Festival Hydro's Notice of Application for Electrical Distribution Change

Festival Hydro Inc. 

EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 1 

Page 1 of 11 

Filed: August 28, 2009 

FESTIVAL HYDRO INC. 

APPLICATION FOR APPROVAL OF ELECTRICITY DISTRIBUTION RATES 

EFFECTIVE MAY 1, 2010 

INDEX 

Exhibit Tab Schedule Appendix Contents 

1 – Administrative 

Documents 

1 Administration 

1 Index 

2 Application 

A Schedule of Proposed Rates and Charges 

3 Contact Information 

4 List of Specific Approvals Requested 

5 Draft Issues List 

6 Procedural Orders/Motions/Notices 

7 Accounting Orders Requested 

8 Compliance with Uniform System of 

Accounts 

9 Distribution Service Territory and 

Distribution System 

B Map of Distribution Service Territory 

C Map of Distribution System 

10 List of Neighboring Utilities 

11 Explanation of Host and Embedded 

Utilities 

12 Utility Organization Structure 

13 Corporate Entities Relationships Chart 

14 Planned Changes in Corporate and 

Organizational Structure


1-Administrative 

15 Preliminary List of Witnesses 

Documents – Cont. 


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 1 



2 Overview 

1 Summary of the Application 

D Comparison of Festival Hydro Inc. 

OM&A Costs to “Mid Size Southern 

Medium-High Undergrounding” Cohort 

Grouping 

2 Budget Directives 

3 Changes in Methodology 

4 Calculation of Revenue Deficiency 

5 Causes of Revenue Deficiency 

E Revenue Requirement Work Form 

3 Finance 

1 Financial Statements –2007 and 2008 

F Copy of Audited Financial Statements for 

2007 and 2008 

2 Pro Forma Financial Statements – 

2009 and 2010 

G Copy of Festival Hydro Inc. 2009 Pro 

Forma Statements


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 1 



1 - Administrative 

Documents – Cont. 

H Copy of Festival Hydro Inc. 2010 Pro 

Forma Statements 

3 Reconciliation Between Pro Forma 

Statements and Revenue Deficiency 

Statements 

4 Information on Affiliates 

5 Materiality Thresholds


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 1 




2 – Rate Base 

1 Overview 

1 Rate Base Overview 

2 Variance Analysis on Rate Base Table 

2 Gross Assets – Property, Plant and 

Equipment Accumulated Depreciation 

1 Continuity Statements 

2 Gross Assets Table 

3 Variance Analysis on Fixed Asset By 

Project 

4 Accumulated Depreciation Table 

5 Variance Analysis on Accumulated 

Depreciation 

3 Capital Budget 

1 Capital Project Description 

2 Asset Management Plan Summary 

A Asset Management Plan Report 

3 Capitalization Policy 

4 Allowance for Working Capital 

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Overview and Calculation by Account 

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2009 & 2010 Cost of Power Forecast 

Calculation


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 1 




3 – Operating Revenue 

1 Overview 

1 Overview of Operating Revenue 

2 Summary of Operating Revenue Table 

3 Variance Analysis on Operating Revenue 

2 Throughput Revenue 

1 Weather Normalized Load and Customer/ 

Connection Forecast 

A Monthly Data Used for Regression Analysis 

B Heating and Cooling Degrees Table 

3 Other Distribution Revenue 

1 Summary of Other Distribution Revenue 

2 Variance Analysis on Other Distribution 

Revenue 

4 Revenue Sharing 

1 Description of Revenue Sharing


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 1 




4 – Operating Costs 

1 Overview 

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Overview of Operating Costs 

A 2008 Federal and Ontario Tax Return 

2 Manager’s Summary of OM&A Costs 

1 Departmental and Corporate OM&A 

Activities 

2 OM&A Detailed Costs Table 

3 Variance Analysis on OM&A Costs 

4 Charges to Affiliates for Services 

Provided 

B Affiliate Service Agreements 

5 Purchase of Products and Services from 

non-affiliates 

6 Employee Compensation, Incentive Plan 

Expenses, Pension Expense and Post 

Retirement Benefits 

7 Depreciation, Amortization and Depletion 

C Depreciation Calculations by Account 

3 Income Tax, Large Corporation Tax 

1 Tax Calculations 

2 Capital Cost Allowance (CCA)


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 1 




5 – Cost of Capital and 

Rate of Return 

1 1 Overview 

2 Capital Structure Deemed & Actual 

3 Analysis 

A Promissory Note


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 1 




6 – Calculation of 

Revenue Deficiency or 

Surplus 

1 1 Revenue Deficiency – Overview 

2 Drivers of Revenue Deficiency


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 1 




7 – Cost 

Allocation 

1 1 Cost Allocation Overview 

2 Summary of Results and Proposed 

Adjustments 

3 Revenue to Cost Ratios


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 1 




8 – Rate Design 

1 1 Rate Design Overview 

2 Rate Mitigation 

3 Other Electricity Charges 

4 Existing Rate Classes 

5 Existing Rate Schedule 

6 Schedule of Proposed Rates and Charges 

7 Reconciliation of Rate Class Revenue 

8 Rate and Bill Impacts 

A Table of Rate and Bill Impacts


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 1 




9 – Deferral and 

Variance Accounts 

1 1 Deferral and Variance Accounts & 

Balances 

2 Clearance of Deferral/Variance Accounts 

by way of a Deferral and Variance 

Account Rate Rider 

A Methods of Disposition of Accounts 

3 Proposed Rates and Bill Impacts 

4 Smart Meters 

B Letter from PRP International Inc. 

Fairness Advisory Services


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 2 



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IN THE MATTER OF the Ontario Energy Board Act, 1998, 

being Schedule B to the Energy Competition Act, 1998, S.O. 

1998, c.15; 

AND IN THE MATTER OF an Application by Festival Hydro 

Inc. to the Ontario Energy Board for an Order or Orders 

approving or fixing just and reasonable rates and other service 

charges for the distribution of electricity as of May 1, 2010. 

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Title of Proceeding: 

Applicant’s Name: 

Applicant’s Address for Service: 

An application by Festival Hydro Inc. for an Order or 

Orders approving or fixing just and reasonable distribution 

rates and other charges, effective May 1, 2010. 


187 Erie St. 

P.O. Box 397 

Stratford, ON N5A 6T5 

Attention: Mr. Bill Zehr, President 

Telephone: (519) 271-4703 ext. 243 

Fax: (519) 271-7204 

E-mail: bzehr@festivalhydro.com


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 2 



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1. Introduction 

APPLICATION 

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(a) 

(b) 

(c) 

The Applicant is Festival Hydro Inc. (referred to in this Application as the 

“Applicant”, “Festival Hydro” or “FHI”). The Applicant is a corporation 

incorporated pursuant to the Ontario Business Corporations Act with its head 

office in the City of Stratford. The Applicant carries on the business of 

distributing electricity within the City of Stratford, and the towns of Seaforth, 

Brussels, Hensall, Zurich, Dashwood and St. Marys. 

The Applicant hereby applies to the Ontario Energy Board (the “OEB”) pursuant 

to Section 78 of the Ontario Energy Board Act, 1998 (the “OEB Act”) for 

approval of its proposed distribution rates and other charges, effective May 1, 

2010. A list of requested approvals is set out in Exhibit 1, Tab 1, and Schedule 4. 

Except where specifically identified in the Application, the Applicant followed 

Chapter 2 of the OEB’s Filing Requirements for Transmission and Distribution 

Applications dated May 27, 2009 (the “Filing Requirements”) in order to prepare 

this application. 

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2. Proposed Distribution Rates and Other Charges 

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(a) 

The Schedule of Rates and Charges proposed in this Application is identified in 

Appendix A attached to this application and Exhibit 8, Tab 1, and Schedule 6, 

and the material being filed in support of this Application sets out Festival 

Hydro’s approach to its distribution rates and charges. 

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3. Proposed Effective Date of Rate Order 

(a) The Applicant requests that the OEB make its Rate Order effective May 1, 2010 

in accordance with the Filing Requirements or as soon as possible thereafter in the


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 2 



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(b) 

event that the OEB is unable to provide a Decision and Order in this Application 

for implementation by the Applicant as of May 1, 2010. 

An order providing for notice of the Application and for such procedural order(s) 

as may be considered appropriate by the Board for the proper conduct and 

disposition of the Application. 

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4. The Proposed Distribution Rates and Other Charges are Just and Reasonable 

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(a) 

The Applicant submits the proposed distribution rates contained in this 

Application are just and reasonable on the following grounds: 

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(i) 

(ii) 

(iii) 

(iv) 

(v) 

the proposed rates for the distribution of electricity have been prepared in 

accordance with the Filing Requirements and reflect traditional rate 

making and cost of service principles; 

the proposed adjusted rates are necessary to meet the Applicant’s Market 

Based Rate of Return (“MBRR”) and Payments in Lieu of Taxes (“PILs”) 

requirements; 

there are no impacts to any of the customer classes or consumption level 

subgroups that are so significant as to warrant the deferral of any 

adjustments being requested by the Applicant or the implementation of 

any other mitigation measures; 

the other service charges proposed by the Applicant are the same as those 

previously approved by the OEB; and 

such other grounds as may be set out in the material accompanying this 

Application Summary. 

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EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 2 



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5. Relief Sought 

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(a) 

(b) 

The Applicant applies for an Order or Orders approving the proposed distribution 

rates and other charges set out in Exhibit 1, Tab 1, Schedule 2, Appendix A to this 

Application as just and reasonable rates and charges pursuant to Section 78 of the 

OEB Act, to be effective May 1, 2010 or as soon as possible thereafter in the 

event that the OEB is unable to provide a Decision and Order in this Application 

for implementation by the Applicant as of May 1, 2010. 

An order providing for notice of the Application and for such procedural order(s) 

as may be considered appropriate by the Board for the proper conduct and 

disposition of the Application. 

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6. Form of Hearing Requested 

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(a) 

The Applicant requests that this Application be disposed of by way of a written 

hearing. 

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DATED at Stratford, Ontario, this 28th day of August, 2009. 

All of which is respectfully submitted, 

Mr. Bill Zehr 


187 Erie St. 


Telephone: (519) 271-4703 ext. 243 

Facsimile: (519) 271-7204


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 2 

Appendix A 


APPENDIX A 

SCHEDULE OF PROPOSED RATES AND CHARGES


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 2 

Appendix A 



SCHEDULE OF PROPOSED RATES AND CHARGES 

MONTHLY RATES AND CHARGES 

Residential 

Service Charge $ 15.53 

Distribution Volumetric Rate $/kWh 0.0172 

Low Voltage Cost Recovery Adder $/kWh 0.0001 

Smart Meter Adder $/month 1.00 

Deferral and Variance Account Rate Rider $/kWh (0.0009) 

Retail Transmission Rate - Network Service Rate $/kWh 0.0055 

Retail Transmission Rate - Line and Transformation Connection Service Rate $/kWh 0.0042 

Wholesale Market Service Rate $/kWh 0.0052 

Rural Rate Protection Charge $/kWh 0.0013 

Standard Supply Service - Administrative Charge (if applicable) $ 0.25 

Residential (Hensall) 











General Service Less Than 50 kW 




Smart Meter Adder $/mo 1.00 







General Service 50 to 4,999 kW 


Distribution Volumetric Rate $/kW 2.5255 

Low Voltage Cost Recovery Adder $/kW 0.0001 


Deferral and Variance Account Rate Rider $/kW (0.3676) 

Retail Transmission Rate - Network Service Rate $/kW 2.0144 

Retail Transmission Rate - Line and Transformation Connection Service Rate $/kW 1.5036 

Retail Transmission Rate - Network Service Rate - Interval Metered $/kW 2.1394 

Retail Transmission Rate - Line and Transformation Connection Service Rate - Interval Metered $/kW 1.6483 



Standard Supply Service - Administrative Charge (if applicable) $ 0.25


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 2 

Appendix A 



Large Use 

Service Charge $ 8,730.51 










Unmetered Scattered Load 

Service Charge (per connection) $ 12.91 









Sentinel Lighting 










Street Lighting 






Retail Transmission Rate - Lien and Transformation Connection Service Rate $/kW 1.1624 





EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 2 

Appendix A 



Specific Service Charges 

Customer Administration 

Arrears certificate $ 15.00 

Income tax letter $ 15.00 

Credit reference/credit check (plus credit agency costs) $ 15.00 

Returned Cheque (plus bank charges) $ 15.00 

Account set up charge/change of occupancy charge (plus credit agency costs if applicable) $ 30.00 

Meter dispute charge plus Measurement Canada fees (if meter found correct) $ 30.00 

Non-Payment of Account 

Late Payment - per month % 1.50 

Late Payment - per annum % 19.56 

Collection of account charge - no disconnection $ 30.00 

Disconnect/Reconnect Charge - At Meter During Regular Hours $ 65.00 

Disconnect/Reconnect Charge - At Meter After Hours $ 185.00 

Disconnect/Reconnect at pole - during regular hours $ 185.00 

Disconnect/Reconnect at pole - after regular hours $ 415.00 

Install/Remove load control device - during regular hours $ 65.00 

Install/Remove load control device - after regular hours $ 185.00 

Service call - customer owned equipment $ 30.00 

Service call - after regular hours $ 165.00 

Temporary service install & remove - overhead - no transformer $ 500.00 

Temporary service install & remove - underground - no transformer $ 300.00 

Temporary service install & remove - overhead - with transformer $ 1000.00 

Specific Charge for Access to the Power Poles - per pole/year $ 22.35 

Allowances 

Transformer Allowance for Ownership - per kW of billing demand/month $/kW (0.60) 

Primary Metering Allowance for transformer losses - applied to measured demand and energy % (1.00) 

Retail Service Charges (if applicable) 

Retail Service Charges refer to services provided by a distributor to retailers or customers related 

to the supply of competitive electricity 

LOSS FACTORS 

One-time charge, per retailer, to establish the service agreement between the distributor and the retailer $ 100.00 

