are explained in Section

4.0 of this report.

The results of the financial forecast and cost-of-service analysis provided a basis for the third phase which

was the development of recommendations pertaining to electric service rates to be considered by AL&W.

Section 5.0 of this report discusses the implications of the financial plan and cost-of-service results on

AL&W’s current electric rates and describes the proposed modifications to those retail rates.

Section 6.0 summarizes the results of the Study and Burns & McDonnell’s recommendations for AL&W

moving forward.

Throughout this report, references are made to various tables that detail specific aspects of the analyses

completed.

3.0 – REVENUE REQUIREMENTS ANALYSIS

Electric Cost of Service and Rate Design Study Revenue Requirements Analysis


3.0 REVENUE REQUIREMENTS ANALYSIS

3.1 Overview

The first phase of the Study completed for AL&W was the determination of the test year net revenue

requirement. This net revenue requirement was used as the basis for the subsequent phases of the project,

namely the cost-of-service and rate analyses. In order to calculate the test year net revenue requirement, a

five-year financial forecast was developed to project the results from the electric operations of AL&W.

3.1.1 Customer Accounts

Table 3-1 presents the projected numbers of electric customer accounts for AL&W from FY 2018 to FY

2021. Over the past few years, AL&W has experienced moderate growth in customer accounts.

Table 3-1: Projected Customer Accounts

3.1.2 Energy Requirements

For the analysis, AL&W provided historical actuals, by class, through FY 2017. The energy sales

projections assume relatively unchanged use of kWh per customer, with customer count increasing at a

rate slightly below one percent on average. As presented in Table 3-2, annual energy sales total

225,975,406 kWh in FY 2017 and are projected to increase to 263,018,182 kWh in FY 2021. Projected

energy sales include all municipal energy requirements.

CUSTOMERS

Small business (G-1) 1,332 1,353 1,375 1,397 1,419

Medium business (G-2) 278 278 278 278 278

Large business (T.O.U.) 34 34 34 34 34

Street Lights (SL-1, SL-2, SL-3) 65 54 45 37 31

Outdoor Lights (SL-2, OL) 42 46 50 55 60

Municipal Accounts (MS) 137 147 158 169 181

Total Commercial 1,888 1,912 1,940 1,970 2,003

Residential (D, WH/SH) 14,667 14,765 14,863 14,963 15,063

Total Customers 16,555 16,677 16,803 16,933 17,066



Table 3-2: Projected Energy Sales

Forecast energy requirements were calculated assuming a system loss factor of 4.27 percent from FY

2018 through FY 2021, which is equal to the average system loss factor from FY 2015 to FY 2017. As

presented in Table 3-3, annual AL&W energy purchases are projected to increase from 267,387,041 kWh

in FY 2017 to 274,743,791 kWh in FY 2021.

3.1.3 Peak Demand

The basis for projecting annual system peak demands from FY 2018 through FY 2021 were determined

by dividing the total annual energy requirement by the annual system load factor multiplied by 8760.

Table 3-3 summarizes the annual system peak demand for each year of the analysis.

Table 3-3: Projected System Load

3.2 Financial Forecast

The financial forecast was developed to estimate AL&W’s annual revenue requirements and included

projections of annual operating revenues, operating expenses, net non-operating income, and the resulting

net income, as well as projections of plant investment, debt service, and other cash flows from FY 2017

Unaudited Actuals


ENERGY SALES (kWh)

Small business (G-1) 19,381,913 19,687,000 20,008,000 20,328,000 20,648,000

Medium business (G-2) 52,584,411 52,584,000 52,584,000 52,584,000 52,584,000

Large business (T.O.U.) 86,896,074 86,896,000 86,896,000 86,896,000 86,896,000

Street Lights (SL-1, SL-2, SL-3) 43,301 36,000 30,000 25,000 21,000

Outdoor Lights (SL-2, OL) 82,464 90,000 98,000 108,000 118,000

Municipal Accounts (MS) 10,699,604 11,481,000 12,340,000 13,199,000 14,136,000

Total Commercial 169,687,767 170,774,000 171,956,000 173,140,000 174,403,000

Residential (D, WH/SH) 86,287,639 86,863,730 87,443,667 88,027,475 88,615,182

Total Energy Sales (kWh) 255,975,406 257,637,730 259,399,667 261,167,475 263,018,182

Forecast

Unaudited Actuals


Energy Sales and Supply

Billed Energy Sales (kWh) [1] 255,975,406 257,637,730 259,399,667 261,167,475 263,018,182

Line Losses, Electric Dept, Street Lighting (kWh) 11,411,635 11,485,743 11,564,292 11,643,102 11,725,609

Total Energy Requirement (kWh) 267,387,041 269,123,473 270,963,958 272,810,578 274,743,791

Purchased Power (kWh) [2] 267,387,041 269,123,473 270,963,958 272,810,578 274,743,791

Sales (%) 95.73% 95.73% 95.73% 95.73% 95.73%

Line Losses, Electric Dept, Street Lighting (%) 4.27% 4.27% 4.27% 4.27% 4.27%

Total Requirements (%) 100.00% 100.00% 100.00% 100.00% 100.00%

Average System Billing Demand (MW) 65.3 65.8 66.2 66.7 67.1

System Load Factor (%) [4] 46.75% 46.71% 46.71% 46.71% 46.71%

Forecast



and forecast FY 2018 through FY 2021. The forecast considered annual levels of internally generated

funds from operations and AL&W’s projected capital expenditure requirements. These estimates are

typically used to forecast the need for additional funds through retail rate adjustments, transfers from

reserves, and/or external capital financing.

The projections developed were summarized in a cash flow statement. The annual revenue requirements

were determined from this financial statement. The basis of the projections and the assumptions used in

the development of each component of the forecast are described herein.

3.2.1 Operating Revenues

3.2.1.1 Base Rate Revenues

Burns & McDonnell projected annual base rate revenues from current rates based on the average revenue

per kWh for each class and annual billing determinants from the projected energy sales. Table 3-4

presents projected base rate revenue for each year of the analysis period.

