cos-study

8/3/2019 COS-STUDY

1/83

Electric Utility Cost ofService Study

City of Norway, Michigan

SEH No. NORWY0301.00

Revised February 2004

8/3/2019 COS-STUDY

2/83

February 9, 2004 RE: Electric Utility Cost of Service StudyCity of Norway, MichiganSEH No. NORWY0301.00

Mr. Karl Zueger, Utilities DirectorCity of Norway915 Main StreetPO Box 99Norway, MI 49870-0099

Dear Mr. Zueger:

Enclosed are 12 copies of the Electric Utility Cost of Service/Rate Study. I look forward to our

upcoming discussions regarding this project.

Please call if you have any questions.

Sincerely,

David Krause, PEProject Manager

lsx:\ko\norwy\030100\cost of service study.doc

8/3/2019 COS-STUDY

3/83

Electric Utility Cost of Service Study

Prepared for:City of Norway

Norway Michigan

Prepared by:Short Elliott Hendrickson Inc.

421 Frenette DriveChippewa Falls, WI 54729-3374

715.720.6200

8/3/2019 COS-STUDY

4/83

Distribution List

No. of Copies Sent to

12 Karl Zueger, Utilities DirectorCity of Norway915 Main StreetP.O. Box 99Norway, MI 49870-0099

8/3/2019 COS-STUDY

5/83

Electric Utility Cost of Service Study NORWY0301.00City of Norway, Michigan

Executive Summary

Historical Perspective and Rate Study Purpose

The present rate structure of the City of Norway Electric Utility has been in place for many years,

with no significant rate increases since 1994. Over the years, changes have taken place in the citypopulation, community businesses and wholesale power costs. At the present time, utility staffmembers are considering some significant electric generation and distribution system improvements.The proposed improvements will result in improved system reliability and safety. These factors,along with the desire to take a more modern approach to rate-making, have led Norway toinvestigate its present electric rates. Accordingly, Norway authorized Short Elliott Hendrickson

Inc.

(SEH) to perform a Cost of Service and Rate Study. The purpose of the study is to identify theutilitys cost of providing electric service to its customers and to propose rates reflecting the utilityscost structure.

Spreadsheet Model

SEH developed a series of integrated spreadsheets and graphical charts as a key component of theelectric rate study. The spreadsheet model identifies the cost of service and evaluates the impacts ofproposed rate changes on both utility revenues and customer charges. The spreadsheets and chartsrepresent a financial model of Norways municipal electric utility. The model is very sophisticatedbut has relatively few user inputs. These inputs can be adjusted by utility personnel to accommodatechanges in utility finances and to predict the financial impact of rate adjustments on utility revenuesand customer energy costs. The spreadsheet model is offered for use by the utilitys staff with theunderstanding that Norway will use the software exclusively for the City of Norway and thatelectronic copies of the software will not be released to other parties without first contacting SEH orits successors for release authorization.

Comparative Electric RatesNorways present electric rates are generally comparable to those of neighboring electric utilities.The Rate Study compares Norways rates with the rates of neighboring Escanaba and GladstoneMunicipal Utilities and We Energies. Typically Norway rates are lower than their neighbors.

Cost of Service

Capital improvements, purchased power and labor have historically been Norways most significantcosts. These costs are expected to increase in coming years. If the re-regulation agreement with WeEnergies were to go away, an increase in the demand component of costs from the present 5% to14% of total expenditures could be anticipated. This would equate to a $0.0065 per kWh increase inrates for recovery, or an additional $195,000. Additionally we anticipate an increase in transmission

service costs of 50%-100% in the next five years. At the present rate of $0.80214/kW monthly, thiswould represent an additional $27,000 in costs or $0.0009/kWh in increased rates for recovery.There are other variable costs not included in this rate analysis. Future adjustments to this ratestructure can be anticipated based on changing market conditions. Norways expenses in recentyears appear to be representative of future utility costs. Norways revenues come primarily fromresidential, commercial and industrial customers. During each of the past five years, annual customerrevenues have generally kept up with operating costs, allowing the utility to contribute to the citygeneral fund and other non-utility funds as well as making occasional additions to utility reserves.

8/3/2019 COS-STUDY

6/83

Executive Summary (Continued)


Cost of Service Rates

The cost of service is one of the most important considerations in establishing electric rates. The

American Public Power Association (APPA) offers a widely accepted methodology to establish costof service rates for municipal utilities. We have applied this methodology to the City of Norway,with some minor modifications to accommodate local situations. The cost allocation process hasidentified a slight rate disparity between customer classes. The residential customer class appears tobe contributing less revenue to the utility with respect to their electric kWh consumption while thecommercial and industrial customers are contributing somewhat more.

Rate Design Theory

A section of the report is offered on basic rate design theory to provide a general review of ratedesign and to introduce several trends in electric rate making. The section should encouragediscussion among utility and city personnel to identify the philosophies that might best beincorporated into Norways rates.

Rate Unbundling

Customer choice is a key concept in the regulatory changes occurring within the electric industry.Although recent events on both the east and west coasts have slowed the pace of regulatory changein the Midwest, electric consumers may some day be allowed a choice in their suppliers and in theway they purchase energy. To provide customers with the choices they want, utilities musteventually unbundle their rates. The APPA methodology has been used in this study to identify theunbundled cost of service. There are, as yet, no firmly established procedures in place forunbundling electric rates.

Perhaps the best way to move toward an unbundled rate structure is incrementally, one step at a

time. Although it may be premature for Norway to fully unbundle their rates now, it makes sense toestablish a distribution wheeling rate to anticipate customers that may wish to purchase some of theirenergy services from other providers. Starting with the distribution wheeling rate, the city can set upa billing structure that will accommodate unbundling. By separating functions and costs, Norwaycan avoid losing revenue if customers choose to purchase specific energy services elsewhere.

Distribution Wheeling Rate

Electric distribution will remain the key service offered by the City of Norway. A well-maintained,reliable distribution system presents a nearly insurmountable economic barrier to other organizationswishing to enter Norways present service area. A distribution wheeling rate can be established toprovide sufficient revenue to maintain Norways distribution system regardless of whom the

customers purchase their energy from. Each customer would be assessed the distribution wheelingrate on a per kWh basis for electricity from the utility or wheeled across Norways distributionsystem from an outside supplier.

The distribution wheeling rate can be based on Norways cost of service for providing electricdistribution to its customers. The distribution wheeling rate can be embedded in each of the presentresidential, commercial, small industrial and industrial rates until such time that utility deregulationmakes it worthwhile for the utility to establish a separate line item for distribution wheeling in themonthly customer billing statements.

8/3/2019 COS-STUDY

7/83



Cost of Energy Adjustment Clause

The City of Norway does not presently have an energy cost adjustment clause in the electric rate

structure. The utility may wish to establish an energy cost adjustment clause to accommodate WeEnergies wholesale fuel clause rate adjustment. The We Energies monthly rate adjustments couldthen be passed on to Norways customers without a formal rate hearing. In addition, the councilcould establish a maintenance cost adjustment clause so that unanticipated or extraordinarymaintenance and capital expenditures can be recovered directly through customer revenues.Maintenance efforts associated with storm damage might be an example of costs that could berecovered through the maintenance cost adjustment clause without a permanent rate increase.

Monthly Customer Charge

The City of Norway has a monthly customer charge for residential, commercial, small industrial andindustrial customers to recover some of the utilitys fixed customer service costs. These are coststhat do not vary with kWh energy or kW demand and are incurred by the utility regardless of howmuch energy is consumed by customers. The monthly customer charge helps reduce Norwaysdependence on stable energy sales to recover fixed costs on a per kWh basis. In addition, themonthly customer charge would apply to all customers obtaining energy through the utilitysdistribution system, regardless of whether they buy the energy from Norway or, in the future, fromanother provider. We recommend making modest increases in the monthly customer charge over thenext several years to help recover more of Norways fixed costs.

Proposed Rates

Norway has not increased the electric rates since 1994, nearly ten years ago. The present rates haveprovided sufficient customer revenues to allow the City of Norway to meet its energy costobligations, make improvements to the generation plant and distribution system, add to utility

reserves and provide transfers to the citys general fund and to other non-utility funds. At the presenttime, utility staff members are forced to consider significant electric generation and distributionsystem remedies. A rate increase will help the utility meet its current and future obligations. Inaddition, several adjustments should be made to better balance the burden of electric costs amongNorways electric customers. The proposed rate increase of approximately 1.5 cents/kWh iscomprised of two components: $0.6 cents based on increasing costs in purchased power/energy andinsurance requirements and $0.9 cents based on debt repayment to fund the recommendations madein the Electrical System Review.