Monthly Fixed Charge, pre retailer $ 20.00 

Monthly Variable Charge, per customer, per retailer $/cust. 0.50 

Distributor-consolidated billing charge, per customer, per retailer $/cust. 0.30 

Retailer-consolidated billing credit, per customer, per retailer $/cust. (0.30) 

Service Transaction Requests (STR) 

Request fee, per request, applied to the requesting party $ 0.25 

Processing fee, per request, applied to the requesting party $ 0.50 

Request for customer information as outlined in Section 10.6.3 and Chapter 11 of the Retail 

Settlement Code directly to retailers and customers, if not delivered electronically through the 

Electronic Business Transaction (EBT) system, applied to the requesting party 

Up to twice a year 

no charge 

More than twice a year, per request (plus incremental delivery costs) $ 2.00 

Total Loss Factor - Secondary Metered Customer 5,000 kW 1.0176 

Total Loss Factor - Primary Metered Customer 5,000kW 1.0075


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 3 



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CONTACT INFORMATION: 


187 Erie Street, P.O. Box 397 


PRESIDENT: 

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Mr. Bill Zehr 

Telephone: (519) 271-4703 ext. 243 

Facsimile: (519) 271-7204 

E-mail: bzehr@festivalhydro.com 

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VP ENGINEERING & OPERATIONS: 

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Mr. Jac Vanderbaan 

Telephone: (519) 271-4703 ext. 241 

Facsimile: (519) 271-7204 

E-mail: jvanderbaan@festivalhydro.com 

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SECRETARY TREASURER 

Mrs. Debbie Reece 

Telephone: (519) 271-4703 ext. 268 

Facsimile: (519) 271-7204 

E-mail: dreece@festivalhydro.com 

FINANCIAL & REGULATORY ANALYST 

Mrs. Kelly McCann 

Telephone: (519) 271-4703 ext. 221 

Facsimile: (519) 271-7204 

E-mail: kmccann@festivalhydro.com


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 4 



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SPECIFIC APPROVALS REQUESTED: 

In this proceeding, Festival Hydro is requesting the following approvals: 

‣ Approval to charge rates effective May 1, 2010 to recover a revenue requirement of 

$10,511,581 as set out in Exhibit 1, Tab 2, Schedule 4 and Exhibit 6, Tab 1, Schedule 1. 

The schedule of proposed rates is set out in Exhibit 1, Tab 1, Schedule 2 Appendix A and 

Exhibit 8 Tab 1 Schedule 6; 

‣ Approval of the Applicant’s proposed change in capital structure, decreasing the 

Applicant’s deemed common equity component from 43.3% to 40.0% and increasing the 

deemed debt component from 56.67% to 60.0% comprised of 56% for long term debt and 

4% for short term debt, as set out in Exhibit 5, Tab 1, Schedule 2, consistent with Report 

of the Board on Cost of Capital and 2nd Generation Incentive Regulation for Ontario’s 

Electricity Distributors dated December 20, 2006. The change in capital structure is 

anticipated to result in a reduced cost of capital of $120,345. 

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‣ Approval of revised Low Voltage Cost Recovery Adder as proposed and described in 

Exhibit 8, Tab 1, Schedule 1; 

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‣ Approval of the rate adder of $1.00 per customer per month to fund Smart Meter 

activities as proposed and described in Exhibit 8, Tab 1, Schedule 1; 

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‣ Approval of the proposed loss factors as set out in Exhibit 8, Tab 1, Schedule 1; 

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‣ Approval of revised Retail Transmission rates as proposed and described in Exhibit 8, 

Tab 1, Schedule 1. 

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‣ Approval to continue the Specific Service Charges and Transformer Allowance approved 

in the OEB Decision and Order in the matter of Festival Hydro’s 2009 Distribution Rates 

(EB-2008-0175)


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 4 



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‣ Approval to dispose of the following Deferral and Variance Account Balances as at 

December 31, 2008 with applicable interest to April 30, 2010 over a four-year period 

using the method of recovery described in Exhibit 9, Tab 1, Schedule 3: 

1508 Other Regulatory Assets 

1518 Retail Cost Variance Account – Retail 

1548 Retail Cost Variance Account – STR 

1550 Low Voltage 

1580 RSVA - Wholesale Market Service Charge 

1582 RSVA - One-time Wholesale market Service 

1584 RSVA - Retail Transmission Network Charge 

1586 RSVA - Retail Transmission Connection Charge 

1588 RSVA – Power 

‣ The following accounts have offsetting balances and FHI requests the balances to 

removed from the accounts. 

1565 CDM Expenditures & Recoveries 

1566 CDM Contra Account


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 5 



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DRAFT ISSUES LIST: 

The Applicant would expect, based on previous regulatory experience and other hearings, that 

the following matters pertaining to the 2010 Test Year may constitute issues in this Application: 

‣ The amount of Festival Hydro’s proposed revenue requirement; 

‣ The reasonableness of the proposed electricity distribution rates; and 

‣ The reasonableness of the 2010 capital program. 

‣ The reasonableness of the 2010 operating, maintenance and administrative budget 

‣ The reasonableness of the 2010 weather normalized forecast and customer forecast.


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 6 



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PROCEDURAL ORDERS/MOTIONS/NOTICES: 

On March 2, 2007, the OEB issued a Report titled "LDC Screening Methodology to Establish a 

Rebasing Schedule for Electricity LDCs". The purpose of that Report was "to describe the 

criteria to be considered in determining which electricity distributors to engage in proceedings 

before the Board for rebasing to establish rates for each of the years 2009, 2010 and 2011” and to 

establish the next steps and timelines for filing. Section 3.3 of that Report provided an 

opportunity for LDCs to "self-nominate" to be rebased in a particular year. 

On March 28, 2008, Festival Hydro filed a self-nomination request for rebasing in 2010. 

Subsequently, in Board File No. EB-2006-0330, the OEB issued its list of distributors that will 

be rebased in 2010. Festival Hydro was included on that list. 

On March 5, 2009, in Board File No. EB-2009-0028, the OEB issued its list of distributors that 

will be rebased in 2010 and 2011. Festival Hydro was included on the 2010 list. 

FHI has no orders or directions outstanding.


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 7 



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ACCOUNTING ORDERS REQUESTED: 

Festival Hydro is not requesting Accounting Orders in this proceeding.


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 8 



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COMPLIANCE WITH UNIFORM SYSTEM OF ACCOUNTS: 

Festival Hydro has followed the accounting principles and main categories of accounts as stated 

in the OEB’s Accounting Procedures Handbook (the “APH”) and the Uniform System of 

Accounts (“USoA”) in the preparation of this Application.


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 9 



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DISTRIBUTION SERVICE TERRITORY AND DISTRIBUTION SYSTEM: 

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Description of Distributor: 

COMMUNITIES SERVED: 

Stratford 

Seaforth 

Brussels 

Hensall 

Zurich 

Dashwood 

St. Marys 

TOTAL SERVICE AREA: 

45 sq km 

RURAL SERVICE AREA: 

0 sq km 

DISTRIBUTION TYPE: 

Electricity distribution 

SERVICE AREA POPULATION: 43,541 

MUNICIPAL POPULATION: 43,541 

A map of Festival Hydro’s Distribution Service Territory accompanies this Schedule as 

Appendix B. 

A schematic diagram of Festival Hydro’s distribution system is attached in Appendix C.


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 9 

Appendix B 


APPENDIX B 

MAP OF DISTRIBUTION SERVICE TERRITORY


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 9 

Appendix B 



MAP OF DISTRIBUTION SERVICE TERRITORY 

The map below highlights the service territory of FHI.


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 9 

Appendix B 


Filed: August 28, 2009


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 9 

Appendix C 


APPENDIX C 

MAP OF DISTRIBUTION SYSTEM


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 9 

Appendix C 



MAP OF FESTIVAL HYDRO INC. DISTRIBUTION SYSTEM 

The following distribution system maps are included below: 

 

 

 

 

 

 

 

 

City of Stratford 4.16kV distribution system 

City of Stratford 27.6kV distribution system 

St. Mary’s 13.8kV distribution system 

Hensall 27.6kV distribution system 

Zurich 27.6kV distribution system 

Seaforth 4.16kV distribution system 

Dashwood 8.3kV distribution system 

Brussels 8.3kV distribution system


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 9 

Appendix C 




EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 9 

Appendix C 




EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 9 

Appendix C 




EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 9 

Appendix C 




EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 9 

Appendix C 




EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 9 

Appendix C 




EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 9 

Appendix C 




EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 9 

Appendix C 




EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 10 


Date Filed: August 28, 2009 

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LIST OF NEIGHBOURING UTILITIES: 

Festival Hydro is bounded by Hydro One Networks Inc. on all service territory boundaries.


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 11 


Filed August 28, 2009 

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EXPLANATION OF HOST AND EMBEDDED UTILITIES: 

FHI is a Registered Market Participant for the purposes of settlement with the Independent 

Electricity System Operator. However, FHI is considered a partially “embedded” LDC because 

it receives some of its electricity from Hydro One Network Inc.’s low voltage distribution system 

for electricity supplied to our customers in the towns of Brussels, Seaforth, Hensall, Zurich, and 

Dashwood.


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 12 



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UTILITY ORGANIZATIONAL STRUCTURE: 

Festival Hydro Inc. is wholly owned by the City of Stratford. Festival Hydro Inc. is the licensed 

distributor. Festival Hydro Services Inc. is also wholly owned by the City of Stratford. Festival 

Hydro Services Inc. owns assets including sentinel lights, and dark fibre optic cable. Festival 

Hydro Services Inc. has no employees and management services are contracted from Festival 

Hydro Inc. Festival Hydro Inc. also supplies street lighting installation and repair services to the 

City of Stratford. The City of Stratford provides tree trimming services to Festival Hydro Inc. 

within the City of Stratford. In addition to these shared services, Festival Hydro Inc. provides 

waste and sewage billing services to the City of Stratford as well as rents a bay from the service 

Centre to the City of Stratford water department. 

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The City of Stratford does not have a holding company for Festival Hydro Inc. or Festival Hydro 

Services Inc., but each company reports to the Finance and Labour Relations Subcommittee on a 

quarterly basis. Both companies also hold monthly board meetings. A chart illustrating Festival 

Hydro’s corporate family is provided at Exhibit 1, Tab 1, Schedule 13 followed by a corporate 

organization chart.


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 13 



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CORPORATE ENTITIES RELATIONSHIP CHART 

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EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 13 




EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 14 



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PLANNED CHANGES IN CORPORATE AND OPERATIONAL STRUCTURE: 

No changes to Festival Hydro’s corporate and operational structures are planned at the present 

time.


EB-2009-0263 

Exhibit 1 

Tab 1 

Schedule 15 



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PRELIMINARY LIST OF WITNESSES: 

While Festival Hydro requests that this Application be disposed of by way of a written hearing, 

should a technical conference or an oral hearing be necessary, Festival Hydro will provide a list 

of potential witnesses as required.


EB-2009-0263 

Exhibit 1 

Tab 2 

Schedule 1 



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SUMMARY OF THE APPLICATION: 

Preamble 

This Application has been prepared for submission to the Ontario Energy Board in accordance 

with the requirements specified in the Ontario Energy Board Chapter 2 of the Filing 

Requirements for Transmission and Distribution Applications dated May 27, 2009. In addition, 

this Application is consistent with Festival Hydro’s Corporate Mission and Corporate Goals 

outlined below. Current rates will result in actual Return on Equity in 2009 and 2010 below 

levels currently approved by the OEB. The increased rates are required to: 

1) Maintain current capital investment levels in infrastructure to ensure a safe, reliable, and 

efficient distribution system. 

2) Manage staffing levels and skills to ensure regulatory compliance, promote conservation 

programs, and implement reporting changes resulting from the adoption of International 

Financial Reporting Standards. 

3) To provide a reasonable rate of return to the Shareholder. 

It is anticipated that additional work may be required and costs incurred as a result of the Green 

Energy and Green Economy Act. However, at this time, Festival Hydro understands that such 

work and costs will be the subject of a future proceeding and therefore has not included any such 

costs in this Application. 

Festival Hydro’s Mission Statement is: 

Festival Hydro Inc. is the distributor of reliable and safe electric power and related 

products and services for the City of Stratford and surrounding communities. We focused 

on delivering dependable, cost-effective and quality services to our customers.


EB-2009-0263 

Exhibit 1 

Tab 2 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

Festival Hydro Inc. conducts the operations of the business prudently to provide profits 

for our shareholder through strong financial performance, ensuring growth and 

sustainability for the future. 

Our employees are one of our strongest assets. Festival Hydro fosters an organizational 

culture that encourages employee growth and development and recognizes individual and 

team contributions. We operate with a strong commitment to maintain a healthy and safe 

working environment for employees and the community. 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

26 

27 

28 

29 

30 

31 

32 

33 

34 

35 

Festival Hydro’s priorities are defined in its Corporate Goals: 

Festival Hydro will incorporate the latest appropriate technological innovations in the 

distribution and delivery of its products. 

We will grow internally and externally through a philosophy that encourages 

accountability, and continuous improvement at all levels of our organization by 

continuing to create economic value added services and through identification of 

opportunities for growth. 

By following the best practices and procedures we strive to be above industry averages 

and to continuously improve our safety record for the workplace and electrical systems. 

We provide ongoing training and education to challenge ourselves to be better and to 

ensure safety for all. 

We are dedicated to providing the highest quality services that not only meet the needs, 

but exceed the requirements of internal and external customers. We are committed to 

continuous improvement and are open to suggestions and options. We create a learning 

environment leading to the most efficient and effective work processes. We anticipate 

needs and learn quickly when facing new challenges; we analyze our actions to improve 

the way we find solutions. 

Personal and corporate integrity is fundamental to our success. We will be direct, 

trustworthy and truthful and will present the unvarnished truth in an appropriate and 

helpful manner. We are accountable for our actions and as such we will do what we say; 

we will keep confidences and build trust; we will admit mistakes and we will not 

misrepresent ourselves for personal gain. 