Table 3-4: Projected Base Rate Revenue at Current Rates

3.2.2 Operating Expenses

3.2.2.1 Power Supply Expense

Purchased power cost projections were developed based on projected energy and distribution costs

provided by AL&W. Table 3-5 presents an annual forecast of purchased power expenses. The cost of

purchased power for FY 2017 was based on unaudited actuals provided by AL&W and was projected for

each of the subsequent years in the forecast. The cost of purchased power is estimated to decrease from

$23.1 million in FY 2017 to $20.3 million in FY 2019. The primary reason for this drop in Purchased

Unaudited Actuals


BILLED REVENUES ($)

Small business (G-1) 3,061,227$ 3,111,000$ 3,161,700$ 3,212,200$ 3,262,800$

Medium business (G-2) 6,950,329$ 6,950,300$ 6,950,300$ 6,950,300$ 6,950,300$

Large business (T.O.U.) 10,145,766$ 10,145,800$ 10,145,800$ 10,145,800$ 10,145,800$

Street Lights (SL-1, SL-2, SL-3) 12,369$ 10,300$ 8,600$ 7,100$ 6,000$

Outdoor Lights (SL-2, OL) 15,837$ 17,300$ 18,800$ 20,700$ 22,700$

Municipal Accounts (MS) 1,251,142$ 1,342,500$ 1,443,000$ 1,543,400$ 1,653,000$

Total Commercial 21,436,671$ 21,577,200$ 21,728,200$ 21,879,500$ 22,040,600$

Residential (D, WH/SH) 11,496,331$ 11,573,100$ 11,650,400$ 11,728,100$ 11,806,400$

Total Billed Revenue ($) 32,933,002$ 33,150,300$ 33,378,600$ 33,607,600$ 33,847,000$

Forecast



Power cost is the retirement of the San Juan resource as part of the power supply portfolio and replacing it

with a lower cost resources.

Table 3-5: Purchased Power Expenses

3.2.2.2 Operation and Maintenance Expense

In addition to purchased power expenses, the AL&W electric utility incurs operating and maintenance

expenses (O&M) from its distribution and general plant, maintenance work, customer accounts, and

administrative operations. Including purchased power, O&M expenses for FY 2017 are estimated to be

$31.1 million, and future O&M expenses are projected to range from $27.5 million in FY 2018 to $30.1

million in FY 2021 as illustrated in Table 3-6.

Table 3-6: Projected O&M Expenses

Unaudited Actuals


Purchased Power Expense

Total Energy Cost ($) 23,329,856$ 17,459,287$ 16,319,840$ 16,319,840$ 16,319,840$

Total Resource Energy (kWh) 267,387,041 269,123,473 270,963,958 272,810,578 274,743,791

Total Energy Cost ($/kWh) 0.0873$ 0.0649$ 0.0602$ 0.0626$ 0.0651$

Escalation (%) 4.0% 4.0%

Energy Cost ($) 23,329,900$ 17,459,300$ 16,319,800$ 17,088,300$ 17,897,800$

Total Transmission Cost ($) 3,353,558$ 4,018,411$ 3,506,411$ 3,506,411$ 3,506,411$

Total Transmission Energy (kWh) 267,387,041 269,123,473 270,963,958 272,810,578 274,743,791

Total Transmission Cost ($/kWh) 0.0125$ 0.0149$ 0.0129$ 0.0135$ 0.0140$

Escalation (%) 4.0% 4.0%

Transmission Cost ($) 3,353,600$ 4,018,400$ 3,506,400$ 3,671,500$ 3,845,400$

Total Purchase Power Expense ($) 26,683,500$ 21,477,700$ 19,826,200$ 20,759,800$ 21,743,200$

Scheduling, System Control and Dispatching Services. 433,641$ 570,103$ 570,100$ 587,200$ 604,800$

RESALE (Excess wholesale+ Balancing/optimization) (4,017,473)$ (3,479,486)$ (2,000,000)$ (2,000,000)$ (2,000,000)$

Total Purchase Power Expense ($) 23,099,668$ 18,568,317$ 18,396,300$ 19,347,000$ 20,348,000$

Total Purchase Power Expense ($/kWh) 0.0864$ 0.0690$ 0.0679$ 0.0709$ 0.0741$

Forecast

Unaudited Actuals


Operating Expense Summary ($)

DISTRIBUTION PLANT EXPENSES ($) 890,000$ 890,000$ 916,700$ 944,400$ 972,800$

GENERAL PLANT EXPENSES ($) 357,849$ -$ -$ -$ -$

POWER SUPPLY EXPENSES ($) 23,099,668$ 18,568,317$ 19,125,400$ 19,347,000$ 20,348,000$

DISTRIBUTION EXPENSES (MAINTENANCE) ($) 3,503,932$ 3,975,790$ 4,095,100$ 4,217,900$ 4,344,400$

DISTRIBUTION EXPENSES (OPERATION) ($) 31,615$ 40,565$ 41,900$ 43,200$ 44,500$

DISTRIBUTION EXPENSES (MAINTENANCE) ($) 418,241$ 418,241$ 430,800$ 443,700$ 457,000$

CUSTOMER ACCOUNT EXPENSES ($) 2,780,162$ 3,605,455$ 3,713,600$ 3,825,100$ 3,939,900$

ADMINISTRATIVE AND GENERAL EXPENSES ($) 4,250$ 4,250$ 4,400$ 4,500$ 4,600$

Total Operating Expenses ($) 31,085,716 27,502,618$ 28,327,900 28,825,800 30,111,200

Forecast



3.2.3 Capital Improvement Expenditures

A forecast of capital expenditures for the electric system was developed by AL&W. The capital

expenditures forecast was incorporated into the financial model and utilized to determine the forecasted

annual plant in service and depreciation expense. AL&W funds its capital expenditures through a

combination of cash financing, debt financing and operating fund transfers. The largest of these capital

expenditures is the advanced metering infrastructure (AMI) upgrades, and substation facility

improvements. The electric system’s total estimated cost for the AMI project is $6.3 million in the next 3

years, and the estimated cost for the substation improvements totals to $5.1 million for FY 2018 through

FY 2021. Table 3-7 presents a summary of projected capital improvements for the forecast period.

Table 3-7: Projected Capital Improvements

3.2.4 Debt Service

Currently the electric utility pays annual payments on two series of revenue bonds, with one issued by the

Financing Authority for Resource Efficiency of California (FARECal) and the other issued by the City.

The bonds were issued to finance the acquisition, construction and installation of certain capital

improvement projects for the City of Azusa’s electric system. The projections of outstanding debt service

obligations from FY 2018 through FY 2021 are based on debt service schedules provided by AL&W.

Table 3-8 presents annual projections of outstanding debt service obligations of the electric utility.

Unaudited Actuals


Capital Improvements ($)

Department Equipment

AMI 500,000$ 2,500,000$ 2,500,000$ 750,000$ -$

Underground Electric Line Replacements & Line Extensions -$ 100,000$ 600,000$ 100,000$ 100,000$

Electric Substations Facility Improvements -$ 100,000$ 2,000,000$ 2,000,000$ 1,000,000$

Todd & 10th Street Electric Line Extension and Equipment -$ 150,000$ -$ -$ -$

LED Street Lights Fixture Retrofit -$ 115,000$ -$ -$ -$

Total Capital Improvements ($) 500,000$ 2,965,000$ 5,100,000$ 2,850,000$ 1,100,000$

Revenue Financed Capital Improvements 500,000$ 2,965,000$ 5,100,000$ 2,850,000$ 1,100,000$

Debt Financed Capital Improvements -$ -$ -$ -$ -$

[1] Capital improvements for 2018 through 2021 are based on a 5 year capital plan provided by Azusa

Forecast



Table 3-8: Projected Debt Obligations

3.2.5 Projected Cash Flow

The projection of cash flow for each year provided the basis for determining if the revenue generated

from operations sufficiently covered costs. Ultimately, the cash flow was used to establish AL&W test

year rate revenue requirement for FY 2018.