Our proposed rates are based on a number of factors as discussed in this study. Norways existingrates represent the most important of these factors, followed perhaps by cost of service, the rates of

neighboring utilities, and allocating utility costs fairly among the customer types. To meet theutilitys anticipated obligations we recommend a residential rate increase of nearly 30%, acommercial rate increase of nearly 19% and an industrial rate increase of about 13%. Theseincreases will not only boost annual revenues, but will also provide a better balance in the cost ofoperating the utility between the residential, commercial and industrial customers. The proposed rateincreases are substantial, particularly for the residential customers. Norway may wish to implementthe rate increases gradually, in several increments over a period of two to three years to allow thecustomers to better budget for the higher electric costs.

8/3/2019 COS-STUDY

8/83



Norway has a rate for small industrial customers. Presently, only four customers are served by thesmall industrial rate. We recommend that the small industrial rate be eliminated and that these fourcustomers be transferred into the industrial rate.

One of the changes we recommend is a gradual increase in the monthly customer charge. Changes tothe monthly customer charge should be made gradually and made with care because they affectsmall customers much more significantly than large users. The customer charge represents a muchgreater portion of the monthly bill for a small customer than it does for a large energy user. A rateincrease may result in more financial hardship for small customers than it does for large users.

Norways monthly rates for all security lighting options are somewhat lower than the estimatedmonthly cost of service. SEH recommends that the present $6.90 monthly security lighting rate beincreased to $8.00 per month this year, $9.00 per month next year and to $10.00 per month thefollowing year.

Revenues Under Existing and Proposed Rates

The existing and proposed rates can be applied to historic energy consumption patterns in Norway toidentify the impact on utility revenues. Applying the existing and proposed rates to the past fiveyears of energy consumption data results in a significant increase in utility customer revenues fromresidential, commercial and industrial customers. The projected revenues from small industrialcustomers are difficult to predict since past kW demand data for these customers is unavailable. Thesmall industrial customer class is nearly insignificant, however, representing only about 1% of totalutility annual customer revenues. Reclassifying these customers under the industrial rate will nothave a material effect on utility revenues.

Customer Impact of Proposed Rates

The proposed rate changes have a very significant impact on the average City of Norway residentialcustomer. The average residential customer electric bills will increase by about 30%. Smallresidential customers will experience an increase of about 33% or $7.25 per month. Large residentialcustomers will face an increase of perhaps 29%. The percent change in energy costs for smallcustomers is somewhat higher than for large customers due to the monthly customer charge.Increases in the monthly service charge have a greater effect on small customers than for largeenergy users. Commercial customers will experience an increase in electric energy costs of about18.5%. An alternate method of assessing the rate increases proposed it to consider the changes on a$/kwh basis. Using 30 million kwh as the base sales figure, the proposed increase of 1.5 cents/kwhcan be represented as 0.9 cents/kwh for system improvements and 0.6 cents/kwh for operating andother expenses. The proposed residential and commercial rates will be somewhat higher than the

rates for Gladstone and Escanaba but still competitive. The proposed rates will still be lower than theresidential and commercial rates charged by We Energies.

The proposed rate changes will have a different impact on each industrial customer. Each industrialcustomer has a unique relationship between monthly peak kW demand and monthly kWh energyuse. As part of the study, we looked at the impact that the proposed rates will have on several ofNorways key customers. Based on the demand and energy consumption during 2002, the proposed

8/3/2019 COS-STUDY

9/83



rates will result in electric energy cost increases of 10.4% and 10.8% for Norways largest industrialcustomers.

RecommendationsDuring recent years the present rates have allowed the utility to meet its obligations and to help fundother city functions. Utility costs are increasing and a rate increase will be required to sustain thelevel of past funding for utility improvements and non-utility city functions. In addition, utilitymanagement is planning some significant capital improvement projects that will help maintainelectric system reliability and safety. It may be difficult to fund these projects from utility reservesand annual cash flow. The improvements could instead be funded by tax exempt revenue bonds. Theproposed rate increase would provide revenues to retire the bonds.

In the study we are proposing a significant rate increase. The increase is based in part on the plannedcapital improvement projects. The proposed rate increase need not be made immediately but can

instead be made in several increments during the next two or three years as plans for the proposedcapital improvements move forward. The proposed rate changes will also help correct the revenueimbalance associated with the present rate structure. Further adjustment to the electric energy ratesmay be required in future years to meet utility obligations and to maintain a good balance among allcustomer groups in sharing the cost of operating the electric utility.

8/3/2019 COS-STUDY

10/83

SEH is a registered trademark of Short Elliott Hendrickson Inc.

Electric Utility Cost of Service Study NORWY0301.00City of Norway, Michigan Page i

Table of Contents

Letter of TransmittalTitle PageDistribution List

Executive SummaryTable of Contents

Page

1.0 Rate Study Historical Perspective ..........................................................................1

2.0 Spreadsheet Model ..................................................................................................1

3.0 Comparative Electric Rates.....................................................................................2

3.1 Comparison of Average Utility Revenue ............................................................23.2 Rate Comparison with Escanaba Municipal and Gladstone Municipal ...............43.3 Residential Rate Comparison ............................................................................43.4 Commercial Rate Comparison...........................................................................43.5 Small Industrial Rate Comparison......................................................................43.6 Industrial Rate Comparison ...............................................................................43.7 Security Lighting ................................................................................................4

4.0 Cost of Service .........................................................................................................5

4.1 Average Costs ...................................................................................................64.2 Marginal Costs...................................................................................................64.3 Evaluating New Customers on the Basis of Average Costs ...............................64.4 Norway Annual Expenses..................................................................................7

5.0 Norway Annual Revenues and Retained Earnings ................................................8

5.1 Electric Utility Customers.................................................................................135.2 Annual Electric Customer Revenues ...............................................................135.3 Annual Energy Sales .......................................................................................135.4 Annual Energy Sales Revenue per kWh..........................................................135.5 Meters, Revenues and kWh Sales...................................................................15

6.0 Cost of Service Rates ............................................................................................17

6.1 Functionalization of Revenue Requirements....................................................176.2 Classification of Revenue Requirements .........................................................186.3 Allocation of Revenue Requirements to Customer Classes .............................246.4 Residential Cost of Service Rates....................................................................286.5 Commercial Cost of Service Rates ..................................................................316.6 Small industrial Cost of Service Rates .............................................................326.7 Industrial Cost of Service Rates.......................................................................326.8 Security Lighting ..............................................................................................35

7.0 Rate Design Theory................................................................................................37

7.1 Electric Rate Design is not Uniform .................................................................377.2 Objectives of Setting Electric Rates .................................................................377.3 Encouraging Energy Conservation ..................................................................38

8/3/2019 COS-STUDY

11/83

Table of Contents (Continued)

Electric Utility Cost of Service Study NORWY0301.00City of Norway, Michigan Page ii

7.4 Time-Of-Day Rates..........................................................................................387.5 Off-Peak Rates ................................................................................................397.6 Peak Curtailment Rate.....................................................................................397.7 Rate Unbundling..............................................................................................39

7.7.1 Customer Choice .................................................................................397.7.2 Cost Accounting for Rate Unbundling...................................................407.7.3 Unbundled Rate Packages...................................................................417.7.4 Procedures for Unbundling...................................................................41

7.8 Distribution Wheeling Rate ..............................................................................427.8.1 Maintaining Revenue Through the Distribution Wheeling Rate.............427.8.2 Cost of Service Distribution Wheeling Rate..........................................42

7.9 Cost of Energy Adjustment Clause ..................................................................43

7.9.1 Energy Cost Variation ..........................................................................437.9.2 Cost of Energy Adjustment Clause.......................................................437.9.3 Maintenance/Capital Cost Adjustment Clause......................................44

7.10 Monthly Customer Charge...............................................................................447.10.1 Recovering Fixed Costs Through the Monthly Customer Charge.........45

8.0 Proposed Rates......................................................................................................45

8.1 Rate Increase ..................................................................................................468.2 Monthly Customer Charge...............................................................................478.3 Small Industrial Customer Class......................................................................478.4 Distribution Wheeling Rate ..............................................................................488.5 Energy Cost Adjustment Clause ......................................................................48

8.6 Maintenance Cost Adjustment Clause .............................................................488.7 Security Lighting ..............................................................................................49

9.0 Revenues Under Existing and Proposed Rates ...................................................49

9.1 Residential Customer Revenues Under Existing and Proposed Rates.............499.2 Commercial Customer Revenues Under Existing and Proposed Rates ...........509.3 Small Industrial Customer Revenues Under Existing and Proposed Rates......509.4 Industrial Customer Revenues Under Existing and Proposed Rates................509.5 Total System Customer Revenues Under Existing and Proposed Rates .........50