At Festival Hydro, we create a climate in which people want to do their best. We 

empower others and invite input from each person. We share ownership and visibility for 

our success and convey that each individual’s contribution is important. We foster twoway 

dialogue with others and find positive solutions for work and results; we bring out 

the best in people. As such, we build rapport and relate well with all kinds of people,


EB-2009-0263 

Exhibit 1 

Tab 2 

Schedule 1 



1 

2 

inside and outside the organization. We develop constructive and effective relationships 

and use diplomacy and tact with others. 

3 

4 

5 

6 

In keeping with this vision to pursue health and safety as its top priority, Festival Hydro was 

recently awarded by the Electrical & Utilities Safety Association (“E&USA”) the safety Silver 

Award pursuit of Zero Quest which represents zero injuries and illnesses. 

7 

8 

9 

10 

11 

12 

Festival Hydro has consistently exceeded the OEB’s Service Quality Indicators and, as set out in 

Table 1 below, has targeted to maintain its performance at levels equal to or above the OEB’s 

standards in 2009 and 2010. 

Table 1 

Appointments 

Met at the 

appointed time 

Telephone 

Accessibility 

answered in 

person within 30 

seconds 

Underground 

cable locates 

within 5 working 

days 

Connection of 

new services 

within 5 working 

days 

Emergency 

Response 

within 60 

minutes 

Written 

responses to 

inquiriries 

within 10 

working days 

SAIDI ‐ 

Excluding 

Loss of 

Supply 

Telephone Call 

Abandon Rate 

SAIDI 

SAIFI 

2006 Actual 98.28% 99.71% N/A 99.34% 98.58% NA 100.00% 3.07 2.17 3.43 3.06 

2007 Actual 97.01% 92.68% N/A 98.95% 97.47% NA 100.00% 4.18 2.54 4.82 2.81 

2008 Actual 99.51% 98.27% N/A 99.51% 98.01% 100.00% 100.00% 1.73 1.16 1.86 1.36 

2009 FHI & OEB Target 90.00% 65.00% 

2010 FHI & OEB Target 90.00% 65.00% 

Festival Hydro's Service Quality Indicators & Reliability Statistics 

Average Performance for 2006, 2007, & 2008 as well as targets for 2009 & 2010 

(note that 2009 & 2010 reliability targets are calculated based on the prior 3 year actual years average) 

SAIFI ‐ 

Exlcluding 

Loss of 

Supply 

less than or equal 

to 10% N/A 90.00% 80.00% 80.00% 2.99 1.96 3.37 2.41 

less than or equal 

to 10% N/A 90.00% 80.00% 80.00% 2.97 1.89 3.35 2.19 

13 

14 

**Underground cable locate targets are included in the "Appointments Met" category effective Jan. 1/09 per OEB direction. 

15 

16 

The FHI targets for 2009 and 2010 are compliant with the OEB SQI targets. FHI continuously 

analyzes system reliability and an annual report is created for the Board of Directors and


EB-2009-0263 

Exhibit 1 

Tab 2 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

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20 

21 

22 

23 

24 

Management. A copy of the latest report can be found in Appendix 8 of the Asset Management 

Plan included in Exhibit 2, Tab 3, Schedule 2, Appendix A. 

Purpose and Need 

Festival Hydro’s requested revenue requirement for 2010 in the amount of $10,511,581 includes 

the recovery of its costs to provide distribution services, its permitted Return on Equity [“ROE”], 

PILs and the funds necessary for the cost of capital including its permitted return on equity and 

debt servicing requirements for the 60/40 debt equity capital structure. 

When forecasted energy and demand levels for 2010 are considered, Festival Hydro estimates 

that its present rates will produce a deficiency in gross distribution revenue of $979,467 for the 

2010 Test Year. Should this revenue deficiency continue, Festival Hydro will not be able to 

sustain the current capital investments required to ensure a safe and reliable distribution system. 

Therefore, Festival Hydro seeks the OEB’s approval to revise its electricity distribution rates. 

The rates proposed to recover its projected revenue requirement and other relief sought are set 

out in Exhibit 1, Tab 1, Schedule 2, Appendix A and Exhibit 8, Tab 1, Schedule 6 to this 

Application. 

The information presented in this Application is Festival Hydro’s forecasted results for its 2010 

Test Year. Festival Hydro is also presenting the historical actual information for fiscal 2006, 

OEB-Approved data for 2006, actual information for fiscal 2007 and fiscal 2008, and forecast 

results for the 2009 Bridge Year. 

Timing 

The financial information supporting the Test Year for this Application will be Festival Hydro’s 

fiscal year ending December 31, 2010 (the “2010 Test Year”). However, this information will be 

used to set rates for the period May 1, 2010 to April 30, 2011.


EB-2009-0263 

Exhibit 1 

Tab 2 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

Customer Impact 

In preparing this application, Festival Hydro has considered the impacts on its customers, with a 

goal of minimizing those impacts. With respect to cost allocation, Festival Hydro notes that for 

the majority of its customers, the revenue to cost ratio of each rate class falls within the 

applicable threshold defined by the OEB in the OEB’s November 28, 2007 Report on 

Application of Cost Allocation for Electricity Distributors (the “Cost Allocation Report”). 

However, FHI has proposed certain changes to the rates, such as the street lighting class, as a 

result of the cost allocation study, that will reduce cross-subsidization. There is also a small 

segment of residential customers (413 customers) known as Hensall Residential who will 

experience higher bill impacts due to the move towards harmonization of Festival Hydro’s 

residential rates. 

Customer impacts including the percentage average Total Bill Impact and Average Dollar 

Impact, which include revised distribution rates [monthly service charge and volumetric rates], 

revised loss factors, revised low voltage cost recovery adder, revised retail transmission service 

rates, and deferral and variance rate riders to dispose of the balances in the Deferral and Variance 

Accounts requested in this Application over a four-year period. The comparison is between 

typical usages billed at approved 2009 rates to proposed 2010 rates. 

18


EB-2009-0263 

Exhibit 1 

Tab 2 

Schedule 1 



1 

Table 2 

Total Bill Impact - Precentage & Dollar 

Class - Typcial Usage 

Total Bill Impact 

(%) 

Monthly Dollar 

Impact 

Residential 

800 kWh 1.83% $ 

1.80 

1,000 kWh 1.54% $ 

1.90 

Residential Hensall 

800 kWh 7.45% $ 

6.72 

1,000 kWh 6.59% $ 

7.35 

GS < 50kW 

2,000 kWh 0.99% $ 

1.43 

10,000 kWh 0.04% $ 

0.40 

GS > 50kW to 4,999 kW 

100 kW, 30,000 kWh -1.78% $ 

(57.71) 

500 kW, 200,000 kWh -1.22% $ 

(235.34) 

2,000 kW 800,000 kWh (interval metered) -0.45% $ 

(344.29) 

Large Use 

5,400 kW 2,400,000 kWh -1.76% $ (3,978.40) 

7,500 kW 3,100,000 kWh -1.68% $ (4,879.19) 


1 connection, .17 kW, 62.47 kWh 8.89% $ 

0.54 

5916 connections, 938 kW, 325344 kWh (monthly load) 9.73% $ 3,146.15 

Sentinel Lights 

1 connection, .68 kW, 235.63 kWh 12.84% $ 

3.05 

83 connections, 57 kW, 19558 kWh (monthly load) 12.86% $ 

253.62 

2 


1 connection, 336 kWh -3.92% $ 

(1.90) 

156 connections, 52,478 (monthly load) -4.51% $ 

(341.48) 

3


EB-2009-0263 

Exhibit 1 

Tab 2 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

26 

27 

Capital Structure 

Festival Hydro is requesting a change in its deemed capital structure. Specifically, Festival 

Hydro is requesting a decrease in the deemed equity ratio from 43.3% to 40.0% consistent with 

the third year of the phase-in of the shift in Festival Hydro’s capital structure from 50% to 40% 

equity as outlined in the Report of the Board on Cost of Capital and 2 nd Generation Incentive 

Regulation for Ontario Electricity Distributors dated December 20, 2006 (the “Cost of Capital 

Report”). 

Return on Equity 

Festival Hydro has assumed a return on equity of 8.01% consistent with the Cost of Capital 

Parameter Updates for 2009 Cost of Service Applications issued by the OEB on February 24, 

2009. Festival Hydro understands the OEB will be finalizing the return on equity for 2010 rates 

based on January 2010 market interest rate information. Festival Hydro’s use of a return of 

equity 8.01% is without prejudice to any revised return on equity that may be adopted by the 

OEB in early 2010. 

Capital Expenditures 

Festival Hydro continues to expand and reinforce its distribution system in order to meet the 

demand of new and existing customers in its service territory. The increase in demand comes 

both from expansion of the FHI distribution system into currently non-serviced areas and 

distribution system upgrades required in existing areas. 

Major projects planned for 2010 include: 

The purchase of new transformers for all planned projects in 2010 

Approximately 40 small customer driven projects such as new commercial and industrial 

service connections (which may or may not require new primary extensions and 

transformation), line relocations (requested by MTO or City), single pole relocations (to 

accommodate new or expanded driveways), new subdivisions (which may or may not 

require line extensions), in-fill projects (which typically require new or upgraded 

transformers), and make-ready work for third party attachments. Capital contributions


EB-2009-0263 

Exhibit 1 

Tab 2 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

are collected from customers consistent with the respective customer class as outlined in 

FHI’s Conditions of Services. For eligible projects (subdivisions), FHI will perform an 

Economic Evaluation to determine the capital contribution required. 

The replacement of a radial boom derrick truck (# 4 - 1994 vintage), a minivan (#13 - 

1997 vintage), and one sedan (#20 - 1999 vintage). These three vehicles are deemed to 

be at end of life based on physical condition, cost to maintain, in-field failure frequency, 

and maintainability 

Stratford MS #1 Ph2-Conversion 

Stratford Delamere – Rebuild 

Stratford Douro Ph2 Rebuild 

The capital program is supported by the Asset Management Plan which is included in Exhibit 2, 

Tab 3, Appendix A. 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

26 

27 

Operating and Maintenance Costs 

Based on the OEB’s Comparison of Ontario Electricity Distributors Costs [EB-2006-0268], as 

updated with 2007 Data issued on June 25, 2008, Festival Hydro’s OM&A costs per customer 

compare favorably with its “Mid Size Southern Medium-High Undergrounding” cohort. In 

2007, the average OM&A cost per customer for the cohort was $214.00 while Festival Hydro’s 

cost was $185.00. Over the 3-year average from 2005 to 2007, Festival Hydro’s cost was 

$182.00 while the average for the cohort was $208.00. Details of the calculations supporting this 

analysis are included in Appendix D to this Schedule. 

Major projects planned for 2010 include: 

Annual tree trimming program 

Annual system inspections including infared inspections 

Annual switchgear maintenance 

Annual vehicle maintenance


EB-2009-0263 

Exhibit 1 

Tab 2 

Schedule 1 



1 

2 

3 

Typical building maintenance 

The operating and maintenance expenditures are supported by the Asset Management Plan which 

is included in Exhibit 2, Tab 3, Appendix A.


EB-2009-0263 

Exhibit 1 

Tab 2 

Schedule 1 

Appendix D 


APPENDIX D 

COMPARISON OF FESTIVAL HYDRO’S 

2007 OM&A COSTS TO 

“Mid Size Southern Medium-High Undergrounding” 

COHORT GROUPING


EB-2009-0263 

Exhibit 1 

Tab 2 

Schedule 1 

Appendix D 



SUMMARY OF THE APPLICATION 

Comparison of Festival Hydro Inc. 

OM&A Costs to “Mid Size Southern Medium-High Undergrounding” 

Cohort Grouping 

Cohort Groupings 

By Distribution Company 

Total OM&A 

2005-2007 

3 Year Avg. 2007 

E.L.K. Energy Inc. $ 155.00 $ 182.00 

Wasaga Distribution Inc. $ 157.00 $ 159.00 

Chatam-Kent Hydro Inc. $ 162.00 $ 164.00 

Peterborough Distribution Incorporated $ 181.00 $ 192.00 

Festival Hydro Inc. $ 182.00 $ 185.00 

Kingston Electricity Distribution Limited $ 189.00 $ 182.00 

Westario Power Inc. $ 203.00 $ 196.00 

COLLUS Power Corp. $ 211.00 $ 225.00 

St. Thomas Energy Inc. $ 216.00 $ 214.00 

Essex Powerlines Corporation $ 221.00 $ 206.00 

Woodstock Hydro Services Inc. $ 223.00 $ 228.00 

Niagara Falls Hydro Inc. $ 247.00 $ 255.00 

Bluewater Power Distribution Company $ 261.00 $ 256.00 

Erie Thames Powerline Corporation $ 329.00 $ 356.00 

Average for Cohort Group $ 208.00 $ 214.00 

SOURCE: 

Comparison of Ontario Electricity Distributors Costs [EB-2006-0268], updated with 2007 Data 

Issued June 25, 2008.


EB-2009-0263 

Exhibit 1 

Tab 2 

Schedule 2 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

BUDGET DIRECTIVES: 

Festival Hydro compiles budget information for the three major components of the budgeting 

process: revenue forecasts, operating and maintenance expense forecast and capital budget 

forecast. This budget information is compiled for both the 2009 Bridge Year and the 2010 Test 

Year. 

Revenue Forecast 

Festival Hydro's energy sales and revenue forecast model was updated to reflect more recent 

information. This model was then used to prepare the revenues sales and throughput volume and 

revenue forecast at existing rates for fiscal 2009 and 2010. The forecast is weather normalized 

as outlined in Exhibit 3, Tab 2, Schedule 1 using a three-step process. First, a total system 

weather normalized purchased energy forecast is developed based on a multifactor regression 

model that incorporates historical load, weather (heating degree days, cooling degree days), local 

population growth, and Province of Ontario economic data. Second, the weather normalized 

purchased energy forecast is adjusted by a historical loss factor to produce a weather normalized 

billed energy forecast. Finally, the forecast of billed energy by rate class is developed based on a 

forecast of customer numbers, using company knowledge of local economic conditions, 

residential development opportunities and status of specific key customers where applicable, and 

historical usage patterns per customer. 