Annual base rate revenues were projected using the average retail rate revenue for each class and annual

billing determinants from the load forecast. Annual base rate revenues from base or customer charges,

energy usage charges, and demand charges were generated from the following classes: Small Business,

Medium Business, Large Business, Street Lights, Outdoor Lights, Municipal Accounts, and Residential

Service. In total, base rate revenues are projected to total $33.2 million in FY 2018 and reach $33.8

million in FY 2021 as seen in Table 3-9.

Other types of electric revenues include revenue from sales to public authorities, power cost adjustments,

sales for resale, miscellaneous billing revenues and other operating and non-operating revenues. Adding

all these sources of revenues together with revenue from retail sales produced total revenues in FY 2017

of $45.5 million. Total revenues are projected to decrease to $40.9 million by 2021. This decrease,

starting in FY 2018, can mainly be attributed to lower overall power supply costs after the completion of

San Juan divestiture in December and replacement with lower cost forward contracts. This is shown in

Table 3-10.

Electric expenses were projected for each year of the financial forecast. Expenses include purchased

power expenses, allocations to Fund 31 for customer related services, transfers to the PCA stabilization

account (including the stabilization requirement) and operating and maintenance expenses. Franchise

Fees, Payments in Lieu of Taxes (PILOT), and interest expense are included in non-operating expenses.

Expenses are projected to increase from $37.7 million in FY 2017 to $38.9 million in FY 2021.

Unaudited Actuals


Outstanding Debt ($)

Principal Outstanding - Beg. Bal. 6,600,000$ 5,950,000$ 5,170,000$ 4,375,000$ 3,555,000$

Principal -$ 780,000$ 795,000$ 820,000$ 845,000$

Sinking Fund 650,000$ -$ -$ -$ -$

Interest 25,344$ 3,621$ -$ -$ -$

Total Payment 675,344$ 783,621$ 795,000$ 820,000$ 845,000$

Debt Issue Cost Amort-Outstanding Debt -$ -$ -$ -$ -$

Principal Outstanding - End. Bal. 5,950,000$ 5,170,000$ 4,375,000$ 3,555,000$ 2,710,000$

Forecast



Net income before capital infrastructure plan (CIP) and debt service was $7.7 million in FY 2017, and

decreases to $2.0 million by FY 2021. This decrease is a result of the drop in total revenues while total

expenses increase slightly. After CIP and debt service are accounted for, cash and cash reserves remain at

a healthy level of $29.6 million in FY 2017 and $24.6 million in FY 2021. After deducting the $12.6

million minimum reserve requirement, unrestricted funds were at $17.0 million in FY 2017 and $12.0 in

FY 2021.

Table 3-9: Base Rate Revenues

Unaudited Actuals


System Operations ($) ($) ($) ($) ($)

Annual Energy Sales (kWh) 255,975,406 257,637,730 259,399,667 261,167,475 263,018,182

Average Electric Rate ($/kWh) 0.1701$ 0.1577$ 0.1500$ 0.1491$ 0.1483$

Base Rate Revenues

Commercial Electric Sales 21,436,671$ 21,577,200$ 21,728,200$ 21,879,500$ 22,040,600$

Residential Electric Sales 11,496,331$ 11,573,100$ 11,650,400$ 11,728,100$ 11,806,400$

Revenue from Retail Sales - Existing Rates 32,933,002$ 33,150,300$ 33,378,600$ 33,607,600$ 33,847,000$

Forecast



Table 3-10: Cash Flow

3.2.6 Projected Revenue Requirements

A summary of the test year FY 2018 rate revenue requirement is presented in Table 3-11. The annual

cost-of-service consists of total operating expenses, non-operating expenses, transfers, CIP, debt service,

and net change in operating reserves. Based on the revenue requirements analysis completed and specific

discussion regarding rate revenues and requirements, Burns & McDonnell recommends AL&W take no

action to raise additional revenue over and above monies generated by current rates and to go forward

with the approved PCA Stabilization Plan adjustments.

Unaudited Actuals


System Operations ($) ($) ($) ($) ($)

Beginning Balance - Cash & Cash Reserves 23,229,032 29,595,983 30,551,827 26,074,368 24,645,027

Revenues:

Commercial Electric Sales 21,436,671 21,577,200 21,728,200 21,879,500 22,040,600

Residential Electric Sales 11,496,331 11,573,100 11,650,400 11,728,100 11,806,400

Sales to Public Authorities (Major Only) 1,376,120 1,376,120 1,376,120 1,376,120 1,376,120

Power Cost Adjustment Revenues 3,910,300 1,185,134 698,472 514,525 321,990

Revenue from Retail Sales - Existing Rates 38,219,421 35,711,554 35,453,192 35,498,245 35,545,110

Sales for Resale 4,017,473 3,479,486 2,000,000 2,000,000 2,000,000

Misc. Billing Revenue 1,298,587 1,448,628 1,448,628 1,448,628 1,448,628

Total Electric Sales Revenues 43,535,481 40,639,668 38,901,820 38,946,873 38,993,738

Other Operating Revenues 1,113,825 1,113,825 1,113,825 1,113,825 1,113,825

Nonoperating Revenues 818,811 818,803 818,803 818,803 818,803

Total Revenues 45,468,117 42,572,296 40,834,448 40,879,501 40,926,366

Expenses:

Power Supply Expenses 23,408,509 18,568,317 18,396,300 19,347,000 20,348,000

Nonoperating Expenses (FF, PILOT, Transfers, Int. Exp) 4,077,320 4,495,375 4,630,200 4,265,260 4,316,300

Transfers out - Other (Fund 33 to Fund 31) 2,587,217 2,807,870 2,892,100 2,978,900 3,068,300

Transfer to PCA Stabilization Account - 2,892,900 3,416,063 2,442,463 1,417,523

Operating Expenses 7,677,207 8,934,301 9,931,600 9,478,800 9,763,200

Subtotal Expenses 37,750,253 37,698,763 39,266,263 38,512,423 38,913,323

Net Income/(Expense) Before CIP & Debt Service 7,717,864 4,873,533 1,568,185 2,367,078 2,013,043

Plant Capital Expenditures (Cash Financed) 500,000 2,965,000 5,100,000 2,850,000 1,100,000

Annual Debt Service 850,912 952,689 945,644 946,419 944,331

Subtotal Capital Improvements and Debt Service 1,350,912 3,917,689 6,045,644 3,796,419 2,044,331