10.0 Customer Impact of Proposed Rates....................................................................54

10.1 Residential Customer Cost Comparison Under Existing and Proposed Rates .54

10.2 Commercial Customer Cost Comparison Under Existing and Proposed Rates5410.3 Individual Customer Cost Comparisons Under Existing and Proposed Rates..58

11.0 Recommendations .................................................................................................64

8/3/2019 COS-STUDY

12/83


Electric Utility Cost of Service Study NORWY0301.00City of Norway, Michigan Page iii

List of Tables

Table 1 Average Utility $/kWh Rates by Customer Class .......................................... 2Table 2 Electric Rate Comparison with Neighboring Utilities ..................................... 5Table 3A Annual Electric Utility Operating Expenses by Fiscal Year ........................... 9Table 3B Equipment Replacement Bond Calculations............................................... 11Table 4 Annual Electric Utility Operating Revenues by Fiscal Year ......................... 12

Table 5 Annual Electric Customers (Number of Meters).......................................... 14Table 6 Annual Electric Customer Revenues ( $ )................................................... 14Table 7 Annual Electric Sales (kWh) ....................................................................... 14Table 8 Annual Electric Revenue ($/kWh)............................................................... 14Table 9 General Expenses ( $ ) .............................................................................. 20

Table 10 General Expenses Allocated By Function ( $ ) ........................................... 21

Table 11 Generation Plant Expenses........................................................................ 21Table 12 Generation Plant Expenses Allocated by Function ..................................... 22Table 13 Annual Electric Utility Expenses By Function ( $ ) ...................................... 23Table 14 Customer Metering Allocation Factors........................................................ 25Table 15 Customer Energy (kWh) and Demand (kW) Allocation Factors .................. 27Table 16 Residential Cost of Service Rates .............................................................. 30

Table 17 Commercial Cost of Service Rates............................................................. 33

Table 18 Small Industrial Cost of Service Rates........................................................ 34Table 19 Industrial Cost of Service Rates ................................................................. 36Table 20 Security Lighting Cost of Service................................................................ 37Table 21 Proposed Rates ......................................................................................... 46Table 22 Residential Customer Revenues Under Existing and Proposed Rates ....... 52

Table 23 Commercial Customer Revenues Under Existing and Proposed Rates...... 52Table 24 Small Industrial Customer Revenues Under Existing and Proposed Rates. 52Table 25 Industrial Customer Revenues Under Existing and Proposed Rates .......... 53Table 26 Total System Customer Revenue Under Existing and Proposed Rates...... 53Table 27 Residential Customer Costs Under Existing and Proposed Rates.............. 55Table 28 Commercial Customer Costs Under Existing and Proposed Rates............. 55

Table 29A Industrial Customer Billing - 2002 Industrial Rates ..................................... 61

Table 29B Industrial Customer Billing - 2003 Industrial Rates ..................................... 61Table 30A Industrial Customer Billing - 2002 Industrial Rates ..................................... 62Table 30B Industrial Customer Billing - 2003 Industrial Rates ..................................... 62Table 31A Grocery Customer Billing - 2002 Commercial Rates................................... 62

Table 31B Grocery Customer Billing - 2003 Commercial Rates................................... 63Table 32A Entertainment Customer Billing - 2002 Commercial Rates ......................... 63

Table 32B Grocery Customer Billing - 2003 Commercial Rates................................... 64Table 33A Norway School Customer Billing - 2002 Commercial Rates ....................... 64Table 33B Norway School Customer Billing - 2003 Commercial Rates ....................... 65

8/3/2019 COS-STUDY

13/83


Electric Utility Cost of Service Study NORWY0301.00City of Norway, Michigan Page iv

List of Charts

Chart 1 Average Utility $/kWh Rates by Customer Class .......................................... 3Chart 2 2001 Customer Meters............................................................................... 15Chart 3 Customer Electric Revenues ($)................................................................. 16Chart 4 Customer Electric Sales (kWh)................................................................... 16Chart 5 Proposed Electric Revenues ($) ................................................................. 51

Chart 6 Proposed Electric Sales (kWh)................................................................... 51Chart 7 Proposed Residential Rate Comparison..................................................... 56Chart 8 Proposed Commercial Rate Comparison ................................................... 57

8/3/2019 COS-STUDY

14/83

February 2004

NORWY0301.00Page 1

Electric Utility Cost of Service Study

Prepared for City of Norway

1.0 Rate Study Historical PerspectiveThe present electric rates for the City of Norway have been in placefor nearly ten years, with no adjustments made for inflation. This isquite an accomplishment but impossible to sustain. Over the years,

changes have taken place in the city population, community businessesand wholesale power costs. The citys hydropower resource providesmuch of the communitys power needs but some power must still bepurchased. The cost of this purchased power is going up. In addition,significant improvements will soon need to be made to the hydropowerequipment and to the electrical substations. These factors, along withthe desire to take a more modern approach to rate-making, have ledNorway to investigate the current electric rates. Accordingly, the Cityof Norway authorized Short Elliott Hendrickson Inc. (SEH) to performa Cost of Service and Rate Study. The purpose of the study is toidentify the utilitys cost of providing electric service to its customers

and to propose rate changes that will reflect the utilitys present coststructure.

2.0 Spreadsheet ModelSEH developed a series of integrated spreadsheets and graphical chartsas a key part of the electric rate study for Norway. The spreadsheetsidentify the cost of service for Norway and evaluate the impact ofproposed rate changes on both utility revenues and customer energycosts. These spreadsheets and charts are presented in the followingpages, supported by text that explains the unbundled cost of servicerate study process. The spreadsheets and charts represent a financial

model of Norways municipal electric utility. The model is verysophisticated but has relatively few user inputs. The primary userinputs are highlighted yellow. These inputs can be adjusted toaccommodate changes in utility finances and to predict the financialimpact of rate adjustments on both utility revenues and on customerenergy costs. It is important to look at both the utility revenueperspective and the customer energy cost perspective whencontemplating a rate adjustment.

8/3/2019 COS-STUDY

15/83

Electric Utility Cost of Service Study NORWY0301.00City of Norway, Michigan Page 2

The spreadsheet model is offered for use by the utility staff with theunderstanding that Norway will use the software exclusively for theCity of Norway and that electronic copies of the software will not bereleased to other parties without first contacting SEH for releaseauthorization.

3.0 Comparative Electric Rates3.1 Comparison of Average Utility Revenue

Norways present electric rates are generally comparable to those ofneighboring electric utilities. Table 1 and the associated chart presentthe average residential and commercial utility rates for several nearbyutilities serving customers in Northern Michigan. The data showsNorway as having essentially the lowest average rate per kWh for allcustomer classes shown. The community should be proud of thisaccomplishment. Norways low rates are due largely to thehydropower resource and to the fact that the community has notincreased electric rates for nearly ten years.

Care must be taken when comparing the average rates of severalutilities. The average rate data represents not only the basic $/kWh rateof each utility but also the effect of any monthly service charges.Monthly service charges, for those utilities that assess them, have amore significant impact on small customers than large customers. Thecustomer classifications of individual utilities may also make itdifficult to compare the utilities. Each utility has its own customerclassifications. A commercial customer for one utility might beclassified as a small industrial customer for another. Some utilitieshave multiple commercial rate structures to accommodate large and

small commercial customers. Other utilities may have special rates thatdo not easily fit within the classic residential/commercial/industrialbreakdown. Each utility has its own unique mix of customer types andsizes.

Industrial customers are not included in the table due to the monthlydemand charge. The demand charges of industrial customers can havea profound effect on average revenues per kWh. Customers havinglow load factors will provide much higher average revenues per kWhto the utility than customers with high load factors and relativelyminimal demand charges.

Table 1Average Utility $/kWh Rates by Customer Class

Municipal UtilityResidential

(500 kWh/mo)Residential

(1,500 kWh/mo)Commercial

(1,000 kWh/mo)Commercial

(5,000 kWh/mo)

Norway 0.06100 0.05700 0.07500 0.06700Gladstone 0.07600 0.07200 0.07400 0.07080Escanaba 0.07487 0.06724 0.08090 0.06776

We Energies 0.08640 0.07846 0.08130 0.07586

8/3/2019 COS-STUDY

16/83

0.0

0000

0.0

1000

0.0

2000

0.0

3000

0.0

4000

0.0

5000

0.0

6000

0.0

7000

0.0

8000

0.0

9000

0.1

0000

Norway

Gladstone

Escanaba

WeEnergies

MunicipalUtility

$/kWh

Res

iden

tia

l

(500kWh/mo

)Res

iden

tia

l

(1,5

00kWh/mo

)

Commerc

ial

(1,0

00kWh/mo

)

Commerc

ial

(5,0

00kWh/mo

)


Chart1AverageUtility$/kWhRatesbyCusto

merClass

8/3/2019 COS-STUDY

17/83


3.2 Rate Comparison with Escanaba Municipal and GladstoneMunicipal

The nearby cities of Gladstone and Escanaba operate municipalutilities to provide electric energy to residents and businesses withintheir city limits. These two utilities are generally considered Norways

primary competitors. The rates of Norway, Escanaba Municipal andGladstone Municipal are compared in Table 2 along with We Energiesserving Iron Mountain and the surrounding areas.