Operating Maintenance and Administration (“OM&A”) Expense Forecast 

The OM&A expenses for the 2009 Bridge Year and the 2010 Test Year have been based on an 

in-depth review of operating priorities and requirements and is strongly influenced by prior year 

experience. Each item is reviewed account by account for each of the forecast years with 

indirect costs allocated to direct costs for budget presentation.


EB-2009-0263 

Exhibit 1 

Tab 2 

Schedule 2 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

Capital Budget 

The Capital Budget for 2009 and 2010 is established based upon Festival Hydro’s need to ensure 

adequate capital is available to provide a safe, reliable and efficient distribution system on a 

sustainable basis as well as meet the immediate requirements of current and future customers. 

All proposed capital projects are assessed within the framework of its capital budget priority and 

are outlined in Exhibit 2, Tab 3, and Schedule 1 (Capital Project Description). 

Economic Assumptions Used 

In the third quarter of 2008, economic growth came to an abrupt halt as the economy of Ontario, 

Canada, the United States and several foreign countries faltered. In Ontario, the manufacturing 

sector, and in particular the automotive sector, suffered a tremendous slow down as car sales hit 

all time lows and unemployment skyrocketed. Festival Hydro, as like all other LDCs, has been 

negatively impacted with this economic downturn at the end of 2008 and into 2009. 

13 

14 

15 

16 

17 

18 

19 

When preparing our forecast for the bridge year (2009) and test year (2010), Festival Hydro used 

the Government of Ontario’s Budget 2009 Fiscal Review (released the last week of March 2009) 

as a guide. In this report they predict Ontario’s GDP to shrink by 2.5% in 2009 followed by 

growth of 2.3% in 2010. It is our belief that the Ontario GDP factors are a fair representation for 

the City of Stratford and surrounding territory. The City of Stratford is vulnerable with 

automotive related manufacturing and a tourist industry, both sectors which are currently 

suffering from the economic slowdown. 

20 

21 

22 

The other economic assumption we used is that interest rates will remain very low and stable. 

This is based on a July 21, 2009 release from Marc Carney the Bank of Canada who stated that 

he expects bank prime will remain at .25% until at least mid 2010. 

23


EB-2009-0263 

Exhibit 1 

Tab 2 

Schedule 2 



1 

2 

Revenue and economic forecasts were reviewed and approved by Senior Management on July 

24, 2009. 

3 

4 

5 

6 

The 2010 capital budget was presented and approved by the FHI Board of Directors in January, 

2009. A revised capital budget as well as a preliminary OM&A budget for 2010 was presented 

and approved by the FHI Board of Directors in May, 2009. The overall rate impact of the 

proposed budget was also reviewed by the FHI Board in May, 2009.


EB-2009-0263 

Exhibit 1 

Tab 2 

Schedule 3 



1 

2 

CHANGES IN METHODOLOGY: 

Festival Hydro is not requesting any changes in methodology in the current proceeding.


EB-2009-0263 

Exhibit 1 

Tab 2 

Schedule 4 



1 

2 

Calculation of Revenue Deficiency or Surplus 

2010 Test Existing 

Rates 

2010 Test 

Proposed Rates 

Revenue 

Suff/ Def From Below. $979,467 

Distribution Revenue $8,872,663 $8,872,663 

Other Operating Revenue (Net) $659,450 $659,450 

Total Revenue $9,532,113 $10,511,581 

Distribution Costs 

Operation, Maintenance, and Administration $3,968,347 $3,968,347 

Depreciation & Amortization $2,655,496 $2,655,496 

Taxes $50,317 $50,317 

Interest- Deemed Interest $1,660,572 $1,660,572 

Total Costs and Expenses $8,334,732 $8,334,732 

Utility Income Before Income Taxes $1,197,382 $2,176,849 

Net Adjustments per 2010 Pils $662,491 $662,491 

Taxable Income $1,859,872 $2,839,340 

Tax Rate 32.0% 32.0% 

Income Tax $595,159 $908,589 

Utility Income $602,222 $1,268,260 

Rate Base $39,583,651 $39,583,651 

Equity 40.00% 40.00% 

Equity Component Rate Base $15,833,460 $15,833,460 

Income / Equity Rate Base % 3.80% 8.01% 

Target Return -Equity on Rate Base 8.01% 8.01% 

3 

4 

Return- Equity on Rate Base $1,268,260 $1,268,260 

Revenue Deficiency $666,038 

Revenue Deficiency (Gross-up) $979,467


EB-2009-0263 

Exhibit 1 

Tab 2 

Schedule 5 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

CAUSES OF REVENUE DEFICIENCY: 

Festival Hydro’s net revenue deficiency is calculated as $666,038 and when grossed up for PILs, 

the revenue deficiency is $979,467. Festival Hydro’s calculation of its 2010 revenue deficiency 

is provided in Exhibit 1, Tab 2, Schedule 4 and Exhibit 6, Tab 1, Schedule 1. 

The revenue deficiency is primarily the result of: 

‣ Increases in OM&A costs including depreciation expense. In addition, Festival Hydro 

has upgraded its Regulatory and Engineering staff with new hires that have different skill 

sets than those employees that have retired from Festival Hydro. Also, the addition of a 

Conservation and Demand analyst in 2010 is necessary to meet the work load associated 

with conversation programs initiated by the Ontario Power Authority (“OPA”). OM&A 

cost are discussed in further detail in Exhibit 4; and 

‣ Projected increases in investments in gross assets and, as a result, the rate base on which 

the rate of return is based as discussed further in Exhibit 2, Tab 1 (Rate Base Overview) 

and Tab 2 (Gross Assets – Property, Plant & Equipment). 

‣ Projected costs related to the implementation of International Financial Reporting 

Standards 

‣ Projected costs related to the 2010 Rate Rebasing project 

Festival Hydro is committed to meeting its corporate mission and goals of providing a safe and 

reliable distribution through prudent investments in capital assets and investing in training and 

education of staff required to meet the future needs of its customers.


EB-2009-0263 

Exhibit 1 

Tab 2 

Schedule 5 

Appendix E 


APPENDIX E 

Revenue Requirement Work form


EB-2009-0263 

Exhibit 1 

Tab 2 

Schedule 5 

Appendix E 



REVENUE REQUIREMENT WORK FORM 

Name of LDC: Festival Hydro Inc. 

(1) 

File Number: 2002-0513 

Rate Year: 2010 Version: 1.0 

Table of Content 

Sheet 

A 

Name 

Data Input Sheet 

1 Rate Base 

2 Utility Income 

3 Taxes/PILS 

4 Capitalization/Cost of Capital 

5 Revenue Sufficiency/Deficiency 

6 Revenue Requirement 

7 Bill Impacts 

Notes: 

(1) Pale green cells represent inputs 

(2) Please note that this model uses MACROS. Before starting, please ensure that macros have been 

enabled. 

1 

2 

Copyright 

This Revenue Requirement Work Form Model is protected by copyright and is being made available to you solely for 

the purpose of preparing or reviewing your draft rate order. You may use and copy this model for that purpose, and 

provide a copy of this model to any person that is advising or assisting you in that regard. Except as indicated above, 

any copying, reproduction, publication, sale, adaptation, translation, modification, reverse engineering or other use or 

dissemination of this model without the express written consent of the Ontario Energy Board is prohibited. If you 

provide a copy of this model to a person that is advising or assisting you in preparing or reviewing your draft rate 

order, you must ensure that the person understands and agrees to the restrictions noted above. 

3


EB-2009-0263 

Exhibit 1 

Tab 2 

Schedule 5 

Appendix E 






Rate Year: 2010 

Data Input 

(1) 

Application Adjustments Per Board Decision 

1 Rate Base 

Gross Fixed Assets (average) $75,147,744 (4) $75,147,744 

Accumulated Depreciation (average) ($42,899,817) (5) ($42,899,817) 

Allowance for Working Capital: 

Controllable Expenses $4,018,664 (6) $4,018,664 

Cost of Power $44,886,161 $44,886,161 

Working Capital Rate (%) 15.00% 15.00% 

2 Utility Income 

Operating Revenues: 

Distribution Revenue at Current Rates $8,872,663 

Distribution Revenue at Proposed Rates $9,852,131 

Other Revenue: 

Specific Service Charges $207,660 

Late Payment Charges $128,414 

Other Distribution Revenue $186,489 

Other Income and Deductions $136,887 

Operating Expenses: 

OM+A Expenses $3,968,347 $3,968,347 

Depreciation/Amortization $2,655,496 $2,655,496 

Property taxes $30,000 $30,000 

Capital taxes $20,317 

Other expenses $ - $0 

3 Taxes/PILs 

Taxable Income: 

Adjustments required to arrive at taxable income $662,491 (3) 

Utility Income Taxes and Rates: 

Income taxes (not grossed up) $617,840 

Income taxes (grossed up) $908,589 

Capital Taxes $20,317 

Federal tax (%) 18.00% 

Provincial tax (%) 14.00% 

Income Tax Credits $ - 

4 Capitalization/Cost of Capital 

Capital Structure: 

Long-term debt Capitalization Ratio (%) 56.0% 

Short-term debt Capitalization Ratio (%) 4.0% (2) (2) 

Common Equity Capitalization Ratio (%) 40.0% 

Prefered Shares Capitalization Ratio (%) 0.0% 


must total 100% 

Cost of Capital 

Long-term debt Cost Rate (%) 7.40% 

Short-term debt Cost Rate (%) 1.33% 

Common Equity Cost Rate (%) 8.01% 

Prefered Shares Cost Rate (%) 0.00% 

Notes: 

This input sheet provides all inputs needed to complete sheets 1 through 6 (Rate Base through Revenue Requirement), except for 

Notes that the utility may wish to use to support the components. Notes should be put on the applicable pages to understand the 

context of each such note. 

(1) All inputs are in dollars ($) except where inputs are individually identified as percentages (%) 

(2) 4.0% unless an Applicant has proposed or been approved for another amount. 

(3) Net of addbacks and deductions to arrive at taxable income. 

(4) Average of Gross Fixed Assets at beginning and end of the Test Year 

(5) Average of Accumulated Depreciation at the beginning and end of the Test Year. Enter as a negative amount. 

1 

2 

3


EB-2009-0263 

Exhibit 1 

Tab 2 

Schedule 5 

Appendix E 







Line 

No. 

Rate Base 

Particulars Application Adjustments 

Per Board 

Decision 

1 Gross Fixed Assets (average) (3) $75,147,744 $ - $75,147,744 

2 Accumulated Depreciation (average) (3) ($42,899,817) $ - ($42,899,817) 

3 Net Fixed Assets (average) (3) $32,247,927 $ - $32,247,927 

4 Allowance for Working Capital (1) $7,335,724 $ - $7,335,724 

5 

Total Rate Base 

$39,583,651 $ - $39,583,651 

(1) Allowance for Working Capital - Derivation 

6 Controllable Expenses $4,018,664 $ - $4,018,664 

7 Cost of Power $44,886,161 $ - $44,886,161 

8 Working Capital Base $48,904,825 $ - $48,904,825 

9 Working Capital Rate % (2) 15.00% 15.00% 

10 Working Capital Allowance $7,335,724 $ - $7,335,724 

Notes 

(2) 

(3) 

Generally 15%. Some distributors may have a unique rate due as a result of a lead-lag study. 

Average of opening and closing balances for the year. 

1 

2 

3


EB-2009-0263 

Exhibit 1 

Tab 2 

Schedule 5 

Appendix E 







Utility income 

Line 

No. 

Particulars Application Adjustments 

Per Board 

Decision 

Operating Revenues: 

1 Distribution Revenue (at Proposed Rates) $9,852,131 $ - $9,852,131 

2 Other Revenue (1) $659,450 $ - $659,450 

3 Total Operating Revenues 

$10,511,581 $ - $10,511,581 

Operating Expenses: 

4 OM+A Expenses $3,968,347 $ - $3,968,347 

5 Depreciation/Amortization $2,655,496 $ - $2,655,496 

6 Property taxes $30,000 $ - $30,000 

7 Capital taxes $20,317 $ - $20,317 

8 Other expense $ - $ - $ - 

9 Subtotal 

$6,674,159 $ - $6,674,159 

10 Deemed Interest Expense $1,660,572 $ - $1,660,572 

11 Total Expenses (lines 4 to 10) $8,334,732 $ - $8,334,732 

12 Utility income before income taxes 

$2,176,849 

$ - 

$2,176,849 

13 Income taxes (grossed-up) 

14 Utility net income 

$908,589 

$1,268,260 

$ - $908,589 

$ - $1,268,260 

Notes 

(1) Other Revenues / Revenue Offsets 

Specific Service Charges $207,660 $207,660 

Late Payment Charges $128,414 $128,414 

Other Distribution Revenue $186,489 $186,489 

Other Income and Deductions $136,887 $136,887 

Total Revenue Offsets 

$659,450 $659,450 

1


EB-2009-0263 

Exhibit 1 

Tab 2 

Schedule 5 

Appendix E 







Taxes/PILs 

Line 

No. 

Particulars 

Application 

Per Board 

Decision 

Determination of Taxable Income 

1 Utility net income 

$1,268,260 $1,268,260 

2 Adjustments required to arrive at taxable utility income 

$662,491 $662,491 

3 Taxable income 

$1,930,751 $1,930,751 

Calculation of Utility income Taxes 

4 Income taxes $617,840 $617,840 

5 Capital taxes $20,317 $20,317 

6 Total taxes 

$638,157 $638,157 

7 Gross-up of Income Taxes $290,748 $290,748 

8 Grossed-up Income Taxes $908,589 $908,589 

PILs / tax Allowance (Grossed-up Income taxes + 

9 Capital taxes) 

$928,906 $928,906 

10 Other tax Credits $ - $ - 

Tax Rates 

11 Federal tax (%) 18.00% 18.00% 

12 Provincial tax (%) 14.00% 14.00% 

13 Total tax rate (%) 32.00% 32.00% 

Notes 

1


EB-2009-0263 

Exhibit 1 

Tab 2 

Schedule 5 

Appendix E 







Capitalization/Cost of Capital 

Line 

No. 