Net Increase/Decrease in Cash & Reserves 6,366,951 955,843 (4,477,459) (1,429,340) (31,288)

Ending Balance - Cash & Cash Reserves 29,595,983 30,551,827 26,074,368 24,645,027 24,613,739

Minimum Reserve Requirement 12,600,000 12,600,000 12,600,000 12,600,000 12,600,000

Unrestricted Funds 16,995,983 17,951,827 13,474,368 12,045,027 12,013,739

Debt Service Coverage

Net Revenues Available for Debt Service 7,717,864 4,873,533 1,568,185 2,367,078 2,013,043

Debt Service 850,912 952,689 945,644 946,419 944,331

Reserves Available for Debt Service

Net Revenues and Reserves Available for Debt Service 7,717,864 4,873,533 1,568,185 2,367,078 2,013,043

Debt Service Coverage Based on Net Operating Revenues & Reserves 9.07 5.12 1.66 2.50 2.13

Forecast



Table 3-11: Projected Revenue Requirements

Unaudited Actuals Test Year


Annual Revenue Requirement ($)

Power Supply Expenses 23,408,509$ 18,568,317$ 18,396,300$ 19,347,000$ 20,348,000$

Nonoperating Expenses (FF, PILOT, Transfers, Int. Exp) 4,077,320$ 4,495,375$ 4,630,200$ 4,265,260$ 4,316,300$

Transfers out - Other (Fund 33 to Fund 31) 2,587,217$ 2,807,870$ 2,892,100$ 2,978,900$ 3,068,300$

Transfer to PCA Stabilization Account -$ 2,892,900$ 3,416,063$ 2,442,463$ 1,417,523$

Operating Expenses 7,677,207$ 8,934,301$ 9,931,600$ 9,478,800$ 9,763,200$

Capital Improvement Plan (Cash Financed) 500,000$ 2,965,000$ 5,100,000$ 2,850,000$ 1,100,000$

Debt Service 850,912$ 952,689$ 945,644$ 946,419$ 944,331$

Net Change in Operating Reserves 6,366,951$ 955,843$ (4,477,459)$ (1,429,340)$ (31,288)$

Cost of Service 45,468,117$ 42,572,296$ 40,834,448$ 40,879,501$ 40,926,366$

Less Other Revenues & Income

Misc. Billing Revenue 1,298,587$ 1,448,628$ 1,448,628$ 1,448,628$ 1,448,628$

Sales to Public Authorities (Major Only) 1,376,120$ 1,376,120$ 1,376,120$ 1,376,120$ 1,376,120$

Sales for Resale 4,017,473$ 3,479,486$ 2,000,000$ 2,000,000$ 2,000,000$

Other Operating Revenues 1,113,825$ 1,113,825$ 1,113,825$ 1,113,825$ 1,113,825$

Nonoperating Revenues 818,811$ 818,803$ 818,803$ 818,803$ 818,803$

Power Cost Adjustment Revenues 3,910,300$ 1,185,134$ 698,472$ 514,525$ 321,990$


Total Other Revenues & Income 12,535,115$ 9,421,996$ 7,455,848$ 7,271,901$ 7,079,366$


4.0 – COST-OF-SERVICE ANALYSIS

Electric Cost of Service and Rate Design Study Cost-of-Service Analysis


4.0 COST-OF-SERVICE ANALYSIS

4.1 Overview

The second phase of this Study was the development of the cost-of-service analysis. The test year revenue

requirement for FY 2018 developed from the financial forecast, described in Section 3.0 of this report,

was used as the basis for the cost-of-service analysis. Section 4.0 explains the basis of the

functionalization, classification and allocation efforts of the cost-of-service analysis. Tables showing the

assignment of the test year revenue requirement among functional services, as well as the development of

allocation factors and the allocation of the test year revenue requirement to AL&W’s rate classifications,

are presented in the following subsections.

4.2 Revenue Requirement Unbundling

The first step in the development of the cost-of-service analysis was the unbundling of the various

components of the test year revenue requirement by functional utility service. To a certain degree, the

electric service AL&W provides its customers is sold as a bundled product. However, this bundled

product involves the provision of multiple functional services. Utilities such as AL&W have a need to

unbundle the costs of providing the component services making up this bundled product. AL&W will

benefit from this separation of costs and providing its services at a functional level. New information,

provided by the AMI system currently being deployed, will aid AL&W in the overall management of its

costs and in the communication of service costs with its customers. The unbundling of AL&W’s costs

also allows separate pricing of individual services to be easily implemented if desired.

4.2.1 Functionalization

Four functional services were identified while analyzing AL&W’s three cost categories: Power

Production, Power Delivery, and Customer Services. Each cost category and its subordinate functional

services are summarized below.

• Power Production

o Demand – kW

o Energy – kWh

• Power Delivery

o Distribution – DIST

• Customer Service – CUST



4.2.2 Revenue Requirement Classification

The test year cost for each component of the revenue requirement was assigned to one or more of the

unbundled services. The unbundled assignment of each amount was based on the utilization of specific

data to estimate the portions of each item attributable to the various functional services. The amount for

each item was assigned using one of the following approaches:

• Direct Assignment – to one or more specific functional services due to the nature of the

account/element. For example, customer records and collection expenses under the Customer

Accounts cost category were assigned to the CUST functional service due to the nature of these

positions which are typically customer service or support oriented.

• Percentage Utilization – based on estimated level of activities within the account/element, costs

were assigned to multiple functional service categories.

• Composite Ratio Assignment – involves the assignment of costs based on the ratio of costs by

functional service, whose percentage allocations have already been established, to the associated

functional services for the test year. For example, interest income was assigned to functional

services based on the percentage distribution of all other system costs.

The manner in which each component was assigned to the functional services varied based on the nature

of the item. Burns & McDonnell developed the proposed unbundling of the components of the FY 2018

revenue requirement based on its understanding of the types of associated costs. A summary of the

assignment of each detailed component of the test year revenue requirement is shown in Table 4-1.

In Table 4-1, the assignment of the components of the test year revenue requirement for FY 2018 shows

that $16.7 million, or 50.33 percent, of AL&W’s test year revenue requirement was related to the power

supply energy – kWh functional service.

4.2.3 Revenue Requirement Allocation

Following the unbundling of the various components of the test year revenue requirement to the

functional utility services, the unbundled test year revenue requirement was allocated to AL&W’s retail

rate classifications. These allocations were developed to reflect the relative impact each rate class will

have on the level of each component of the test year revenue requirement.