3.3 Residential Rate Comparison

Norways present rates are very competitive with those of neighboringEscanaba Municipal and Gladstone Municipal. The City of Norwayhas significantly lower energy rates per kWh than both Escanaba andGladstone. Norways monthly customer charge is nearly the same asthe monthly charges for Gladstone and Escanaba.

3.4 Commercial Rate Comparison

The City of Norway offers generally lower commercial rates than bothEscanaba and Gladstone. Norways monthly customer charge,however, is significantly higher than the charge for both Escanaba andGladstone.

3.5 Small Industrial Rate Comparison

Norway has very few small industrial customers. Norways rates forthese customers are very high compared to those of the neighboringutilities. Note that Gladstone offers two small industrial rates, one ratefor three-phase customers and one rate for single-phase customers.

3.6 Industrial Rate Comparison

The City of Norway offers a three-phase industrial rate comparable toEscanaba Municipal and Gladstone Municipal. Gladstone has aslightly lower $/kW demand charge but a much higher monthlycustomer charge. Escanabas industrial $/kWh energy rate is nearlyequal to the rate that Norway offers, but Escanaba has no monthlycustomer charge. Norways monthly demand charge is significantlyhigher than the demand charge for the neighboring utilities. Thedemand charges for Escanaba and Gladstone appear to be much lowerthan their cost of service and should be examined more closely byutility personnel.

3.7 Security LightingNorways monthly charge for security lighting is significantly lowerthan the charge for Escanaba and Gladstone. It appears that thesecurity lighting rate for Norway could be increased if it is not meetingthe cost of service.

8/3/2019 COS-STUDY

18/83


Table 2Electric Rate Comparison with Neighboring Utilities

PresentNorway(City)

EscanabaGladston

e

Residential

Monthly Customer Charge ($) 3.00 2.39 3.00Energy Charge ($/kWh) 1st 400 kWh 0.05500 0.07175 0.07000Energy Charge ($/kWh) Over 400 kWh 0.05500 0.06343 0.07000Commercial (Single Phase)

Monthly Customer Charge ($) 10.00 2.39 4.00Energy Charge ($/kWh) 1st 500 kWh 0.06500 0.08942 0.07000Energy Charge ($/kWh) 500 to 2,000 kWh 0.06500 0.06759 0.07000Energy Charge ($/kWh) Over 2,000 kWh 0.06500 0.06343 0.07000

Small IndustrialMonthly Customer Charge ($) 20.00 0.00 10.00Energy Charge ($/kWh) 1st 1,000 kWh 0.09500 0.05200 0.05500Energy Charge ($/kWh) 1,000 to 20,000 kWh 0.06500 0.05200 0.05500

IndustrialMonthly Customer Charge ($) 20.00 0.00 40.00Energy Charge ($/kWh) 1st 50,000 kWh 0.05000 0.05200 0.04300

Energy Charge ($/kWh)50,000 to 200,000

kWh 0.05000 0.04900 0.04300Energy Charge ($/kWh) Over 200,000 kWh 0.05000 0.04600 0.04300Monthly Demand ($/KW) All kW 6.00 3.27 4.00

Security LightingMonthly Customer Charge ($) 6.90 9.63 10.04

Notes: Gladstone small Industrial Rates: Single Phase - $6.00 Monthly Customer Charge, $0.057/kWh

4.0 Cost of Service

Prices in a regulated industry are generally based on costs. In aregulated industry, suppliers are typically allowed a specific profitmargin, based on their cost of doing business. This is particularly trueof investor owned utilities where the profit margin is distributed tocompany shareholders in the form of stock dividends. Identifying thecost of serving electric customers is critical to the regulatory process.

Municipal utilities are generally not as closely regulated as investorowned utilities. The primary regulatory effort is at the local level,through a municipal utility board, commission or city council. As non-profit enterprises, municipal utilities strive to offer their customers thelowest possible electricity prices while maintaining excellent service.In a sense, municipal utilities offer a form of competition to investorowned utilities by establishing benchmark levels of pricing andservice. Identifying the cost of serving customers is critical tomunicipal utilities just as it is to investor owned utilities. The cost ofservice must be identified to ensure that the electric rates are setsufficiently high to cover current and projected costs and to assure thatrates are set equitably for all customer classes.

8/3/2019 COS-STUDY

19/83


4.1 Average Costs

Historically, electric rates have been based on average costs. Todetermine average costs, a utility must know the quantity of electricitythey will sell and the customers they will serve. Average costs canthen be calculated by dividing the cost of service by the quantity of

electricity or the number of customers. This is generallystraightforward for a utility whose service area and customer base isstatic or changes relatively slowly and predictably.

4.2 Marginal Costs

Portions of the electric industry are moving toward increasedcompetition. In a competitive industry, pricing is generally based onthe established competition instead of average costs. New supplierswanting to enter a specific market must offer improved service orlower pricing than the established supplier offers. The marginal cost ofdoing business in the new market becomes the decision-makingcriteria, as opposed to the average cost of doing business in an existing

service area. As competition increases, utilities must first evaluatewhat customers will pay and then choose the quantity of electricity toproduce and the markets they will serve, instead of basing theiractivities on an average cost of doing business. The marginal cost ofserving new customers or the increased load of an existing customer isseldom equal to the average cost of serving the present customers.

The marginal cost of serving a new customer or the increased load ofan existing customer can be more difficult to determine than theaverage cost of service. The marginal cost will depend on the newcustomer size, location, load factor and load profile. Sunk costs, as

well as overhead or common costs are seldom included in marginalcosts. Sunk costs and overhead are not affected by an incrementalincrease or decrease in electric output. The new customer may requirea capital investment or increased operation and maintenance costs forthe utility.

4.3 Evaluating New Customers on the Basis of Average Costs

The balance of this section on cost of service is based on the averagecosts associated with serving Norways existing customers.Competition will most likely be introduced slowly to the market thatNorway presently serves. Competition may never be realized in thedistribution portion of the utilitys business. The average cost ofservice still provides a valuable basis for establishing electric rates.Caution should be used in applying the average cost of serviceinformation presented in this study to the potential cost of servingmajor new customers or a large increase in the load of an existingcustomer.

8/3/2019 COS-STUDY

20/83


4.4 Norway Annual Expenses

Table 3A presents Norways annual operating expenses during the pastfive years. The data in the table is taken primarily from City ofNorway Electric Fund annual financial reports. In the City of NorwayElectric Fund annual financial reports, one entry is provided for energy

purchases. Using the wholesale power invoices for 2000 and 2001,SEH separated the energy portion from the demand portion of thewholesale bills. It is important to separate energy costs from demandcosts when preparing a cost of service electric rate study. The tablealso includes a column for the 2003-2004 budgeted utility expensesand a column titled study year. The study year column represents anexpectation of annual utility expenses during the next several years.

Total utility operating expenses have varied significantly during thepast five years. While some of the variation is due to purchased power,capital improvements and transfers to other city funds have resulted inwide changes to the annual operating expenses from year to year. The

situation continues into the 2003-2004 budget year. The utility isplanning some significant capital improvements to maintain reliabilityin the hydro generation and electric distribution systems. In addition,the utility anticipates significant purchased power costs during aperiod when one of the hydropower generators is out of service.

The wide variation in utility expenses during the past several yearsmakes it difficult to select any of these years to represent theanticipated expenses in future years. For this reason we haveestablished the study year column to provide a representation of utilityexpenses going forward. In the study year column, we have allocated

no costs for new vehicles in account items 970 and no costs to accountitems 971 and 972, capital improvements for distribution and hydro.Utility staff plans to accomplish several utility vehicle purchases in thecoming years and has established a forecast for these purchases. Thisforecast is included in the appendix and reflected in item 998,equipment replacement for the study year in Table 3A. Likewise,utility management is contemplating some significant capitalimprovements during the next several years to maintain the electricdistribution and generation system reliability. The improvements canbe financed by issuing municipal revenue bonds during this period oflow interest rates. Assuming a conservative interest rate of 5.5% and a

20-year bonding period results in an annual payment of $243,674 toretire the bonds as shown in Table 3B. This figure is also shown forthe study year in Table 3A under account item 999, capital projects.