Particulars Capitalization Ratio Cost Rate Return 


(%) ($) (%) ($) 

Debt 

1 Long-term Debt 56.00% $22,166,845 7.40% $1,639,514 

2 Short-term Debt 4.00% $1,583,346 1.33% $21,059 

3 Total Debt 60.00% $23,750,191 6.99% $1,660,572 

Equity 

4 Common Equity 40.00% $15,833,460 8.01% $1,268,260 

5 Preferred Shares 0.00% $ - 0.00% $ - 

6 Total Equity 40.00% $15,833,460 8.01% $1,268,260 

7 Total 100% $39,583,651 7.40% $2,928,832 

Per Board Decision 

(%) ($) (%) 

Debt 

8 Long-term Debt 56.00% $22,166,845 7.40% $1,639,514 

9 Short-term Debt 4.00% $1,583,346 1.33% $21,059 

10 Total Debt 60.00% $23,750,191 6.99% $1,660,572 

Equity 

11 Common Equity 40.0% $15,833,460 8.01% $1,268,260 

12 Preferred Shares 0.0% $ - 0.00% $ - 

13 Total Equity 40.0% $15,833,460 8.01% $1,268,260 

14 Total 100% $39,583,651 7.40% $2,928,832 

Notes 

(1) 

4.0% unless an Applicant has proposed or been approved for another amount. 

1


EB-2009-0263 

Exhibit 1 

Tab 2 

Schedule 5 

Appendix E 







Revenue Sufficiency/Deficiency 

Per Application 


Line 

No. 

Particulars 

At Current 

Approved Rates 

At Proposed 

Rates 

At Current 

Approved Rates 

At Proposed 

Rates 

1 Revenue Deficiency from Below $979,468 $979,468 

2 Distribution Revenue $8,872,663 $8,872,663 $8,872,663 $8,872,663 

3 Other Operating Revenue Offsets - net $659,450 $659,450 $659,450 $659,450 

4 Total Revenue $9,532,113 $10,511,581 $9,532,113 $10,511,581 

5 Operating Expenses $6,674,159 $6,674,159 $6,674,159 $6,674,159 

6 Deemed Interest Expense $1,660,572 $1,660,572 $1,660,572 $1,660,572 

Total Cost and Expenses $8,334,732 $8,334,732 $8,334,732 $8,334,732 

7 Utility Income Before Income Taxes $1,197,381 $2,176,849 $1,197,381 $2,176,849 

Tax Adjustments to Accounting 

8 Income per 2009 PILs $662,491 $662,491 $662,491 $662,491 

9 Taxable Income $1,859,872 $2,839,340 $1,859,872 $2,839,340 

10 Income Tax Rate 32.00% 32.00% 32.00% 32.00% 

11 Income Tax on Taxable Income $595,159 $908,589 $595,159 $908,589 

12 Income Tax Credits $ - $ - $ - $ - 

13 Utility Net Income $602,222 $1,268,260 $602,222 $1,268,260 

14 Utility Rate Base $39,583,651 $39,583,651 $39,583,651 $39,583,651 

Deemed Equity Portion of Rate Base $15,833,460 $15,833,460 $15,833,460 $15,833,460 

15 Income/Equity Rate Base (%) 3.80% 8.01% 3.80% 8.01% 

16 Target Return - Equity on Rate Base 8.01% 8.01% 8.01% 8.01% 

Sufficiency/Deficiency in Return on Equity -4.21% 0.00% -4.21% 0.00% 

17 Indicated Rate of Return 5.72% 7.40% 5.72% 7.40% 

18 Requested Rate of Return on Rate Base 7.40% 7.40% 7.40% 7.40% 

19 Sufficiency/Deficiency in Rate of Return -1.68% 0.00% -1.68% 0.00% 

20 Target Return on Equity $1,268,260 $1,268,260 $1,268,260 $1,268,260 

21 Revenue Sufficiency/Deficiency $666,038 $0 $666,038 $0 

22 Gross Revenue Sufficiency/Deficiency $979,468 (1) $979,468 (1) 

Notes: 

(1) 

Revenue Sufficiency/Deficiency divided by (1 - Tax Rate) 

1


EB-2009-0263 

Exhibit 1 

Tab 2 

Schedule 5 

Appendix E 







Revenue Requirement 

Line 

No. 

Particulars 



1 OM&A Expenses $3,968,347 

2 Amortization/Depreciation $2,655,496 

3 Property Taxes $30,000 

4 Capital Taxes $20,317 

5 Income Taxes (Grossed up) $908,589 

6 Other Expenses $ - 

7 Return 

Deemed Interest Expense $1,660,572 

Return on Deemed Equity $1,268,260 

$3,968,347 

$2,655,496 

$30,000 

$20,317 

$908,589 

$ - 

$1,660,572 

$1,268,260 

8 

Distribution Revenue Requirement 

before Revenues $10,511,581 

$10,511,581 

9 Distribution revenue $9,852,131 

10 Other revenue $659,450 

$9,852,131 

$659,450 

11 Total revenue 

$10,511,581 

$10,511,581 

12 

Difference (Total Revenue Less 

Distribution Revenue Requirement 

before Revenues) $0 (1) $0 (1) 

Notes 

(1) Line 11 - Line 8 

1 

2 

3


EB-2009-0263 

Exhibit 1 

Tab 2 

Schedule 5 

Appendix E 







Selected Delivery Charge and Bill Impacts 

Per Draft Rate Order 

Monthly Delivery Charge 

Total Bill 

Per Draft Change 

Per Draft Change 

Current Rate Order $ % Current Rate Order $ % 

Residential 

800 kWh/month 

$ 

35.71 

$ 37.28 $ 1.57 

4.4% 

$ 

98.38 

$ 

100.18 

$ 

1.80 

1.8% 

GS < 50kW 

2000 kWh/month 

$ 75.40 $ 76.69 

$ 

1.29 

1.7% 

$ 

144.23 

$ 

145.66 

$ 

1.43 

1.0% 

Notes: 

1 

2


EB-2009-0263 

Exhibit 1 

Tab 3 

Schedule 1 



1 

2 

3 

FINANCIAL STATEMENTS – 2007 and 2008: 

Festival Hydro’s Audited 2007 and 2008 Financial Statements accompany this Schedule as 

Appendix F.


EB-2009-0263 

Exhibit 1 

Tab 3 

Schedule 1 

Exhibit F 


APPENDIX F 

COPY OF AUDITED FINANCIAL STATEMENTS FOR 2007 and 2008

1 


EB-2009-0263 

Exhibit 1 

Tab 3 

Schedule 1 

Exhibit F 



1 


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EB-2009-0263 

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EB-2009-0263 

Exhibit 1 

Tab 3 

Schedule 2 



1 

2 

3 

PRO FORMA FINANCIAL STATEMENTS - 2009 AND 2010: 

The Festival Hydro Pro Forma Statements for the 2009 Bridge Year and the 2010 Test Year 

accompany this Schedule as Appendix G and Appendix H respectively.


EB-2009-0263 

Exhibit 1 

Tab 3 

Schedule 2 

Appendix G 


APPENDIX G 

COPY OF FESTIVAL HYDRO INC. 

2009 PRO FORMA STATEMENTS


EB-2009-0263 

Exhibit 1 

Tab 3 

Schedule 2 

Appendix G 



Festival Hydro Inc 

License Number EB-2002-0815, File Number 


2009 BALANCE SHEET 

Account Description 

Total 

1050-Current Assets 

1005-Cash 3,423,148 

1010-Cash Advances and Working Funds 1,060 

1020-Interest Special Deposits 0 

1040-Other Special Deposits 

1100-Customer Accounts Receivable 1,844,813 

1102-Accounts Receivable - Services 371,496 

1104-Accounts Receivable - Recoverable Work 227,429 

1105-Accounts Receivable - Merchandise, Jobbing, etc. 0 

1110-Other Accounts Receivable 28,045 

1120-Accrued Utility Revenues 5,768,017 

1130-Accumulated Provision for Uncollectible Accounts--Credit (109,580) 

1140-Interest and Dividends Receivable 2,600 

1150-Rents Receivable 0 

1180-Prepayments 152,783 

1200-Accounts Receivable from Associated Companies 0 

1210-Notes Receivable from Associated Companies 0 

1050-Current Assets Total 11,709,811 

1100-Inventory 

1330-Plant Materials and Operating Supplies 107,957 

1305-Fuel Stock 0 

1350-Other Materials and Supplies 0 

1100-Inventory Total 107,957 

1150-Non-Current Assets 

1405-Long Term Investments in Non-Associated Companies 2 

1410-Other Special or Collateral Funds 0 

1460-Other Non-Current Assets 33,182 

1150-Non-Current Assets Total 33,184 

1200-Other Assets and Deferred Charges 

1508-Other Regulatory Assets 374,086 

1518-RCVARetail (78,111) 

1525-Miscellaneous Deferred Debits 1,145 

1548-RCVASTR 33,287 

1550-LV Variance Account 102,825 

1555-Smart Meters Capital Variance Account 650,516 

1556-Smart Meters OM&A Variance Account 0 

1562-Deferred Payments in Lieu of Taxes 74,757


EB-2009-0263 

Exhibit 1 

Tab 3 

Schedule 2 

Appendix G 



1565-Conservation and Demand Management Expenditures and Recoveries (670,623) 

1566-CDM Contra Account 670,624 

1570-Qualifying Transition Costs 0 

1571-Pre-market Opening Energy Variance 0 

1572-Extraordinary Event Costs 0 

1580-RSVAWMS (1,687,372) 

1582-RSVAONE-TIME 40,162 

1584-RSVANW (1,183,838) 

1586-RSVACN (1,075,098) 

1588-RSVAPOWER 936,628 

1590-Recovery of Regulatory Asset Balances 42,249 

1200-Other Assets and Deferred Charges Total (1,768,763) 

1450-Distribution Plant 

1805-Land 339,323 

1806-Land Rights 0 

1808-Buildings and Fixtures 1,684,098 

1810-Leasehold Improvements 0 

1815-Transformer Station Equipment - Normally Primary above 50 kV 

1820-Distribution Station Equipment - Normally Primary below 50 kV 1,745,896 

1825-Storage Battery Equipment 0 

1830-Poles, Towers and Fixtures 10,047,075 

1835-Overhead Conductors and Devices 12,389,305 

1840-Underground Conduit 6,222,452 

1845-Underground Conductors and Devices 15,450,319 

1850-Line Transformers 14,528,725 

1855-Services 4,820,275 

1860-Meters 3,504,828 

1450-Distribution Plant Total 70,732,294 

1500-General Plant 

1905-Land 0 

1906-Land Rights 21,798 

1908-Buildings and Fixtures 553,746 

1915-Office Furniture and Equipment 331,792 

1920-Computer Equipment - Hardware 928,757 

1925-Computer Software 479,162 

1930-Transportation Equipment 2,917,270 

1935-Stores Equipment 36,199 

1940-Tools, Shop and Garage Equipment 756,644 

1945-Measurement and Testing Equipment 13,413 

1950-Power Operated Equipment 0 

1955-Communication Equipment 106,528


EB-2009-0263 

Exhibit 1 

Tab 3 

Schedule 2 

Appendix G 



1960-Miscellaneous Equipment 7,842 

1970-Load Management Controls - Customer Premises 117,417 

1975-Load Management Controls - Utility Prem. 127,702 

1980-System Supervisory Equipment 277,006 

1995-Contributions and Grants - Credit (3,938,326) 

1500-General Plant Total 2,736,950 

1550-Other Capital Assets 

1606-Organization Costs 15,648 

2055-Construction Work in Progress--Electric (28,201) 

2060-Electric Plant Acquisition Adjustment 543,560 

2070-Other Utility Plant 0 

1550-Other Capital Assets Total 531,007 

1600-Accumulated Amortization 

2105-Accum. Amortization of Electric Utility Plant - Property, Plant, & Equipment (41,462,401) 

2160-Accumulated Amortization of Other Utility Plant 0 

1600-Accumulated Amortization Total (41,462,401) 

Total Assets 42,620,039 

1650-Current Liabilities 

2205-Accounts Payable 5,920,377 

2208-Customer Credit Balances 378,031 

2210-Current Portion of Customer Deposits 366,513 

2220-Miscellaneous Current and Accrued Liabilities 340,714 

2240-Accounts Payable to Associated Companies 40,292 

2250-Debt Retirement Charges( DRC) Payable 15,600,000 

2290-Commodity Taxes 208,864 

2292-Payroll Deductions / Expenses Payable 94,161 

2294-Accrual for Taxes, Payments in Lieu of Taxes, Etc. (213,608) 

2296-Future Income Taxes - Current 0 

1650-Current Liabilities Total 22,735,344 

1700-Non-Current Liabilities 

2306-Employee Future Benefits 1,290,004 

2310-Vested Sick Leave Liability 

2320-Other Miscellaneous Non-Current Liabilities 589,710 

2335-Long Term Customer Deposits 

2350-Future Income Tax - Non-Current (2,255,000) 

2405-Other Regulatory Liabilities (37,369) 

2425-Other Deferred Credits 0 

1700-Non-Current Liabilities Total (412,655)