Table 4-1: Revenue Requirement Unbundled Assignment Summary

AL&W currently bills its retail electric customers based on rate schedules that became effective in July

2017. The test year revenue requirement was allocated based to these categorizations. The test year FY

2018 rate classifications examined for the cost-of-service analysis are as follows:



• Large Business – Schedule GL, TOU




• Residential – Schedule D, WH/SH

4.2.3.1 Allocation Factors

Burns & McDonnell utilized billing history data and projections of future sales and loads to develop a

series of allocation factors. The allocation factors were developed based on billing determinants,

estimates of the contributions of each rate classification to AL&W’s total annual system energy

requirements, average monthly coincident system peak demand, and average monthly non-coincident

system peak demand. In addition, the total number of customers in each rate category was determined.

Test Year

2018 kW kWh DIST CUST

TOTAL O&M EXPENSE 31,997,993$ 4,720,975$ 18,166,632$ 4,929,198$ 4,181,188$

Cost of Service Ratio 14.75% 56.77% 15.40% 13.07%

OTHER REVENUE REQUIREMENTS

Debt Service 952,689$ 238,172$ -$ 666,882$ 47,634$

Transfers out - Other (Fund 33 to Fund 31) 2,807,870$ 701,968$ -$ 1,965,509$ 140,394$

Interfund Transfers Out - Surplus Fund -$ -$ -$ -$ -$

Transfer to PCA Stabilization Account 2,892,900$ 426,818$ 1,642,423$ 445,643$ 378,016$

Plant Capital Expenditures (Cash Financed) 2,965,000$ 437,455$ 1,683,358$ 456,750$ 387,437$

Net Change in Operating Reserves 955,843$ 141,025$ 542,673$ 147,245$ 124,900$

Total Other Revenue Requirements 10,574,303$ 1,945,438$ 3,868,454$ 3,682,029$ 1,078,382$

Cost of Service 42,572,296$ 6,666,413$ 22,035,086$ 8,611,227$ 5,259,569$

Cost of Service Ratio 15.66% 51.76% 20.23% 12.35%

OTHER OPERATING REVENUES

Misc. Billing Revenue (Fees (1,448,628)$ (213,730)$ (822,448)$ (223,157)$ (189,293)$

Other Sales to Public Authorities (Major Only) (1,376,120)$ (203,032)$ (781,282)$ (211,987)$ (179,818)$

Sales for Resale (3,479,486)$ (513,362)$ (1,975,453)$ (536,005)$ (454,665)$

Other Revenues (1,113,825)$ (164,333)$ (632,366)$ (171,582)$ (145,544)$

Power Cost Adjustment Revenues (1,185,134)$ (174,854)$ (672,851)$ (182,566)$ (154,862)$

Miscellaneous Revenues (Fees, Reimb., Collections) (554,703)$ (81,841)$ (314,929)$ (85,450)$ (72,483)$

Interest revenue (264,100)$ (38,965)$ (149,941)$ (40,684)$ (34,510)$


Total Other Revenues (9,421,996)$ (1,390,119)$ (5,349,271)$ (1,451,431)$ (1,231,175)$


15.92% 50.33% 21.60% 12.15%

UNBUNDLED COSTS

Description



Ratios were calculated of each class’s contribution for each statistic to the corresponding total. These

ratios were used as cost allocation factors to allocate each unbundled component of the test year revenue

requirement to the rate classes. These allocation factors are presented in Table 4-2 and the basis for their

development are provided in the following sections.

Table 4-2: Allocation Factors by Type

4.2.3.1.1 Energy Allocation

An energy allocation factor was developed for use in the apportionment of all energy-related expenses.

Based on the billing data provided, energy sales to each of AL&W’s rate classes were determined. The

energy sales for each class were factored up to the system level. System losses were assumed to occur

between three voltage levels, from power supply to transmission, from transmission voltage to primary

distribution voltage, and from primary distribution voltage to secondary distribution voltage. All customer

classes receive service at secondary distribution voltage levels, so for the analysis, each class shared

proportionally equal losses based on energy sales. The ratios of the resulting estimated contributions of

each class to the total system energy requirements represented the energy allocation factor.

4.2.3.1.2 Demand Allocation

The determination of system demand contributions for each rate class was more complex than the

development of the energy allocation factors for two reasons. First, the normal operation of an electric

utility does not require maintaining the same amount of demand-related data as it does energy-related

data. Therefore, there was not an equal amount of data from which to base the analysis. The second

reason is that there are a variety of methodologies that may be used in allocating the demand costs of an

electric utility. Ideally, hourly demand meters and load profile information would be available for all

AL&W customers from which accurate coincident and non-coincident peak demand data could be

Total

System

Small business (G-

1)

Medium business

(G-2)

Large business

(T.O.U.)

Street Lights (SL-

1, SL-2, SL-3)

Outdoor Lights

(SL-2, OL)

Municipal

Accounts (MS)

Residential (D,

WH/SH)

Energy Allocations

Total Energy Requirement 269,123,473 20,564,666 54,928,246 90,769,909 37,605 94,012 11,992,834 90,736,200

Energy Allocation Factor 1.000 0.076 0.204 0.337 0.000 0.000 0.045 0.337

Demand Allocations

Contribution to Coincident Peak 65,768 6,010 15,224 18,239 0 0 3,856 22,440

Coincident Peak Alloc. Factor 1.000 0.091 0.231 0.277 0.000 0.000 0.059 0.341

Contribution to Non-Coin. Peak 56,114 4,515 11,612 16,447 9 21 2,794 20,716

System NCP Allocation Factor 1.000 0.080 0.207 0.293 0.000 0.000 0.050 0.369

Customer Allocation

Number of Customers 16,677 1,353 278 34 54 46 147 14,765

Unweighted Customer Allocation Factor 1.000 0.081 0.017 0.002 0.003 0.003 0.009 0.885

Relative Weight 1.0 1.0 3.0 0.5 1.0 1.0 1.0

Weighted No. of Customers 16,718 1,353 278 102 27 46 147 14,765

Weighted Customer Allocation Factor 1.000 0.081 0.017 0.006 0.002 0.003 0.009 0.883



obtained. If data is compiled from a statistically valid sample of each classification, load profile results

obtained from each sample could be analyzed and applied to entire classes in the future. In the future,

once the AMI installations are complete, data will be available for all customers.

Burns & McDonnell refined proxy load research data to develop representative coincident peak and non-

coincident peak load data for each of AL&W’s customer classes. Since the test year system peak is

expected to occur in the afternoon hours of the summer season, it was assumed that the Street Lighting

classes would have no load on the system at that time and, therefore, would not contribute to the system

coincident peak demand.

For each class, maximum demands were estimated based on load factors from the proxy load data

available to Burns & McDonnell from a comparable electric utility in Southern California. The load

factors were applied to the corresponding test year energy sales for each class to determine the average

non-coincident peak for each class. Ratios of each class’s non-coincident peak demands to the total for all

classes were calculated. These ratios represented the factors to be used in allocating the system demand

costs among the various rate classes.