In Table 3B we have included a line item for diesel-electric generation.Diesel generation could allow the electric utility to operateindependently of the national electric grid in the event of an outage atthe grid interconnection. At present, Norways hydro generation mustdepend on the grid interconnection for stability control. In the event of

8/3/2019 COS-STUDY

21/83


a power outage, Norway is exposed to very high wholesale demandcharges since the hydro generators must be taken off-line during theoutage and cannot be re-started immediately when wholesale powerbecomes available again at the interconnection. While it may bedesirable to install diesel generation now, it appears that the otherelectric system improvements listed in Table 3B should take priority.At some future time an entry for diesel generation could be made toTable 3B of the electric rate model to begin to identify the impact ofdiesel generation on the cost of service rates for Norway. The dieselgenerating units may also allow Norway to purchase wholesale energyfrom We Energies at an interruptible rate instead of buying firmpower. As such, this detailed analysis is not included here because itfalls beyond the scope of the unbundled cost of service study.

5.0 Norway Annual Revenues and Retained EarningsTable 4 presents Norways annual operating revenues during the pastfive years. The data in the table is taken primarily from City of

Norway Electric Fund annual financial reports. Similar to Table 3A forutility expenses, Table 4 includes a column for the 2003-2004budgeted utility revenues and a column titled study year. The studyyear column represents an expectation of annual utility revenuesduring the next several years. The 2003-2004 budget year includesseveral extraordinary items such as an anticipated property sale underaccount 673 and some miscellaneous revenues under item 633. Theseone-time items are not reflected in the data chosen for the study year torepresent the anticipated utility revenues going forward.

The total operating expenses from Table 3A are shown again at the

base of Table 4. The operating expenses for each year can besubtracted from the utility revenues to identify the retained earnings.These retained earnings would normally be directed into the utilityreserves. During several recent years, utility expenses exceeded therevenues, requiring Norway to dip into the reserves. For the studyyear, we used the spreadsheet model to calculate the annual electricsales and demand charges (account items 641 and 648) based on theelectric rates proposed later in this report. The proposed rates result inretained earnings of about $177,000, representing approximately 7.3%of the annual utility operating income.

8/3/2019 COS-STUDY

22/83

8/3/2019 COS-STUDY

23/83


Table3A(Continued)

AnnualElectricU

tilityOperatingExpensesbyFiscalYear

Year

1997

1998

1999

2000

2001

03-04Bu

dg.

StudyYr.

Acct.#

OPERATINGEXPENSES

$

$

$

$

$

$

$

914

Insurance-Liab./Prop./

Worker'sComp.

45,48

7.0

0

65,2

40.0

0

58,3

91.0

0

32,5

36.0

0

38,1

03.0

0

50,33

0.0

0

50,3

30.0

0

920

Telephone

0.0

0

2,7

97.0

0

3,6

12.0

0

3,9

93.0

0

4,5

46.0

0

4,20

0.0

0

4,2

00.0

0

922

HeatingFuel(Mic

hcon)

0.0

0

2,4

81.0

0

1,7

38.0

0

2,4

92.0

0

406.0

0

2,50

0.0

0

2,5

00.0

0

925

DisposalExpense

0.0

0

7,4

25.0

0

0.0

0

4,6

36.0

0

9,9

64.0

0

3,00

0.0

0

3,0

00.0

0

942

Rental/Lease

0.0

0

9,4

12.0

0

9,4

06.0

0

9,4

00.0

0

9,7

00.0

0

11,25

0.0

0

11,2

50.0

0

955

PropertyTaxes

2,42

3.0

0

2,6

42.0

0

2,8

56.0

0

3,0

96.0

0

3,2

69.0

0

3,50

0.0

0

3,5

00.0

0

956

Misc.

Expense

7,64

9.0

0

2,1

51.0

0

0.0

0

0.0

0

0.0

0

0.0

0

0.0

0

974

BondPayment-P

rincipal

0.0

0

110,0

00.0

0

110,0

00.0

0

115,0

00.0

0

125,0

00.0

0

165,00

0.0

0

165,0

00.0

0

993

BondIssueCosts

(Discounts)

21,18

4.0

0

1,1

84.0

0

21,1

84.0

0

21,1

84.0

0

21,2

45.0

0

21,24

5.0

0

21,2

45.0

0

995

Interestexpense

109,00

4.0

0

103,9

05.0

0

99,3

58.0

0

94,4

99.0

0

92,8

22.0

0

137,98

2.0

0

137,9

82.0

0

--

PropertyAcquisition

0.0

0

0.0

0

0.0

0

0.0

0

0.0

0

0.0

0

0.0

0

970

NewVehicles$E

quip.

0.0

0

0.0

0

0.0

0

0.0

0

39,2

98.0

0

60,00

0.0

0

0.0

0

971

CapitalImprovem

ents-System

30,52

1.0

0

96,7

28.0

0

66,9

82.0

0

105,3

52.0

0

79,5

48.0

0

51,00

0.0

0

0.0

0

972

CapitalImprovem

ents-HydroPlant

0.0

0

262,9

29.0

0

274,3

77.0

0

357,1

03.0

0

261,9

76.0

0

634,50

0.0

0

0.0

0

972-021

DamStabilization

Project

0.0

0

0.0

0

0.0

0

0.0

0

14,5

52.0

0

0.0

0

0.0

0

972-022

HydroStabilizatio

nProject

0.0

0

0.0

0

0.0

0

0.0

0

65,1

50.0

0

0.0

0

0.0

0

982

ToGeneralFund

-OneTime

0.0

0

0.0

0

150,0

00.0

0

0.0

0

0.0

0

0.0

0

0.0

0

982

ToGeneralFund

29,43

6.0

0

124,0

45.0

0

125,2

02.0

0

129,3

65.0

0

859,1

12.0

0

190,21

6.0

0

180,0

00.0

0

997

ToCableTVFund-OneTime

0.0

0

55,0

00.0

0

0.0

0

250,0

00.0

0

0.0

0

0.0

0

0.0

0

998

ToEquipmentRe

placementFund

0.0

0

0.0

0

110,4

57.0

0

0.0

0

0.0

0

0.0

0

54,0

00.0

0

999

ToCapitalProjectsFund

100,00

0.0

0

0.0

0

35,0

00.0

0

35,0

00.0

0

35,0

00.0

0

35,00

0.0

0

274,7

81.2

0

Total

1,315,023

1,873,884

2,028,676

2,310,004

2,758,002

2,776,029

2,244,094

8/3/2019 COS-STUDY

24/83


Table3B

Equipme

ntReplacementBondCalculations

Item

Cost($)

#4Generato

rRep

lacemen

t

495

,000

.00

New

Ma

inSu

bs

tation

1,2

00

,000

.00

New

Hy

dro

Su

bs

tation

200

,000

.00

Distribu

tion

Improvemen

ts

1,9

45

,000

.00

4MW

Diese

lGenera

tion

0.0

0

Subtotal3

,840

,000

.00

4%Bond

OriginationFee

153

,600

.00

Total3

,993

,600

.00

AnnualPayment30yr

(274

,781

.20)

AnnualPayment20yr

(334

,181

.77)

AnnualPayment15yr

(397

,864

.79)

Note:TotalA

nnualPaymentbasedon30year,1

5year

or20yearm

[email protected]

%interest.

Note:4MWDieselGenerationApproximateIns

talled

Cost=$1,40

0,0

00

8/3/2019 COS-STUDY

25/83


Table4

AnnualElectricU

tilityOperatingRevenuesby

FiscalYear

Year

1997

1998

1999

2000

2001

03-04Bu

dg.

StudyYr.

Acct.#

OperatingIncome

$

$

$

$

$

$

$

402

RetireesInsura

nceReimbursement

0.0

0

15,7

88.0

0

21,8

13.0

0

19,7

57.0

0

20,0

23.0

0

28,28

5.0

0

28,2

85.0

0

569

BondProceeds

0.00

0.0

0

0.0

0

0.0

0

986,7

66.0

0

0.0

0

0.0

0

633

Misc.