EB-2009-0263 

Exhibit 1 

Tab 3 

Schedule 2 

Appendix G 



1800-Long-Term Debt 

2550-Advances from Associated Companies 0 

1800-Long-Term Debt Total 0 

1850-Shareholders' Equity 

3005-Common Shares Issued 9,468,388 

3010-Class A Special Shares 6,100,000 

3030-Miscellaneous Paid-In Capital 0 

3045-Unappropriated Retained Earnings 3,352,056 

3046-Balance Transferred From Income 1,376,906 

3049-Dividends Payable-Common Shares 0 

1850-Shareholders' Equity Total 20,297,350 

Total Liabilities & Shareholder's Equity 42,620,039 

Balance Sheet Total (0)




EB-2009-0263 

Exhibit 1 

Tab 3 

Schedule 2 

Appendix G 




2009 STATEMENT OF INCOME AND RETAINED EARNINGS 


Total 

3000-Sales of Electricity 

4006-Residential Energy Sales (6,579,477) 

4010-Commercial Energy Sales 0 

4015-Industrial Energy Sales (17,148,949) 

4020-Energy Sales to Large Users (4,158,778) 

4025-Street Lighting Energy Sales (88,515) 

4030-Sentinel Lighting Energy Sales (10,982) 

4035-General Energy Sales 

4050-Revenue Adjustment 59,562 

4055-Energy Sales for Resale (8,691,502) 

4060-Interdepartmental Energy Sales 

4062-Billed WMS (3,919,980) 

4066-Billed NW (3,119,897) 

4068-Billed CN (2,400,715) 

4075-Billed LV (88,883) 

3000-Sales of Electricity Total (46,148,115) 

3050-Revenues From Services - Distirbution 

4080-Distribution Services Revenue (9,050,048) 

4082-Retail Services Revenues (26,772) 

4084-Service Transaction Requests (STR) Revenues (987) 

4090-Electric Services Incidental to Energy Sales 

3050-Revenues From Services - Distirbution Total (9,077,807) 

3100-Other Operating Revenues 

4210-Rent from Electric Property (148,881) 

4220-Other Electric Revenues (5,880) 

4225-Late Payment Charges (125,527) 

4230-Sales of Water and Water Power 

4235-Miscellaneous Service Revenues (202,991) 

3100-Other Operating Revenues Total (483,279) 

3150-Other Income & Deductions 

4375 - Revenue from non-utility operations (690,042) 

4330-Costs and Expenses of Merchandising, Jobbing, Etc. 0 

4355-Gain on Disposition of Utility and Other Property (18,250) 

4380-Expenses of Non-Utility Operations 617,281 

4390-Miscellaneous Non-Operating Income (31,864) 

4398-Foreign Exchange Gains and Losses, Including Amortization 0 

3150-Other Income & Deductions Total (122,875)


EB-2009-0263 

Exhibit 1 

Tab 3 

Schedule 2 

Appendix G 



3200-Investment Income 

4405-Interest and Dividend Income (25,200) 

3200-Investment Income Total (25,200) 

3350-Power Supply Expenses 

4705-Power Purchased 36,618,642 

4708-Charges-WMS 3,919,980 

4710-Cost of Power Adjustments 

4714-Charges-NW 3,119,897 

4715-System Control and Load Dispatching 

4716-Charges-CN 2,400,715 

4730-Rural Rate Assistance Expense 0 

4750-Charges - LV 88,883 

3350-Power Supply Expenses Total 46,148,116 

3500-Distribution Expenses - Operation 

5005-Operation Supervision and Engineering 0 

5010-Load Dispatching 36,706 

5012-Station Buildings and Fixtures Expense 36,326 

5014-Transformer Station Equipment - Operation Labour 0 

5015-Transformer Station Equipment - Operation Supplies and Expenses 0 

5016-Distribution Station Equipment - Operation Labour 2,182 

5017-Distribution Station Equipment - Operation Supplies and Expenses 9 

5020-Overhead Distribution Lines and Feeders - Operation Labour 16,891 

5025-Overhead Distribution Lines & Feeders - Operation Supplies and Expenses 36,355 

5030-Overhead Subtransmission Feeders - Operation 0 

5035-Overhead Distribution Transformers- Operation 14,243 

5040-Underground Distribution Lines and Feeders - Operation Labour 9,095 

5045-Underground Distribution Lines & Feeders - Operation Supplies & Expenses 1,590 

5050-Underground Subtransmission Feeders - Operations 0 

5055-Underground Distribution Transformers - Operation 13,394 

5065-Meter Expense 248,332 

5070-Customer Premises - Operation Labour 205,632 

5075-Customer Premises - Materials and Expenses 1,898 

5085-Miscellaneous Distribution Expense 9,401 

5095-Overhead Distribution Lines and Feeders - Rental Paid 

5096-Other Rent 8,737 

3500-Distribution Expenses - Operation Total 640,791


EB-2009-0263 

Exhibit 1 

Tab 3 

Schedule 2 

Appendix G 



3550-Distribution Expenses - Maintenance 

5105-Maintenance Supervision and Engineering 0 

5110-Maintenance of Buildings and Fixtures - Distribution Stations 2,246 

5114-Maintenance of Distribution Station Equipment 0 

5120-Maintenance of Poles, Towers and Fixtures 19,671 

5125-Maintenance of Overhead Conductors and Devices 101,807 

5130-Maintenance of Overhead Services 198,083 

5135-Overhead Distribution Lines and Feeders - Right of Way 166,077 

5145-Maintenance of Underground Conduit 44,999 

5150-Maintenance of Underground Conductors and Devices 98,552 

5155-Maintenance of Underground Services 85,817 

5160-Maintenance of Line Transformers 23,848 

5175-Maintenance of Meters 25,235 

3550-Distribution Expenses - Maintenance Total 766,335 

3650-Billing and Collecting 

5305-Supervision 23,661 

5310-Meter Reading Expense 103,296 

5315-Customer Billing 383,914 

5320-Collecting 157,598 

5325-Collecting Cash over and Short 17 

5330-Collection Charges 0 

5335-Bad Debt Expense 146,037 

5340-Miscellaneous Customer Accounts Expenses 208,269 

3650-Billing and Collecting Total 1,022,792 

3700-Community Relations 

5405-Supervision 176 

5410-Community Relations - Sundry 904 

5415-Energy Conservation 10,460 

5420-Community Safety Program 10,834 

5510-Demonstrating and Selling Expense 0 

5515-Advertising Expense 0 

5520-Miscellaneous Sales Expense 0 

3700-Community Relations Total 22,374


EB-2009-0263 

Exhibit 1 

Tab 3 

Schedule 2 

Appendix G 



3800-Administrative and General Expenses 

5605-Executive Salaries and Expenses 458,625 

5610-Management Salaries and Expenses 0 

5615-General Administrative Salaries and Expenses 271,877 

5620-Office Supplies and Expenses 91,425 

5625-Administrative Expense Transferred Credit 0 

5630-Outside Services Employed 166,287 

5635-Property Insurance 15,385 

5640-Injuries and Damages 56,088 

5645-Employee Pensions and Benefits 99,009 

5655-Regulatory Expenses 60,360 

5660-General Advertising Expenses 0 

5665-Miscellaneous General Expenses 43,893 

5670-Rent 9,418 

5675-Maintenance of General Plant 138,255 

3800-Administrative and General Expenses Total 1,410,622 

3850-Amortization Expense 

5705-Amortization Expense - Property, Plant, and Equipment 2,507,719 

5725-Misc. Amortization - Org. Costs 30,061 

3850-Amortization Expense Total 2,537,780 

3900-Interest Expense 

6005-Interest on Long Term Debt 0 

6030-Interest on Debt to Associated Companies 1,135,961 

6035-Other Interest Expense 42,852 

6042-Allowance For Other Funds Used During Construction 

3900-Interest Expense Total 1,178,813 

3950-Taxes Other Than Income Taxes 

6105-Taxes Other Than Income Taxes 89,490 

3950-Taxes Other Than Income Taxes Total 89,490 

4000-Income Taxes 

6110-Income Taxes 835,000 

6115-Provision for Future Income Taxes (172,000) 

4000-Income Taxes Total 663,000 

4100-Extraordinary & Other Items 

6205-Donations 258 

6310-Extraordinary Deductions 

4100-Extraordinary & Other Items Total 258 

Net Income (1,376,906)


EB-2009-0263 

Exhibit 1 

Tab 3 

Schedule 2 

Appendix H 


APPENDIX H 

COPY OF FESTIVAL HYDRO INC. 

2010 PRO FORMA STATEMENTS


EB-2009-0263 

Exhibit 1 

Tab 3 

Schedule 2 

Appendix H 






2010 BALANCE SHEET 


Total 

1050-Current Assets 

1005-Cash 3,658,790 

1010-Cash Advances and Working Funds 1,060 

1020-Interest Special Deposits 0 

1040-Other Special Deposits 

1100-Customer Accounts Receivable 1,812,528 

1102-Accounts Receivable - Services 380,041 

1104-Accounts Receivable - Recoverable Work 232,660 

1105-Accounts Receivable - Merchandise, Jobbing, etc. 0 

1110-Other Accounts Receivable 28,690 

1120-Accrued Utility Revenues 5,667,077 

1130-Accumulated Provision for Uncollectible Accounts--Credit (109,580) 

1140-Interest and Dividends Receivable 2,600 

1150-Rents Receivable 0 

1180-Prepayments 156,297 

1200-Accounts Receivable from Associated Companies 0 

1210-Notes Receivable from Associated Companies 0 

1050-Current Assets Total 11,830,163 

1100-Inventory 

1330-Plant Materials and Operating Supplies 110,440 

1305-Fuel Stock 0 

1350-Other Materials and Supplies 0 

1100-Inventory Total 110,440 

1150-Non-Current Assets 

1405-Long Term Investments in Non-Associated Companies 2 

1410-Other Special or Collateral Funds 0 

1460-Other Non-Current Assets 16,591 

1150-Non-Current Assets Total 16,593 

1200-Other Assets and Deferred Charges 

1508-Other Regulatory Assets 295,385 

1518-RCVARetail (65,574) 

1525-Miscellaneous Deferred Debits 1,145 

1548-RCVASTR 27,566 

1550-LV Variance Account 86,588 

1555-Smart Meters Capital Variance Account 1,916,516 

1556-Smart Meters OM&A Variance Account 150,000 

1562-Deferred Payments in Lieu of Taxes 74,757


EB-2009-0263 

Exhibit 1 

Tab 3 

Schedule 2 

Appendix H 



1565-Conservation and Demand Management Expenditures and Recoveries (670,623) 

1566-CDM Contra Account 670,624 

1570-Qualifying Transition Costs 0 

1571-Pre-market Opening Energy Variance 0 

1572-Extraordinary Event Costs 0 

1580-RSVAWMS (1,376,191) 

1582-RSVAONE-TIME 31,729 

1584-RSVANW (978,107) 

1586-RSVACN (859,590) 

1588-RSVAPOWER 749,872 

1590-Recovery of Regulatory Asset Balances 42,249 

1200-Other Assets and Deferred Charges Total 96,346 

1450-Distribution Plant 

1805-Land 339,323 

1806-Land Rights 0 

1808-Buildings and Fixtures 1,684,098 

1810-Leasehold Improvements 0 


1820-Distribution Station Equipment - Normally Primary below 50 kV 1,745,896 

1825-Storage Battery Equipment 0 

1830-Poles, Towers and Fixtures 10,787,575 

1835-Overhead Conductors and Devices 13,219,305 

1840-Underground Conduit 6,481,952 

1845-Underground Conductors and Devices 15,971,319 

1850-Line Transformers 15,179,725 

1855-Services 5,040,275 

1860-Meters 3,524,828 

1450-Distribution Plant Total 73,974,294 

1500-General Plant 

1905-Land 0 

1906-Land Rights 21,798 

1908-Buildings and Fixtures 653,746 

1915-Office Furniture and Equipment 331,792 

1920-Computer Equipment - Hardware 953,757 

1925-Computer Software 504,162 

1930-Transportation Equipment 3,217,270 

1935-Stores Equipment 36,199 

1940-Tools, Shop and Garage Equipment 791,644 

1945-Measurement and Testing Equipment 13,413 

1950-Power Operated Equipment 0 

1955-Communication Equipment 106,528 

1960-Miscellaneous Equipment 7,842 

1970-Load Management Controls - Customer Premises 117,417 

1975-Load Management Controls - Utility Prem. 127,702 

1980-System Supervisory Equipment 297,006 

1995-Contributions and Grants - Credit (4,328,326) 

1500-General Plant Total 2,851,950

1550-Other Capital Assets 


EB-2009-0263 

Exhibit 1 

Tab 3 

Schedule 2 

Appendix H 



1606-Organization Costs 0 

2055-Construction Work in Progress--Electric (28,201) 

2060-Electric Plant Acquisition Adjustment 543,560 

2070-Other Utility Plant 0 

1550-Other Capital Assets Total 515,359 

1600-Accumulated Amortization 

2105-Accum. Amortization of Electric Utility Plant - Property, Plant, & Equipment (44,337,232) 

2160-Accumulated Amortization of Other Utility Plant 0 

1600-Accumulated Amortization Total (44,337,232) 

Total Assets 45,057,913 

1650-Current Liabilities 

2205-Accounts Payable 5,816,771 

2208-Customer Credit Balances 378,031 

2210-Current Portion of Customer Deposits 360,099 

2220-Miscellaneous Current and Accrued Liabilities 348,551 

2240-Accounts Payable to Associated Companies 41,218 

2250-Debt Retirement Charges( DRC) Payable 15,600,000 

2290-Commodity Taxes 205,209 

2292-Payroll Deductions / Expenses Payable 96,985 

2294-Accrual for Taxes, Payments in Lieu of Taxes, Etc. (213,608) 

2296-Future Income Taxes - Current 0 

1650-Current Liabilities Total 22,633,256 

1700-Non-Current Liabilities 

2306-Employee Future Benefits 1,294,401 

2310-Vested Sick Leave Liability 

2320-Other Miscellaneous Non-Current Liabilities 579,390 

2335-Long Term Customer Deposits 

2350-Future Income Tax - Non-Current (2,412,000) 