4.2.3.1.3 Customer Allocation

Customer allocation factors were developed to allocate the costs of metering, billing, call center, and

other administrative costs to the various rate classifications. Customer allocation factors were based on

relative weighting of the number of customers included in each rate class served by AL&W. Relative

weights were estimated to reflect differences in the effort required and the cost incurred to provide

customer services to customers in the different rate classes.

4.2.3.2 Cost Allocation

Each component item of the test year revenue requirement, which was classified and assigned to the

various functional utility services, was allocated to the appropriate customer rate classifications using the

corresponding allocation factors. The allocated amounts were summarized for each rate class. Table 4-3

presents a summary of the allocation of the net revenue requirement to the rate classifications by the

unbundled functional services. The total amounts in Table 4-3 for each unbundled service within each

component of the test year revenue requirement were carried forward from Table 4-1.



Table 4-3: Functional Cost Allocation Summary

4.3 Cost-of-Service Summary

The results of the cost-of-service analysis and the allocation of the test year revenue requirement to

AL&W’s rate classes are presented in Table 4-4. The results are broken out into energy-related costs,

expressed in both dollars and cents per kWh; peak demand-related costs, expressed in both dollars and

cents per kW of system power supply billing demand per month; distribution-related costs, expressed in

both dollars and dollars per kW of system power supply billing demand per month; and customer-related

costs, expressed in dollars per customer per month. The total cost-of-service is expressed in both dollars

and cents per kWh.

AL&W’s rate revenue requirement of $33.2 million and the total projected system sales of 269,123 MWh

translates to an average cost of 12.87¢/kWh. Table 4-4 also shows the net requirement of providing

service to each class. For example, the cost allocated to the Residential Service rate class in FY 2018

totals $13.6 million. Based on the total energy sales from Residential Service customers of 90,736 MWh,

the base rate requirement to provide service to the Residential Service customer class is 15.69¢/kWh.

Table 4-4 includes a Revenue Comparison that compares the net revenue requirement to the projected

revenue that would be generated by current rates. This analysis indicates the extent to which the test year

revenues generated from existing rates for each class would either exceed or fall short of the

corresponding revenue requirement. The results show the current conditions of how revenues are

generated in comparison to how costs are incurred among classes. For example, the Residential class is

receiving the largest subsidy under current rates. Conversely, the Small Business class is recovering more

cost than it has been allocated, and therefore, is subsidizing more cost than any other class. Since AL&W

wants to continue providing low cost rates to the Residential class, no changes to current rates are

recommended to mitigate this slight subsidization.



Table 4-4: Cost-of-Service Summary

Total

System

Small

business (G-1)

Medium

business (G-2)

Large business

(T.O.U.)

Street Lights

(SL-1, SL-2,

SL-3)

Outdoor

Lights (SL-2,

OL)

Municipal

Accounts

(MS)

Residential

(D, WH/SH)

Summary of Cost of Service

Energy Cost:

Energy Sales (kWh) 257,637,730 19,687,000 52,584,000 86,896,000 36,000 90,000 11,481,000 86,863,730

Total Cost 16,685,815$ 1,275,022$ 3,405,584$ 5,627,788$ 2,332$ 5,829$ 743,563$ 5,625,698$

Dollars/kWh 0.06476 0.06476 0.06476 0.06476 0.06476 0.06476 0.06476 0.06476

Demand Cost (Peak):

Contribution Coincident Peak (kW) 65,768 6,010 15,224 18,239 0 0 3,856 22,440

Total Cost 5,276,294$ 482,192$ 1,221,318$ 1,463,231$ -$ -$ 309,323$ 1,800,231$

$/kW-mo 6.69 6.69 6.69 6.69 0.00 0.00 6.69 6.69

Demand Cost (Distribution):

Contribution Non-Coincident Peak (kW) 56,114 4,515 11,612 16,447 9 21 2,794 20,716

Total Cost 7,159,796$ 576,031$ 1,481,594$ 2,098,595$ 1,095$ 2,739$ 356,495$ 2,643,248$

$/kW-mo 10.63 10.63 10.63 10.63 10.63 10.63 10.63 10.63

Demand Cost (Total):

Contribution Non-Coincident Peak (kW) 56,114 4,515 11,612 16,447 9 21 2,794 20,716

Total Cost 12,436,090$ 1,058,222$ 2,702,912$ 3,561,826$ 1,095$ 2,739$ 665,818$ 4,443,478$

$/kW-mo 18.47 19.53 19.40 18.05 10.63 10.63 19.86 17.87

Customer Service Cost:

Number of Customers 16,677 1,353 278 34 54 46 147 14,765

Total Cost 4,028,394$ 326,022$ 66,988$ 24,578$ 6,506$ 11,084$ 35,422$ 3,557,794$

$/Customer/Month 20.13 20.08 20.08 60.24 10.04 20.08 20.08 20.08

Revenue Requirement Before Adjustments33,150,300$ 2,659,266$ 6,175,483$ 9,214,192$ 9,933$ 19,652$ 1,444,802$ 13,626,971$

Lighting Adjustment -$ 162$ 33$ 4$ 367$ (2,352)$ 18$ 1,768$

Total Revenue Requirement ($) 33,150,300$ 2,659,428$ 6,175,517$ 9,214,196$ 10,300$ 17,300$ 1,444,820$ 13,628,739$

Total Revenue Requirement ($/kWh) 0.1287 0.1351 0.1174 0.1060 0.2861 0.1922 0.1258 0.1569

Total

System

Small

business (G-1)

Medium

business (G-2)

Large business

(T.O.U.)

Street Lights

(SL-1, SL-2,

SL-3)

Outdoor

Lights (SL-2,

OL)

Municipal

Accounts

(MS)

Residential

(D, WH/SH)

Comparison of Revenues ($)

Energy Sales - kWh 269,123,473 20,564,666 54,928,246 90,769,909 37,605 94,012 11,992,834 90,736,200

Revenue Requirement 33,150,300$ 2,659,428$ 6,175,517$ 9,214,196$ 10,300$ 17,300$ 1,444,820$ 13,628,739$

Revenue Generated By Existing Rates 33,150,300$ 3,111,000$ 6,950,300$ 10,145,800$ 10,300$ 17,300$ 1,342,500$ 11,573,100$

Difference -$ (451,572)$ (774,783)$ (931,604)$ -$ -$ 102,320$ 2,055,639$

Revenue Adjustment 0.00% -14.52% -11.15% -9.18% 0.00% 0.00% 7.62% 17.76%

Comparison of Revenues ($/kWh)

Revenue Requirement 0.1287$ 0.1351$ 0.1174$ 0.1060$ 0.2861$ 0.1922$ 0.1258$ 0.1569$

Revenue Generated By Existing Rates 0.1287$ 0.1580$ 0.1322$ 0.1168$ 0.2861$ 0.1922$ 0.1169$ 0.1332$

Difference -$ (0.0229)$ (0.0147)$ (0.0107)$ -$ -$ 0.0089$ 0.0237$

Revenue Adjustment 0.00% -14.52% -11.15% -9.18% 0.00% 0.00% 7.62% 17.76%

5.0 – RATE ANALYSIS

Electric Cost of Service and Rate Design Study Rate Analysis


5.0 RATE ANALYSIS

5.1 Overview

The third and final phase of the Study completed for AL&W was the rate analysis. The cost-of-service

analysis described in Section 4.0 of this report served as one input into the rate analysis and rate

recommendations. Input from AL&W was also taken into consideration in the development of the

recommendations. As discussed in Section 3.0 of this report, the financial forecast indicated that AL&W

is on sound financial footing and the periodic rate adjustment approach employed to date should

sufficiently support the financial health of the utility moving forward. While no overall rate revenue

adjustments are recommended for the utility, a discussion of the rates for each classification is presented

below.