Revenue

s

11,4

70.0

0

1,4

80.0

0

7,6

47.0

0

1,8

58.0

0

870.0

0

130,00

0.0

0

5,0

00.0

0

636

LineInstallationCosts

12,8

97.0

0

8,4

72.0

0

21,5

93.0

0

17,9

28.0

0

13,6

12.0

0

10,00

0.0

0

10,0

00.0

0

641

ElectricSales

1,4

51,7

22.00

1,5

89,5

30.0

0

1,6

74,6

01.0

0

1,6

18,6

52.0

0

1,6

53,8

41.0

0

2,1

60,00

0.0

0

2,1

99,8

70.4

2

646

TimberSales

20,9

75.0

0

0.0

0

0.0

0

0.0

0

0.0

0

0.0

0

0.0

0

647

SurplusPower

Sales

70,1

33.00

44,3

42.0

0

41,4

56.0

0

24,2

54.0

0

38,9

45.0

0

35,00

0.0

0

35,0

00.0

0

648

DemandCharg

es

59,9

01.0

0

78,1

15.0

0

94,5

96.0

0

81,9

47.0

0

77,0

97.0

0

96,00

0.0

0

91,0

00.0

0

655

Penalties

13,5

75.0

0

17,3

48.0

0

15,1

78.0

0

16,2

68.0

0

16,2

56.0

0

17,00

0.0

0

17,0

00.0

0

665

InterestonInvestments

87,3

03.0

0

74,1

50.0

0

72,3

79.0

0

72,1

91.0

0

45,8

68.0

0

25,00

0.0

0

25,0

00.0

0

673

SaleofProperty

0.00

0.0

0

0.0

0

0.0

0

0.0

0

200,00

0.0

0

0.0

0

674

DeveloperCon

tributions

0.0

0

1,0

61.0

0

2,5

99.0

0

8,1

03.0

0

0.0

0

10,00

0.0

0

10,0

00.0

0

679

PlanReview/C

onsulting

Reimbursemen

t

0.0

0

0.0

0

0.0

0

0.0

0

0.0

0

0.0

0

0.0

0

680

TransfersInFr

omOtherFunds

0.0

0

4,0

97.0

0

0.0

0

113,2

29.0

0

0.0

0

0.0

0

0.0

0

685

FromFundEquity-OneTime

0.0

0

0.0

0

0.0

0

0.0

0

0.0

0

0.0

0

0.0

0

Total

1,727,976

1,834,383

1,951,862

1,974,187

2,853,278

2,711,285

2,421,155

OPERAT

INGEXPENSES

(1,3

15,02

3)

(1,8

73,8

84)

(2,0

28,6

76)

(2,3

10,0

04)

(2,7

58,0

02)

(2,7

76,029)

(2,2

44,0

94)

RETAIN

EDEARNINGS

412,95

3

(39,5

01)

(76,8

14)

(335,8

17)

95,2

76

(64,744)

177,0

61

8/3/2019 COS-STUDY

26/83


5.1 Electric Utility Customers

Table 5 presents the quantity of utility customers, based on the numberof electric meters in each service class during recent years. Ninety-onepercent of Norways customers are residential. About 8% arecommercial customers, 0.2% are small industrial, 0.2% are industrial

and 0.3% are street lighting. Norways customer base is very stable,exhibiting only minimal variation within the past five years. In Table5, as well as Tables 6 through 8 we have included some projected datafor the 2003-2004 budget year as well as for a study year.

5.2 Annual Electric Customer Revenues

Table 6 presents the annual energy revenues by customer class inrecent years for the City of Norway. Residential customers representthe largest source of revenue for Norway, about 51% of the totalcustomer revenues. Commercial customers provide about 38% ofNorways customer revenues, followed by industrial customers atapproximately 9%. Small industrial and street lighting each represent

about 1% of Norways annual customer revenues.

The energy revenues presented in the table include the monthly servicecharge for each customer class. There is some variation in revenuesfrom year to year, due perhaps to weather conditions. Note that thestudy year shows a significant increase in the percentage of revenuesfrom residential customers. This situation will be discussed insubsequent sections of the report.

5.3 Annual Energy Sales

Table 7 presents the annual energy sales in kWh for each customerclass. Residential customers represent the largest customer class,consuming approximately 56% of Norways energy output.Commercial customers consume about 36% of the utilitys output.Industrial customers represent about 7% of the total kWh distributed in2001. Small industrial and street lighting each consume about 1% ofthe total energy output.

5.4 Annual Energy Sales Revenue per kWh

The data in Table 6 can be divided by the data in Table 7 to obtainenergy sales revenue information on an average $/kWh basis aspresented in Table 8. For 2001 the industrial revenues on an average$/kWh basis are the highest, followed by the small industrial,

commercial, and street lighting revenues. Residential customers havethe lowest $/kWh.

8/3/2019 COS-STUDY

27/83

8/3/2019 COS-STUDY

28/83


5.5 Meters, Revenues and kWh Sales

The data from Tables 5, 6 and 7 can be presented in the form of piecharts to provide a better understanding of the relationship between thenumber of meters, revenues and kWh sales for each customer class.Chart 2 shows the percentage of total meters in each customer class for

2001. About 90.9% of Norways customers are residential, followedby about 8.4% commercial, 0.3% street lighting, 0.2% small industrialand 0.2% for industrial. Although 90.9% of Norways standard metersare installed on residential properties, these customers represent about51% of the customer revenues as shown in Chart 3 and 55.8% of totalkWh sales shown in Chart 4. The residential customers are using55.8% of the electric energy but are providing only 51% of the utilityrevenues. This represents a significant imbalance in the electric ratestructure. The residential customers appear to be paying a quite a bitless than they should for the energy they consume. The City ofNorway has just the opposite situation for commercial customers.

Commercial customers consume only 35.6% of the energy but provide37.9% of the revenues. The industrial customers also appear to bepaying more than their share for the electric energy they consume. Thecomparison between Charts 3 and 4 suggests that a rate increase forresidential customers might be appropriate.

Chart 2 2001 Customer Meters

Chart 2. 2001 Customer Meters

Residential

90.9%

Industrial

0.2%

Small Industrial

0.2%

Commercial

8.4%

Street Lighting

0.3%

8/3/2019 COS-STUDY

29/83


Chart 3 Customer Electric Revenues ($)

Chart 4 Customer Electric Sales (kWh)

Chart 3. 2001 Electric Revenues ( $ )

Residential

51.0%Commercial

37.9%

Street Lighting

1.0%

Small Industrial

1.1%

Industrial

9.0%

Chart 4. 2001 Electric Sales ( kWh )

Industrial

6.6%Small Industrial

0.9%

Commercial

35.6% Residential

55.8%

Street Lighting

1.1%

8/3/2019 COS-STUDY

30/83


6.0 Cost of Service RatesElectric rates are generally based on many factors. The cost of serviceis one of the most important considerations in establishing rates. Thissection will focus on cost of service as a rate-making tool. Subsequentsections will discuss other factors that enter into rate development.

The American Public Power Association (APPA) offers amethodology to establish cost of service rates for municipal utilities.We have applied this methodology to the City of Norway, with someminor modifications to accommodate local situations specific toNorway. APPA also offers a methodology for unbundling retailelectric rates. Although complete unbundling may not be appropriateunder the present electric regulatory climate, we have incorporatedmany of the APPA unbundling concepts. These will be discussed indetail in subsequent pages of this report.

There are three major steps in the APPA cost of service methodology.

These steps are as follows:

1. Functionalize the utility revenue requirements according to costtype

2. Classify the utility revenue requirements according to the servicesprovided

3. Allocate the utility revenue requirements among customer classes

Each of the APPA steps are described below.

6.1 Functionalization of Revenue Requirements

Cost of service rates are based on the revenue requirements of theutility. An electric utility has a set of costs that must be met in order tostay in business each year. The utility must have enough revenue eachyear to meet these costs. Utility costs vary from year to year but aregenerally quite predictable. A look at the costs and revenues of pastyears probably offers the best indication of utility requirements infuture years.

For cost of service purposes, utility costs are typically broken down, orfunctionalized into the following cost functions:

1. Production or Purchased Power

2. Transmission3. Distribution4. Customer Service5. Administration6. Revenue

8/3/2019 COS-STUDY

31/83


The first four items should be relatively self-explanatory.Administration refers largely to general office functions and overhead.The revenue function refers to other operating and non-operatingrevenue sources generally not part of the utilitys primary purpose ofproviding reliable electric service to its customers. The revenuecomponents can be positive or negative. For example, revenues fromthe sale of surplus materials and equipment would represent a positiverevenue component. The transfer of utility revenues to the city generalfund would be a negative revenue component.

The annual utility and city financial reports provide a good start tofunctionalizing the utilitys operating expenses. The financial data waspresented earlier in Table 3A. In future pages we will makeadjustments to the financial data to further functionalize theseexpenses but first we should review the other two major steps in theAPPA cost of service methodology.