2405-Other Regulatory Liabilities (45,209) 

2425-Other Deferred Credits 2,500,000 

1700-Non-Current Liabilities Total 1,916,582


EB-2009-0263 

Exhibit 1 

Tab 3 

Schedule 2 

Appendix H 



1800-Long-Term Debt 

2550-Advances from Associated Companies 0 

1800-Long-Term Debt Total 0 

1850-Shareholders' Equity 

3005-Common Shares Issued 9,468,388 

3010-Class A Special Shares 6,100,000 

3030-Miscellaneous Paid-In Capital 0 

3045-Unappropriated Retained Earnings 3,718,432 

3046-Balance Transferred From Income 1,221,254 

3049-Dividends Payable-Common Shares 0 

1850-Shareholders' Equity Total 20,508,075 

Total Liabilities & Shareholder's Equity 45,057,913 

Balance Sheet Total 0




EB-2009-0263 

Exhibit 1 

Tab 3 

Schedule 2 

Appendix H 




2010 STATEMENT OF INCOME AND RETAINED EARNINGS 


Total 

3000-Sales of Electricity 

4006-Residential Energy Sales (6,451,177) 

4010-Commercial Energy Sales 0 

4015-Industrial Energy Sales (16,814,544) 

4020-Energy Sales to Large Users (4,077,682) 

4025-Street Lighting Energy Sales (86,789) 

4030-Sentinel Lighting Energy Sales (10,768) 

4035-General Energy Sales 

4050-Revenue Adjustment 58,401 

4055-Energy Sales for Resale (8,521,357) 

4060-Interdepartmental Energy Sales 

4062-Billed WMS (3,843,469) 

4066-Billed NW (2,647,842) 

4068-Billed CN (2,409,496) 

4075-Billed LV (81,437) 

3000-Sales of Electricity Total (44,886,161) 

3050-Revenues From Services - Distirbution 

4080-Distribution Services Revenue (8,969,858) 

4082-Retail Services Revenues (27,160) 

4084-Service Transaction Requests (STR) Revenues (1,009) 

4090-Electric Services Incidental to Energy Sales 

3050-Revenues From Services - Distirbution Total (8,998,026) 

3100-Other Operating Revenues 

4210-Rent from Electric Property (152,305) 

4220-Other Electric Revenues (6,015) 

4225-Late Payment Charges (128,414) 

4230-Sales of Water and Water Power 

4235-Miscellaneous Service Revenues (207,660) 

3100-Other Operating Revenues Total (494,394) 

3150-Other Income & Deductions 

4375 - Revenue from non-utility operations (699,213) 

4330-Costs and Expenses of Merchandising, Jobbing, Etc. 0 

4355-Gain on Disposition of Utility and Other Property (26,087) 

4380-Expenses of Non-Utility Operations 631,478 

4390-Miscellaneous Non-Operating Income (32,109) 

4398-Foreign Exchange Gains and Losses, Including Amortization 0 

3150-Other Income & Deductions Total (125,931)


EB-2009-0263 

Exhibit 1 

Tab 3 

Schedule 2 

Appendix H 



3200-Investment Income 

4405-Interest and Dividend Income (24,000) 

3200-Investment Income Total (24,000) 

3350-Power Supply Expenses 

4705-Power Purchased 35,903,917 

4708-Charges-WMS 3,843,469 

4710-Cost of Power Adjustments 

4714-Charges-NW 2,647,842 

4715-System Control and Load Dispatching 

4716-Charges-CN 2,409,496 

4730-Rural Rate Assistance Expense 0 

4750-Charges - LV 81,437 

3350-Power Supply Expenses Total 44,886,161 

3500-Distribution Expenses - Operation 

5005-Operation Supervision and Engineering 0 

5010-Load Dispatching 37,575 

5012-Station Buildings and Fixtures Expense 37,238 

5014-Transformer Station Equipment - Operation Labour 0 

5015-Transformer Station Equipment - Operation Supplies and Expenses 0 

5016-Distribution Station Equipment - Operation Labour 2,247 

5017-Distribution Station Equipment - Operation Supplies and Expenses 9 

5020-Overhead Distribution Lines and Feeders - Operation Labour 17,313 

5025-Overhead Distribution Lines & Feeders - Operation Supplies and Expenses 37,191 

5030-Overhead Subtransmission Feeders - Operation 0 

5035-Overhead Distribution Transformers- Operation 14,628 

5040-Underground Distribution Lines and Feeders - Operation Labour 9,358 

5045-Underground Distribution Lines & Feeders - Operation Supplies & Expenses 1,627 

5050-Underground Subtransmission Feeders - Operations 0 

5055-Underground Distribution Transformers - Operation 13,760 

5065-Meter Expense 255,093 

5070-Customer Premises - Operation Labour 211,642 

5075-Customer Premises - Materials and Expenses 1,942 

5085-Miscellaneous Distribution Expense 9,630 

5095-Overhead Distribution Lines and Feeders - Rental Paid 

5096-Other Rent 8,938 

3500-Distribution Expenses - Operation Total 658,190


EB-2009-0263 

Exhibit 1 

Tab 3 

Schedule 2 

Appendix H 



3550-Distribution Expenses - Maintenance 

5105-Maintenance Supervision and Engineering 0 

5110-Maintenance of Buildings and Fixtures - Distribution Stations 2,299 

5114-Maintenance of Distribution Station Equipment 0 

5120-Maintenance of Poles, Towers and Fixtures 20,191 

5125-Maintenance of Overhead Conductors and Devices 104,719 

5130-Maintenance of Overhead Services 204,026 

5135-Overhead Distribution Lines and Feeders - Right of Way 170,517 

5145-Maintenance of Underground Conduit 46,250 

5150-Maintenance of Underground Conductors and Devices 101,282 

5155-Maintenance of Underground Services 88,185 

5160-Maintenance of Line Transformers 24,520 

5175-Maintenance of Meters 25,818 

3550-Distribution Expenses - Maintenance Total 787,807 

3650-Billing and Collecting 

5305-Supervision 24,371 

5310-Meter Reading Expense 105,899 

5315-Customer Billing 393,491 

5320-Collecting 162,038 

5325-Collecting - cash over and short 17 

5330-Collection Charges 0 

5335-Bad Debt Expense 121,396 

5340-Miscellaneous Customer Accounts Expenses 213,059 

3650-Billing and Collecting Total 1,020,272 

3700-Community Relations 

5405-Supervision 180 

5410-Community Relations - Sundry 925 

5415-Energy Conservation 30,701 

5420-Community Safety Program 11,124 

5510-Demonstrating and Selling Expense 0 

5515-Advertising Expense 0 

5520-Miscellaneous Sales Expense 0 

3700-Community Relations Total 42,930


EB-2009-0263 

Exhibit 1 

Tab 3 

Schedule 2 

Appendix H 



3800-Administrative and General Expenses 

5605-Executive Salaries and Expenses 478,580 

5610-Management Salaries and Expenses 0 

5615-General Administrative Salaries and Expenses 280,033 

5620-Office Supplies and Expenses 93,528 

5625-Administrative Expense Transferred Credit 0 

5630-Outside Services Employed 133,312 

5635-Property Insurance 15,739 

5640-Injuries and Damages 57,378 

5645-Employee Pensions and Benefits 101,979 

5655-Regulatory Expenses 101,748 

5660-General Advertising Expenses 0 

5665-Miscellaneous General Expenses 44,965 

5670-Rent 9,635 

5675-Maintenance of General Plant 142,249 

3800-Administrative and General Expenses Total 1,459,147 

3850-Amortization Expense 

5705-Amortization Expense - Property, Plant, and Equipment 2,639,848 

5725-Misc. Amortization - Org. Costs 15,648 

3850-Amortization Expense Total 2,655,496 

3900-Interest Expense 

6005-Interest on Long Term Debt 0 

6030-Interest on Debt to Associated Companies 1,135,961 

6035-Other Interest Expense 39,713 

6042-Allowance For Other Funds Used During Construction 

3900-Interest Expense Total 1,175,674 

3950-Taxes Other Than Income Taxes 

6105-Taxes Other Than Income Taxes 50,317 

3950-Taxes Other Than Income Taxes Total 50,317 

4000-Income Taxes 

6110-Income Taxes 730,000 

6115-Provision for Future Income Taxes (159,000) 

4000-Income Taxes Total 571,000 

4100-Extraordinary & Other Items 

6205-Donations 263 

6310-Extraordinary Deductions 

4100-Extraordinary & Other Items Total 263 

Net Income (1,221,254)


EB-2009-0263 

Exhibit 1 

Tab 3 

Schedule 3 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

RECONCILIATION BETWEEN PRO FORMA STATEMENTS AND REVENUE 

DEFICIENCY STATEMENTS 

Festival Hydro advises that because the 2007 and 2008 Audited Financial Statements do not vary 

from the regulatory financial results filed in this Application, a reconciliation between the 

financial statements and financial results filed has not been provided. However, as a result of 

differences between items such as deemed and actual interest expense in 2010 the following 

chart provides a reconciliation between the 2010 Pro Forma Statements and the Revenue 

Deficiency Statements. 

2010 Income Per Proforma Statements 1,221,254 

Plus pro-forma interest expense 1,175,674 

Less: deemed interest expense (1,660,572) 

Plus pro-forma income tax provision 571,000 

Less: grossed up income tax provision (908,589) 

Less: pro forma gain on disposal (26,087) 

Plus: allowed gain for revenue requirement 13,044 

Less: pro forma distribution revenue (8,969,858) 

Plus: Rate design distribution revenue 8,872,663 

Plus: donations included in pro-forma 263 

Net income 288,792 

Plus revenue deficiency 979,468 

1,268,260 

Net income per revenue requirement exhibit 1,268,260 

Difference (0)


EB-2009-0263 

Exhibit 1 

Tab 3 

Schedule 4 



INFORMATION ON AFFILIATES 

Festival Hydro Services Inc is involved mainly in Sentinel Lights and Dark Fibre Optic Cable. The City of 

Stratford also provides tree trimming services on behalf of FHI and FHI performs billing and collections 

services and street lighting services on behalf of the City of Stratford. Refer to information included in the 

shared services section of Exhibit 4 for more information on this affiliate.


EB-2009-0263 

Exhibit 1 

Tab 3 

Schedule 5 



MATERIALITY THRESHOLDS: 

As Festival Hydro’s distribution revenue is less than $10,000,000, a materiality threshold of $50,000 has 

been used to explain changes from year to year in Festival Hydro’s rate base, capital expenditures, and 

OM&A expenditures, in accordance with the OEB’s Chapter 2 of the Filing Requirements for Transmission 

and Distribution applications dated May 27, 2009.


EB-2009-0263 

Exhibit 2 

Index 




2 – Rate Base 

1 Overview 

1 Rate Base Overview 

2 Variance Analysis on Rate Base Table 

2 Gross Assets – Property, Plant and 

Equipment Accumulated Depreciation 

1 Continuity Statements 

2 Gross Assets Table 

3 Variance Analysis on Fixed Assets by 

Project 

4 Accumulated Depreciation Table 

5 Variance Analysis on Accumulated 

Depreciation 

3 Capital Budget 

1 Capital Project Description 

2 

Asset Management Plan Summary 

A Asset Management Plan 

3 Capitalization Policy 

4 Allowance for Working Capital 

1 Overview and Calculation by Account 

2 2009 & 2010 Cost of Power Forecast 

Calculation


EB-2009-0263 

Exhibit 2 

Tab 1 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

RATE BASE: 

Rate Base Overview: 

The rate base used for the purpose of calculating the revenue requirement used in this 

Application follows the definition used in the 2006 EDR Handbook as an average of the balances 

at the beginning and the end of the 2010 Test Year, plus a working capital allowance, which is 

15% of the sum of the cost of power and controllable expenses. 

The net fixed assets include those distribution assets that are associated with activities that enable 

the conveyance of electricity for distribution purposes. The FHI rate base calculation excludes 

any non-distribution assets. Controllable expenses include operations and maintenance, billing 

and collecting and administration expenses. 

FHI has provided its rate base calculations for the years 2006 Board Approved, 2006 Actual, 

2007 Actual, 2008 Actual, 2009 Bridge Year and 2010 Test Year in Table 1 below. FHI has 

calculated its 2010 rate base as $39,583,651. 

Description 

2006 OEB 

Approved 

Table 1 

Summary of Rate Base 

2006 Actual 2007 Actual Year 2008 Actual Year 

2009 Bridge 

Year 

2010 Test Year 

Gross Fixed Assets 56,920,451 62,593,542 65,198,393 70,067,244 73,469,244 76,826,244 

Accumulated Depreciation 28,828,157 33,562,551 35,520,874 38,726,543 41,462,401 44,337,232 

Net Book Value 28,092,294 29,030,991 29,677,519 31,340,701 32,006,843 32,489,012 

Average Net Book Value 28,421,346 28,890,694 29,354,255 30,509,110 31,673,772 32,247,927 

Working Capital 46,050,224 47,968,053 48,360,788 47,080,155 50,100,520 48,904,825 

14 

15 

16 

17 

18 

19 

Working Capital Allowance 6,907,534 7,195,208 7,254,118 7,062,023 7,515,078 7,335,724 

Rate Base 34,999,828 36,085,902 36,608,373 37,571,133 39,188,850 39,583,651 

FHI has provided a summary of its calculations of the cost of power and controllable expenses 

used in the calculations for determining working capital for the years 2006 Board Approved, 

2006 Actual, 2007 Actual, 2008 Actual, 2009 Bridge Year and 2010 Test Year in Table 2, 

below.


EB-2009-0263 

Exhibit 2 

Tab 1 

Schedule 1 



1 

2 

3 

4 

5 

6 

The Cost of Power for 2009 shows a large increase over 2008 due to a higher price for 

commodity (i.e. 6.072 cents per kWh for 2009 as per approved 2009 cost of service rate 

applications versus actual IESO 2008 Weighted Average Hourly Price of 5.17 cents). In 2010 

the cost of power reduces because of much lower sales volumes and reduced rates for network, 

connection and low voltage charges. Details of FHI’s calculation of its working capital 

allowance are provided at Exhibit 2, Tab 4, Schedule 1, below. 