5.1.1 Rate Analysis Objectives

The rate recommendations submitted to AL&W for consideration and adoption were developed in order

to continue to meet the following electric utility rate criteria for service provided by municipally owned

utilities:

• Electric rates should be based on a policy which calls for the lowest possible price consistent with

meeting customer energy requirements, efficient and reliable operations, and sufficient cost

recovery by AL&W to provide service.

• Electric rates should be simple and understandable.

• Electric rates should be equitable among classes of customers and individuals within classes,

taking into consideration the cost-of-service analysis.

• Electric rates should be designed to encourage the most efficient use of power and discourage

unnecessary or wasteful use of electricity.

• Electric rates should comply with the applicable orders and requirements of local and state

regulatory authorities that have jurisdiction.

5.2 Rate Classifications

AL&W customers are charged based on their service application, overall monthly kWh energy

consumption, and/or kW demand characteristics. AL&W serves the following customer classes:



• Large Business – Schedule GL, TOU






• Residential – Schedule D, WH/SH

AL&W also offers a Net Energy Metering tariff. The Net Energy Metering program offers eligible

renewable energy generators compensation for net surplus energy injected into the system. No adjustment

to the net energy metering tariff is proposed at this time.

5.2.1 Existing Rate Schedules

Table 5-1 summarizes the current classes and associated charges.

Table 5-1: Current Rate Classes and Structures

Residential Service customers are billed a monthly basic charge on a $/month basis for electric service.

Residential Service customers are not billed an unbundled monthly demand charge.

Small and Medium Business customers are billed a monthly customer charge on a $/month basis for

electric service. Energy usage is billed on an inclining block basis based on the deviation of current

customer usage from a baseline. Small Business customers are not billed an unbundled monthly demand

charge, while Medium Business customers are. The large Business non-TOU rate is similar to the

Medium Business rate with the exception of the minimum charge and power factor adjustment.



Table 5-2: Existing Residential Service Electric Rates

Table 5-3: Existing Small Business Electric Rates

Table 5-4: Existing Medium Business Electric Rates

Large Business TOU customers are billed a monthly customer charge on a $/month basis for electric

service. Energy usage is billed on a TOU basis with varying rates during peak, mid-peak, and off-peak

time periods, and include power factor adjustment charges. Billing demand is calculated on a TOU basis

with varying rates during peak, mid-peak and off-peak time periods.

Municipal Account customers are billed a monthly basic charge on a $/month basis for electric service.

Energy usage is billed on a flat $/kWh rate, and are not billed an unbundled monthly demand charge.

Residential (D) Summer Rates Winter Rates

Customer Charge ($/month) 3.81$ 3.81$

Energy Charge (kWh)

First 250 kWh 0.1160$ 0.1160$

All excess kWh 0.1487$ 0.1487$

Residential (WH/SH) Summer Rates Winter Rates


Energy Charge (kWh)

First 250 kWh 0.1160$ 0.1160$

Allowance for water heating, per month 250 kWh 0.1160$ 0.1160$



Small Business (G-1) Summer Rates Winter Rates


Energy Charge (kWh)

0 - 500 0.1740$ 0.1740$

500 + 0.1426$ 0.1426$

Medium Business (G-2) Summer Rates Winter Rates

Customer Charge ($/month) -$ -$

Demand Charge

First 20 KW or less -$ -$

Additional KW of demand 8.39$ 8.39$

Energy Charge (kWh)

0 - 500 0.1748$ 0.1748$

500 - 4,500 0.1539$ 0.1539$

4,500 + 0.0950$ 0.0950$

Minimum Monthly Charge (if bill does not exceed) 167.81$ 167.81$



AL&W offers Metered and Non-Metered Street Lighting, and Outdoor Lighting Service to individual

customers and the City where it is economically feasible to serve. Customers are billed monthly for

lighting service on either a $/lamp/mo. plus ¢/kWh energy basis or simply a $/lamp/mo. basis if

unmetered. In some cases, a Customer Service charge is applied to the bill on a $/month basis.

Table 5-5: Existing Large Business TOU Electric Rates

Table 5-6: Existing Municipal Accounts Electric Rates

Large Business (TOU + D) Summer Rates Winter Rates


Demand Charge

All kW of Max Demand, per kW (non-time related) 4.50$ 4.50$

On-Peak 7.51$ -$

Mid-Peak 1.31$ 1.03$

Off-Peak -$ -$

Energy Charge (kWh)

On-Peak 0.1546$ -$

Mid-Peak 0.1044$ 0.1194$

Off-Peak 0.0703$ 0.0703$

Municipal Accounts (MS) Summer Rates Winter Rates


Energy Charge (kWh) 0.1157$ 0.1157$



Table 5-7: Existing Street Lighting and Outdoor Lighting Electric Rates

Street Lights (SL-1) Avg kWh per Month Per Lamp per Month

Incandescent

4,000 Lumen (300W) 104 5.32$

Mercury Vapor 60 15.74$

7,000 Lumen (175W) 86 20.32$

11,000 Lumen (250W) 138 27.84$

20,000 Lumen (400W)

High-Pressure Sodium

9,500 (100W) 35 14.26$

9,500 Lumen (2-100W) 70 32.11$

14,000 Lumen (150W - 14') 52 24.30$

14,000 Lumen (150W - 28') 52 29.00$

22,000 Lumen (220W) 76 19.83$

22,500 Lumen (250W) 86 21.22$

Outdoor Lights (SL-2) Summer Rates Winter Rates


Energy Charge (kWh) 0.1102$ 0.1102$

Avg kWh per Month Per Lamp per Month

Incandescent

4,000 Lumen (300W) 104 5.32$

Mercury Vapor 60 15.74$

7,000 Lumen (175W) 86 20.32$

11,000 Lumen (250W) 138 27.84$

20,000 Lumen (400W)