6.2 Classification of Revenue RequirementsAfter the utility revenue requirements have been separated by function,they can be classified according to cost component. The typical utilitycost components are as follows:

1. Energy2. Demand3. Customer4. Revenue5. Direct

Energy costs are associated with the supply of energy to meet the

electric requirements of the utility customers. These costs vary withkWh energy consumption. Demand costs are associated with the peakdemand of each customer and overall peak demand of the utility. Thepeak occurs when utility customers are using the highest amounts ofenergy. Peak electric demand periods typically take place during hotsummer weather when customers are making heavy use of airconditioning or during exceptionally cold winter weather when electricheat is operating.

Customer costs are associated with billing functions and serving theutilitys customers. Customer costs typically vary with the number ofcustomers that a utility serves. Revenue costs were describedpreviously and are associated with the sale of surplus equipment,financial transfers to the city general fund or other sources of incomeand disbursements not generally associated with the utilitys corefunction of providing electric service. Direct costs are costs clearlyrelated to a specific customer or class of customers. Special services toa key industrial customer or to a specific group of rural customers areexamples of direct costs. Street lighting might also be considered adirect cost.

8/3/2019 COS-STUDY

32/83


The functionalization and classification processes are typicallystraightforward with the possible exception of general andadministrative costs. The utility financial data presented previously inTable 3A has many entries devoted to general expenses. Theseexpenses should be broken down into the classifications describedabove. Tables 9 and 10 demonstrate the classification of generalexpenses. Table 9 repeats the portions of Table 3 that are classified asgeneral expenses. In Table 10, allocation factors are applied to thetotal yearly general expenses from Table 9. The allocation factors aresomewhat arbitrary. In Table 10, we have assumed that 30% of theutility general expenses can be allocated to each of the functionsrepresented by power generation (demand), distribution system andcustomer service. Energy is allocated 5%, revenue 4% and streetlighting 1%.

Tables 11 and 12 demonstrate the classification of generation plantexpenses following the format used earlier for Tables 9 and 10.

Table 11 repeats the portions of Table 3 that are classified asgeneration plant expenses. In Table 12, allocation factors are appliedto the total yearly generation plant expenses from Table 11. Again, theallocation factors are somewhat arbitrary. In Table 12, we haveassumed that 40% of the utility generation plant expenses can beallocated to power (demand) while 60% can be allocated to energy.

The rest of the cost classification process is accomplished in Table 13.For Norway, we used six utility functions as follows:

1. Customer Service2. Street Lighting

3. Power (kW Demand)4. Energy (kWh Energy)5. Distribution System (Poles, Wires, Underground, Substations)6. Revenue (non-utility related functions)

Table 13 is a reorganization of the city financial statements for theelectric utility as presented earlier in Table 3A, with adjustments madein Tables 9 though 11. Note that each of the functions presented inTable 13 has a general expense item. The general expense items foreach function were developed previously in Tables 9 and 10. Recallthat we used Tables 9 and 10 to allocate the large general expense

category to the various utility functions.

8/3/2019 COS-STUDY

33/83


Table9

GeneralExpenses($)

Year

1997

1998

1999

2000

2001

03-04B

udg.

StudyYr.

Acct.#

G

eneralExpenses

$

$

$

$

$

$

$

702

Sa

laries-

Full

Time

433

,560

357

,642

343

,677

331

,936

312

,377

422

,665

422

,665

703

Sa

laries-

Par

tTime

0

0

0

3,8

64

22

,196

8

,438

8,4

38

704

Sa

laries-

Ove

rtime

0

49

,520

52

,297

59

,219

69

,650

63

,430

63

,430

705

Emp

loyee

Separa

tion

0

6,6

15

0

14

,500

0

0

0

706

SickTime

Buy

bac

k

0

0

0

0

0

0

0

707

Longev

itypay

5,6

75

4,8

75

4,9

25

4,7

25

4,3

50

4

,800

4,8

00

708

COLAAdjustm

en

t

0

0

0

0

1,2

05

0

0

709

ShiftDifferent

ial-

Hy

dro

0

0

0

0

0

0

0

712

VEBACon

tribu

tion

0

0

0

0

5,4

50

5

,430

5,4

30

715

Emp

loyer-

FICA

32

,693

32

,122

30

,489

33

,155

31

,875

38

,250

38

,250

716

Group

Insuran

ce

72

,875

82

,123

103

,086

108

,512

123

,048

195

,983

195

,983

717

Se

lfInsure

dR

eten

tion

0

0

0

0

3,2

04

9

,000

9,0

00

718

Emp

loyer-

MERS

3,8

41

25

,229

36

,306

52

,036

44

,633

68

,250

68

,250

719

Unemp

loymen

tCompensa

tion

9,9

81

8,7

49

3,9

76

3,0

45

1,4

29

4

,460

4,4

60

720

Tra

ining

/Mem

bers

hip/Trave

l/Educa

tion

0

3,5

70

3,5

61

4,2

37

5,0

07

13

,500

13

,500

740

Supp

lies

(Ope

rating

&Office

)

28

,155

10

,775

12

,970

9,2

59

4,8

55

7

,000

7,0

00

745

Prin

ting

/Posta

ge

/Stationary

/Pu

blica

tions

0

5,8

52

6,2

45

6,8

19

9,6

24

7

,000

7,0

00

750

Un

iform

/Clean

ing

Expense

1,0

36

3,0

61

2,4

99

2,6

75

3,5

24

3

,600

3,6

00

751

Gas

&Oil

3,7

12

3,8

11

4,0

85

4,2

52

4,0

21

5

,500

5,5

00

753

Banners

&De

cora

tions

0

8,6

20

1,3

31

1,4

86

309

0

0

819

Pro

fess

ionalS

erv

ices

18

,958

13

,599

5,2

08

86

,260

50

,190

31

,500

31

,500

861

Ma

intenance-

Equ

ip/Bu

ildings

15

,346

25

,529

19

,590

36

,313

30

,177

20

,000

20

,000

903

Compu

ter

Exp

ense

4,1

09

3,4

88

5,1

30

1,4

93

385

1

,000

1,0

00

914

Insurance-Lia

b./

Prop./

Worker's

Comp.

45

,487

65

,240

58

,391

32

,536

38

,103

50

,330

50

,330

920

Te

lep

hone

0

2,7

97

3,6

12

3,9

93

4,5

46

4

,200

4,2

00

922

Hea

ting

Fuel

(Michcon

)

0

2,4

81

1,7

38

2,4

92

406

2

,500

2,5

00

925

Disposa

lExpe

nse

0

7,4

25

0

4,6

36

9,9

64

3

,000

3,0

00

942

Ren

tal/Lease

0

9,4

12

9,4

06

9,4

00

9,7

00

11

,250

11

,250

955

Property

Taxe

s

2,4

23

2,6

42

2,8

56

3,0

96

3,2

69

3

,500

3,5

00

956

Misc.

Expense

7,6

49

2,1

51

0

0

0

0

0

Total

685,500

737,328

711,378

819,939

793,497

984

,586

984,586

8/3/2019 COS-STUDY

34/83


Table10

GeneralEx

pensesAllocatedByFunction($)

Year

1997

1998

1999

2000

2001

03-04Budg.

StudyYr.

UtilityFunction

AllocationFactor

$

$

$

$

$

$

$

Power

30%

205

,650

221

,198

213

,413

245

,982

238

,049

295,3

76

295

,376

Energy

5%

34

,275

36

,866

35

,569

40

,997

39

,675

49,2

29

49

,229

Distribu

tion

Sys

tem

30%

205

,650

221

,198

213

,413

245

,982

238

,049

295,3

76

295

,376

Cus

tomer

Serv

ice

30%

205

,650

221

,198

213

,413

245

,982

238

,049

295,3

76

295

,376

Stree

tLighting

1%

6,8

55

7,3

73

7,1

14

8,1

99

7,9

35

9,8

46

9,8

46

Revenue

4%

27

,420

29

,493

28

,455

32

,798

31

,740

39,3

83

39

,383

Total

100%

685,500

737,328

711,378

819,939

793,497

984,5

86

984,586

Table11

G

enerationPlantExpenses

Year

199

7

1998

1999

2000

2001

03-04B

udg.

StudyYr.