9,500 (100W) 35 14.26$

22,000 Lumen (220W) 76 19.83$

22,500 Lumen (250W) 86 21.22$

Outdoor Lights (SL-3) Avg kWh per Month Per Lamp per Month


9,500 (100W) 35 14.26$

22,500 Lumen (250W) 86 21.22$

Outdoor Lights (OL) Existing Pole New Pole

Mercury Vapor 16.01$ 19.91$

7,000 Lumen (175W) 29.23$ 33.12$

20,000 Lumen (400W)


9,500 (100W) 14.26$ 18.15$

22,500 Lumen (250W) 20.19$ 24.09$



5.2.2 Proposed Rate Schedules

As previously discussed, the financial forecast indicated that AL&W is on sound financial footing and the

periodic rate adjustment approach employed to date should sufficiently support the financial health of the

utility moving forward. Burns & McDonnell recommends AL&W take no action to raise additional

revenue over and above monies generated by current rates. AL&W is maintaining adequate operating

income and operating fund cash balances, meeting debt service coverage requirements, and generating

sufficient rate base returns. However, Burns & McDonnell does recommend that minimal base rate

adjustments be made, such that the fixed charge portion of residential and commercial rates are increased,

and the variable, or energy, portion of the rate is decreased. These adjustments would keep rates revenue

neutral. An increase in solar customers on the system and the increase in customers participating in net

energy metering (NEM), fixed costs incurred by AL&W will not be sufficiently recovered under the

existing rate structures. Increasing the fixed portion of the rates will help AL&W recover these fixed costs

and maintain adequate levels of income from base rates. On average, customers will not see an increase in

their monthly bills. Street Lighting, Outdoor Lighting and Municipal Account rates are recommended to

remain the same.

Table 5-8: Proposed Residential Service Electric Rates

Table 5-9: Proposed Small Business Electric Rates

Residential (D) Summer Rates Winter Rates


Energy Charge (kWh)

First 250 kWh 0.1091$ 0.1091$


Residential (WH/SH)


Energy Charge (kWh)

First 250 kWh 0.1091$ 0.1091$




Small Business (G-1) Summer Rates Winter Rates


Energy Charge (kWh)

0 - 500 0.1650$ 0.1650$

500 + 0.1430$ 0.1430$



Table 5-10: Proposed Medium Business Electric Rates

Table 5-11: Proposed Large Business TOU Electric Rates

Medium Business (G-2) Summer Rates Winter Rates

Customer Charge ($/month) -$ -$

Demand Charge

First 20 KW or less -$ -$

Additional KW of demand 9.75$ 9.75$

Energy Charge (kWh)

0 - 500 0.1689$ 0.17$

500 - 4,500 0.1498$ 0.15$

4,500 + 0.0950$ 0.10$

Minimum Monthly Charge (if bill does not exceed) 167.81$ 167.81$

Large Business (TOU + D) Summer Rates Winter Rates


Demand Charge

All kW of Max Demand, per kW (non-time related) 4.50$ 4.50$

On-Peak 7.51$ -$

Mid-Peak 1.31$ 1.03$

Off-Peak -$ -$

Energy Charge (kWh)

On-Peak 0.1546$ -$

Mid-Peak 0.1044$ 0.1194$

Off-Peak 0.0703$ 0.0703$

6.0 – SUMMARY & RECOMMENDATIONS

6.0 SUMMARY & RECOMMENDATIONS

6.1 Summary

This report described the approach and assumptions used to complete the Electric Cost of Service and

Rate Design Study. The following is a summary of the results of the Study and Burns & McDonnell’s

recommendations for AL&W.

The first phase of the Study completed for AL&W determined the test year net revenue requirement. In

order to determine the test year net revenue requirement, a five-year financial forecast was developed to

estimate the results from the electric operations of AL&W. Following the development of the financial

forecast, a comparison of annual revenue and revenue requirements was completed to determine whether

sufficient revenue would be available to cover projected operating and capital expenditures or if revenue

adjustments would be required. This phase of the Study showed that AL&W is maintaining adequate

operating income and operating fund cash balances, meeting debt service coverage requirements, and

generating sufficient rate base returns.

The development of the cost-of-service analysis followed the revenue requirements analysis. The cost-of-

service analysis included the assignment, or unbundling, of the various costs included in the test year

2018 revenue requirement to AL&W’s functional services. These unbundled cost components of the

revenue requirement were then allocated to the various electric rate classifications to determine cost

recovery requirements. The results of the cost-of-service analysis indicated some cross subsidization

between the rate classes.

The final phase of the Study was the rate analysis. As previously discussed, the financial forecast

indicated that AL&W is on sound financial footing and the periodic rate adjustment approach employed

to date should sufficiently support the financial health of the utility moving forward. Based on sufficient

financial results and rate design constraints, moderate base rate adjustments are recommended while

mainlining revenue neutrality among existing and proposed rates.

6.2 Recommendations

Burns & McDonnell recommends a number of actions be taken by AL&W based on the analyses

conducted during the Study. The Study recommendations are presented herein.

• Based on the analysis completed and specific discussion regarding rates, Burns & McDonnell

recommends AL&W take no action to raise additional revenue over and above monies generated

by current rates.

• Burns & McDonnell recommends adjustments be made to rate structures by increasing the fixed

charge portion of the rate and lowering the energy charge portion of the rate. These adjustments

are revenue neutral for the system.

• AL&W should consider reassessing the PCA to more closely reflect reductions in power supply

costs. One approach may be to reassess the PCA base rate and adjust it if significantly different

than one currently used.

• AL&W should consider implementing the recommended time of use (TOU) seasonal rate

adjustments to more accurately reflect time-based power supply costs incurred by the system.

• AL&W may consider devising a modified TOU rate, and offer it as an option, whereby energy

component of the rate would be closely linked to the ISO wholesale energy prices in the Los

Angeles Basin.

• Burns & McDonnell recommends consideration of additional rate options once the advanced

metering infrastructure (AMI) program is completed and AL&W has a minimum of one year’s

worth of usage data on the system.

• AL&W should continue to monitor their financial position and revisit a rate analysis in three to

five years; or after the AMI system has been in place for at least one year.

The City should monitor the financial position of AL&W, including adequacy of cost recovery and cash

balances on an on-going basis to help ensure the utility continues to meet its financial requirements.

Burns & McDonnell recommends the reexamination of the utility’s financial plan, costs-of-service, and

electric rates at most every five years. Reexamination of financial position and rates may have to be

contemplated sooner or on more frequent bases when major capital infrastructure projects are

contemplated and/or endeavored.

Burns & McDonnell World Headquarters 9400 Ward Parkway

Kansas City, MO 64114 O 816-333-9400 F 816-333-3690

www.burnsmcd.com

http://www.burnsmcd.com/

Electric Cost of Service and Rate Design Study

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