Acct.#

GenerationPlantExpenses

$

$

$

$

$

$

$

974

Bon

dPaymen

t-

Princ

ipa

l

0

110

,000

110

,000

115

,000

125

,000

165

,000

165

,000

993

Bon

dIssue

Cos

ts(Discoun

ts)

21

,184

1,1

84

21

,184

21

,184

21

,245

21,2

45

21

,245

995

Interes

texpense

109

,004

103

,905

99

,358

94

,499

92

,822

137

,982

137

,982

972

Cap

ita

lImpr

ovemen

ts-

Hy

dro

Plan

t

0

262

,929

274

,377

357

,103

261

,976

634

,500

0

972-0

21

Dam

Stabiliz

ation

Pro

jec

t

0

0

0

0

14

,552

0

0

972-0

22

Hy

dro

Stabiliza

tion

Pro

jec

t

0

0

0

0

65

,150

0

0

647

Surp

lus

Pow

er

Sa

les

(70,1

33)

(44

,342)

(41

,456)

(24

,254)

(38

,945)

(35,000)

(35

,000)

998

To

Equ

ipme

ntRep

lacemen

tFun

d

0

0

110

,457

0

0

0

54

,000

999

To

Cap

italP

rojec

tsFun

d

100

,000

0

35

,000

35

,000

35

,000

35,0

00

274

,781

Totals

160

,055

433

,676

608

,920

598

,532

576

,800

958

,727

618

,008

8/3/2019 COS-STUDY

35/83


Table12

GenerationP

lantExpensesAllocatedbyF

unction

Year

1997

1998

1999

2000

2001

03-04Budg.

StudyYr.

UtilityFunction

AllocationFactor

$

$

$

$

$

$

$

Power

40%

64

,022

173

,470

243

,568

239

,413

230

,720

383,491

247

,203

Energy

60%

96

,033

260

,206

365

,352

359

,119

346

,080

575,236

370

,805

Distribu

tion

Sys

tem

0%

0

0

0

0

0

0

0

Cus

tomer

Serv

ice

0%

0

0

0

0

0

0

0

Stree

tLighting

0%

0

0

0

0

0

0

0

Revenue

0%

0

0

0

0

0

0

0

Total

100%

160

,055

433

,676

608

,920

598

,532

576

,800

958,727

618

,008

8/3/2019 COS-STUDY

36/83


Table 13Annual Electric Utility Expenses By Function ( $ )

Year 1997 1998 1999 2000 200103-04Budg. Study Yr.

Customer Service $ $ $ $ $ $ $Meter Expense 473 1,687 38 5,007 2,328 5,000 5,000

General Expenses 205,650 221,198 213,413 245,982 238,049 295,376 295,376Generation Plant Expenses 0 0 0 0 0 0 0

Subtotal 206,123 222,885 213,451 250,989 240,377 300,376 300,376

Street LightingStreet Lighting 4,809 5,626 1,342 4,334 5,417 3,000 3,000General Expenses 6,855 7,373 7,114 8,199 7,935 9,846 9,846Generation Plant Expenses 0 0 0 0 0 0 0

Subtotal 11,664 12,999 8,456 12,533 13,352 12,846 12,846

Power (Demand)Purchased Power 91,171 113,174 95,309 108,921 111,613 160,000 135,000General Expenses 205,650 221,198 213,413 245,982 238,049 295,376 295,376Generation Plant Expenses 64,022 173,470 243,568 239,413 230,720 383,491 247,203

Subtotal 360,843 507,842 552,290 594,316 580,382 838,867 677,579

Energy

Energy Purchases - Energy 169,317 210,179 177,002 202,282 207,280 255,000 210,000General Expenses 34,275 36,866 35,569 40,997 39,675 49,229 49,229Generation Plant Expenses 96,033 260,206 365,352 359,119 346,080 575,236 370,805

Subtotal 299,625 507,251 577,922 602,398 593,035 879,466 630,034

Distribution SystemTransmission/Distribution Expense 62,316 37,951 34,880 42,874 31,276 50,000 50,000Toll Charges 11,292 14,148 16,168 19,144 12,888 23,500 23,500New Vehicles $ Equip. 0 0 0 0 39,298 60,000 0Capital Improvements - System 30,521 96,728 66,982 105,352 79,548 51,000 0General Expenses 205,650 221,198 213,413 245,982 238,049 295,376 295,376Generation Plant Expenses 0 0 0 0 0 0 0

Subtotal 309,779 370,025 331,443 413,352 401,059 479,876 368,876

RevenueTo General Fund 29,436 124,045 125,202 129,365 859,112 190,216 180,000

To Cable TV Fund - One Time 0 55,000 0 250,000 0 0 0To Equipment Replacement Fund 0 0 110,457 0 0 0 54,000To General Fund - One Time 0 0 150,000 0 0 0 0To Capital Projects Fund 100,000 0 35,000 35,000 35,000 35,000 274,781Retirees Insurance Reimbursement 0 15,788 21,813 19,757 20,023 28,285 28,285Misc. Revenues (11,470) (1,480) (7,647) (1,858) (870) (130,000) (5,000)Line Installation Costs (12,897) (8,472) (21,593) (17,928) (13,612) (10,000) (10,000)Timber Sales (20,975) 0 0 0 0 0 0Penalties (13,575) (17,348) (15,178) (16,268) (16,256) (17,000) (17,000)Interest on Investments (87,303) (74,150) (72,379) (72,191) (45,868) (25,000) (25,000)Sale of Property 0 0 0 0 0 (200,000) 0Developer Contributions 0 (1,061) (2,599) (8,103) 0 (10,000) (10,000)Plan Review/ ConsultingReimbursement 0 0 0 0 0 0 0

Transfers In From Other Funds 0 (4,097) 0 (113,229) 0 0 0From Fund Equity - One Time 0 0 0 0 0 0 0General Expenses 27,420 29,493 28,455 32,798 31,740 39,383 39,383Generation Plant Expenses 0 0 0 0 0 0 0Property Acquisition 0 0 0 0 0 0 0

Subtotal 10,636 117,718 351,531 237,343 869,269 (99,116) 509,450

Grand Total 1,198,670 1,738,722 2,035,094 2,110,930 2,697,474 2,412,314 2,499,160

8/3/2019 COS-STUDY

37/83


In Table 13, the power and energy cost functions vary somewhat withthe weather and with economic development from year to year butshow a generally increasing trend. Colder weather during any oneparticular year will cause people to use electric heat more, increasingthe wholesale energy costs to the utility. Unusually warm weather willcause utility customers to use more air conditioning, again boostingthe utility wholesale energy costs for that year. The distributionfunction costs also vary from year to year, primarily due toexpenditures for maintenance and capital improvements. The revenuecosts vary tremendously from year to year. In 2001, a large transferwas made to the city general fund. During other years, inconsistenciesin transfers to other city funds or revenues from non-core utilityactivities have resulted in the variations from year to year.

6.3 Allocation of Revenue Requirements to Customer Classes

Now that we have accomplished the functionalization of utilityrevenue requirements by cost function and the classification by service

type, we must allocate these costs fairly to the utility customer classesto determine the cost of serving each customer class. The City ofNorway has five primary customer classes as follows:

1. Residential2. Commercial3. Small Industrial4. Industrial5. Street Lighting

Customer service costs vary with the number of customers, or meters,

that a utility supplies. Typically, some types of customers require morecustomer service attention than others. Three phase customers mayhave higher metering costs or may have more questions regarding theirbills, service connection or power quality. For these and other reasons,it is customary to apply weighting factors to the raw quantity ofcustomer meters in each customer class. Table 14 illustrates thecustomer service weighting factor process for Norway. Table 14 is amodification of Table 5, presented previously. Residential customersare typically assigned a weighting factor of one. We have assigned aweighting factor of three to the commercial customers and smallindustrial customers. The industrial customers receive a weighting

factor of five. Street lighting customers have been assigned aweighting factor of 0.5.

8/3/2019 COS-STUDY

38/83


The weighting factors are used to adjust the quantity of meters in eachcustomer class and the overall total for the utility. The weightedquantity of meters in each customer class can be divided by the totalnumber of utility meters to obtain an allocation factor. This allocationfactor, expressed as a percentage of the total meters, will be used laterto fairly allocate the customer service costs to each class of utilitycustomers.

Table 14Customer Metering Allocation Factors

Year 1997 1998 1999 2000 200103-04Budg. Study Yr.

Residential

Number of Meters 1669 1720 1897 1976 1979 2077 2077Weighting Factor 1.0 1.0 1.0 1.0 1.0 1.0 1.0Weighted Meters 1,669.0 1,720.0 1,897.0 1,976.0 1,979.0 2,077.0 2,077.0Percent of Weighted Total 75.6% 74.2% 76.3% 77.1% 77.6% 77.6% 77.6%

Commercial

Number of Meters 171 189 186 186 183 192 192Weighting Factor 3.0 3.0 3.0 3.0 3.0 3.0 3.0Weighted Meters 513.0 567.0 558.0 558.0 549.0 576.0 576.0Percent of Weighted Total 23.2% 24.5% 22.4% 21.8% 21.5% 21.5% 21.5%

Small IndustrialNumber of Meters 4 4 4 4 4 4 4Weighting Factor 3.0 3.0 3.0 3.0 3.0 3.0 3

cos-study

Documents