Description 

2006 OEB 

Approved 

Table 2 

Summary of Working Capital 

2006 Actual 

2007 Actual 

Year 

2008 Actual 

Year 

2009 Bridge 

Year 

2010 Test 

Year 

Cost of Power 42,648,111 44,210,195 44,549,337 43,327,319 46,148,116 44,886,161 

Operations 404,166 528,712 522,506 623,913 640,791 658,190 

Maintenance 796,377 674,908 835,083 745,455 766,335 787,807 

Billing & Collecting 909,919 962,636 921,773 928,131 1,022,792 1,020,272 

Community Relations 24,784 113,313 157,301 12,067 22,374 42,930 

Administration & General Expense 1,234,811 1,348,436 1,249,982 1,383,769 1,410,622 1,459,147 

Property Taxes 32,056 129,853 124,805 59,500 89,490 50,317 

7 

8 

Working Capital 46,050,224 47,968,053 48,360,788 47,080,155 50,100,520 48,904,825 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

The FHI Distribution System: 

FHI owns and operates the electricity distribution system in its licensed service area in the City 

of Stratford, and the Towns of St. Marys, Seaforth, Brussels, Hensall, Zurich, and Dashwood, 

serving approximately 25,400 Residential, General Service, Large Use, Street Light, Sentinel 

Light and Unmetered Scattered Load customers/connections. 

FHI is supplied through the Hydro One transmission system at primary voltage of 27.6 kV. 

Electricity is then distributed through FHI’s service area of 44.7 square kilometres, over 90.1 

kilometres of underground cable and 184.8 kilometres of overhead conductor. FHI delivers 

electricity at its primary supply voltage to Large Use and larger General Service >50 kW (27.6 

kV wye), General Service (27.6, 13.8 or 4 kV wye) and Residential (16.0, 4.8 or 2.4 kV) 

customers. Primary voltage is stepped down through 6 FHI-owned distribution stations to 

service General Service (347/600 wye 600 delta, 240 delta, 120/208 wye, three phase) and


EB-2009-0263 

Exhibit 2 

Tab 1 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

Residential (120/240 single phase) customers. Voltage is stepped down from the 27.6, 8, and 

4.16 kV primary feeders through approximately 2,433 LDC owned distribution transformers. 

FHI monitors its distribution system through a control system at its main office. The engineering 

department operates the Supervisory Control and Data Acquisition ("SCADA") system eight 

hours a day, five days a week. 

FHI owns and maintains approximately 19,527 meters installed on its customers’ premises for 

the purpose of measuring consumption of electricity for billing purposes. Meters vary in type by 

customer and include meters capable of measuring kWh consumption, kW and kVA demand as 

well as hourly interval data. FHI has not begun the process of installing smart meters as part of 

the Province of Ontario’s smart meter initiative and the cost of smart meters have not been 

included in the proposed revenue requirement in this application. 

In managing its distribution system assets, FHI’s main objective is to optimize performance of 

the assets at a reasonable cost with due regard for system reliability, public & worker safety and 

customer service requirements. This Application incorporates FHI’s 2009 and 2010 Capital and 

Expense Budgets in determining the revenue requirement to bring these plans to fruition. 

Further information will be provided later in this Application. FHI considers performancerelated 

asset information including, but not limited to, data on reliability, asset age and condition, 

loading, customer connection requirements, and system configuration, to determine investment 

needs of the system. 

On an annual basis, FHI reviews capital projects identified for potential implementation and 

attempts to prioritize each project based on defined criteria on a relative basis. All members of 

the management team follow the criteria as they individually complete their work on preparing 

outlines of their recommendations, which are then discussed by the full group. 

In addition to the capital needs of the network, FHI provides for maintenance planning for the 

assets. The same preparation and consideration steps are undertaken before the Finance


EB-2009-0263 

Exhibit 2 

Tab 1 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

department establishes the recommended budget amounts. Further information on FHI’s Capital 

and Operation, Maintenance & Administration amounts will follow later in this Application. 

FHI assets fall into two broad categories – distribution plant, which includes assets such as wires, 

overhead and underground electricity distribution infrastructure, transformers, meters and 

substations; and general plant which includes assets such as substation buildings, SCADA, 

equipment and tools. More detailed lists of distribution and general plant categories can be 

found in the Gross Assets Table at Exhibit 2, Tab 2, and Schedule 2. 

Capital Projects: 

FHI’s capital budget items include: 

10 

 

Customer Driven Project: 

11 

12 

13 

14 

15 

16 

17 

These are projects that FHI undertakes to meet its customer service obligations in accordance 

with the OEB’s Distribution System Code (the “DSC”) and FHI’s Conditions of Service. 

Activities include connecting new customers, building new subdivisions and relocating system 

plant for roadway reconstruction work. Capital contributions toward the cost of these projects 

are collected by FHI in accordance with the DSC and the provisions of its Conditions of Service. 

FHI uses the economic evaluation methodology from the DSC to determine the level of capital 

contribution for each project. 

18 

 

Rebuild and Conversion Project 

19 

20 

21 

22 

23 

24 

Renewal projects are completed when assets reach their end of useful life and must be replaced. 

FHI completes visual inspections of its plant and performs predictive testing on certain assets 

where such testing is available, and replaces assets based on these inspection and testing 

activities if warranted. In some cases the projects involve spot replacement of assets; in others, 

the projects involve complete asset replacement within a geographic area. When a large project 

area is targeted for replacement, the supply voltage is reviewed to determine if a conversion to a


EB-2009-0263 

Exhibit 2 

Tab 1 

Schedule 1 



1 

2 

higher voltage is warranted based on the age of the substation. New assets require less 

maintenance, deliver better reliability and reduce safety risks to the general public. 

3 

 

Capacity: 

4 

5 

6 

7 

8 

Load growth caused by new customer connections and increased demand of existing customers 

over time can result in a need for capacity improvements on the system. Projects can take the 

form of new or upgraded feeders, transformers or voltage conversion projects, substations or 

transformer stations. These projects are not customer-specific, but rather, they benefit many 

customers. 

9 

 

Reliability: 

10 

11 

12 

13 

14 

15 

16 

The main driver for these investments is an analysis of what measures could be undertaken to 

improve FHI reliability performance as measured by SAIDI, SAIFI and CAIDI indices. These 

indices are indicators of the reliability of FHI’s distribution system. These activities will support 

maintenance of or improvement to the Service Quality Indices measured and submitted to the 

OEB each year by FHI. The Asset Management Report provided in Exhibit 2, Tab 3, Schedule 

2, Appendix A supports the capital and maintenance programs needed to maintain and enhance 

the reliability of FHI’s distribution system. 

17 

 

Substations: 

18 

19 

20 

21 

22 

23 

24 

Substation investments are undertaken to improve or maintain reliability to large numbers of 

customers and to maintain security and safety at the substations. The renewal or retirement of 

FHI’s 4.16 kV substations is the subject of a review being undertaken as part of the Asset 

Management Report. Since 1985, FHI has been expanding the 27.6kV system with the objective 

of eliminating some of the 4.16kV network, which could eventually lead to a reduction in the 

number of distribution stations, reduced number of distribution feeders and improved efficiency 

in the delivery of electricity. 

25


EB-2009-0263 

Exhibit 2 

Tab 1 

Schedule 1 



1 

 

Customer Connections and Metering: 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

Capital expenditures in this pool include meter installations, meter upgrades, and the capital 

components of wholesale and retail meter verification activities. 

FHI capital projects for the 2010 Test Year are discussed in further detail below. FHI has 

provided project-specific justifications in Exhibit 2, Tab 3, Schedule 1. Similarly, written 

explanations have been provided for rate base-related variances that exceed materiality of 

50,000. 

Gross Assets – Property, Plant and Equipment and Accumulated Depreciation: 

The 2009 Bridge and 2010 Test Years’ gross asset balances reflect the capital expenditure 

programs forecast for both years. These programs are described in detail in FHI’s written 

evidence at Exhibit 2, Tab 2, Schedule 3 and Tab 3, Schedule 1. 

The following comments provide an overview of FHI’s budgeting process. 

Overall Budget Process: 

The budget is prepared annually by management and is reviewed and approved by the FHI Board 

of Directors. The budget is prepared before the start of each fiscal year. Once approved, it does 

not change, but provides a plan against which actual results may be evaluated. 

Responsibilities: 

> It is the responsibility of the Finance and Engineering departments to coordinate the 

development of the operating budget, capital budget and forecast processes. 

> Each department is responsible for preparing its operating budget, capital budget, and 

rolling forecasts.


EB-2009-0263 

Exhibit 2 

Tab 1 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

> The President, with assistance from the Secretary Treasurer and Vice President of 

Engineering and Operations, is responsible for presenting and recommending the budget 

to the Board of Directors for approval. 

> It is the responsibility of the Board of Directors, on behalf of the shareholder, to approve 

the budget. 

The budget is an important planning tool for FHI. It puts capital and operational plans into a 

common financial plan. The final document provides a comprehensive package of department 

budgets that collectively ensure that appropriate resources are designated for the various capital 

and operational needs of the utility for the coming year. 

The departmental Budget Plans represent the output of detailed work plans based on required 

activities for the year. FHI notes that these Budget Plans address both capital and operating 

requirements.


EB-2009-0263 

Exhibit 2 

Tab 1 

Schedule 2 



1 

2 

3 

4 

RATE BASE VARIANCE ANALYSIS: 

The following Table 1 sets out FHI’s rate base and working capital calculations for 2006 Board 

Approved, 2006 Actual, 2007 Actual, 2008 Actual, 2009 Bridge Year and 2010 Test Year, and 

the following variances: 

5 

6 

7 

8 

9 

 

 

 

 

 

2006 Actual against 2006 Board Approved; 

2007 Actual against 2006 Actual; 

2008 Actual against 2007 Actual 

2009 Bridge Year against 2008 Actual; and 

2010 Test Year against 2009 Bridge Year. 

Table 1 

Rate Base Variances 

Rate Base: 

Description 

2006 OEB 

Approved* 

2006 Actual 

Variance from 

2006 OEB 

Approved 

2007 Actual 

Year 

Variance from 

2006 Actual 

2008 Actual 

Year 

Variance 

from 2007 

Actual Year 

2009 Brdge 

Year 

Variance from 

2008 Actual 

Year 

2010 Test 

Year 

Variance from 

2009 Bridge 

Year 

Gross Fixed Assets 56,920,451 62,593,542 5,673,091 65,198,393 2,604,851 70,067,244 4,868,851 73,469,244 3,402,000 76,826,244 3,357,000 

Accumulated Depreciation 28,828,157 33,562,551 4,734,394 35,520,874 1,958,322 38,726,543 3,205,670 41,462,401 2,735,858 44,337,232 2,874,831 

Net Book Value 28,092,294 29,030,991 938,697 29,677,519 646,529 31,340,701 1,663,181 32,006,843 666,142 32,489,012 482,169 

Average Net Book Value 28,421,346 28,890,694 469,348 29,354,255 463,561 30,509,110 1,154,855 31,673,772 1,164,662 32,247,927 574,156 

Working Capital 46,050,224 47,968,053 1,917,829 48,360,788 392,735 47,080,155 (1,280,634) 50,100,520 3,020,365 48,904,825 (1,195,695) 

10 

11 

Working Capital Allowance 6,907,534 7,195,208 287,674 7,254,118 58,910 7,062,023 (192,095) 7,515,078 453,055 7,335,724 (179,354) 

Rate Base 34,999,828 36,085,902 1,086,075 36,608,373 522,471 37,571,133 962,760 39,188,850 1,617,717 39,583,651 394,801 

12 

13 

14 

15 

16 

17 

FHI notes that the 2006 OEB Approved rate base was determined through the 2006 EDR process 

and is based on the 2004 year end rate base adjusted for Tier 1 Adjustments. Accordingly, the 

variance between 2006 Actual and 2006 OEB Approved spans a two-year period. 

FHI has calculated the materiality threshold on its rate base to be $50,000 for 2010 in accordance 

with the Filing Requirements. 

FHI offers the following comments in respect of the relevant variances identified above: 

18


EB-2009-0263 

Exhibit 2 

Tab 1 

Schedule 2 



1 

2 

3 

4 

2010 Test Year: 

As shown in Table 1 above, the total rate base in the 2010 test year is forecast to be $39,583,651. 

Average net fixed assets accounts for $32,247,927 of this total. The allowance for working 

capital totals $7,335,724. 

5 

 

2010 Test Year vs. 2009 Bridge Year: 

6 

7 

8 

9 

10 

11 

12 

13 

The total rate base is expected to be $394,801 higher in the 2010 Test Year than in the 2009 

Bridge Year. This increase is shown in Table 1 above and is attributable primarily to an increase 

in average net fixed assets of $574,156. The increase in fixed assets along with the required 

detailed information for projects is discussed in detail by capital project in Exhibit 2, Tab 3, 

Schedule 1. 

The working capital allowance decreased by $179,354 from the 2009 Bridge Year. A detailed 

calculation of the working capital allowance for the 2010 Test Year can be found at Exhibit 2, 

Tab 4, Schedule 1, below. 

14 

 

2009 Bridge Year vs. 2008 Actual: 

15 

16 

17 

18 

19 

20 

The total rate base for the 2009 Bridge Year is expected to be $39,188,850, which represents an 

increase of $1,617,717 over the 2008 Actual year. This change results in part from an increase in 

average net assets of $1,164,662. This increase is primarily due to capital expenditures. The 

working capital allowance increased by $453,055 from 2008. A detailed calculation of the 

working capital allowance for the 2009 Bridge Year can be found at Exhibit 2, Tab 4, Schedule 

1, below. 

21 

 

2008 Actual vs. 2007 Actual: 

22 

23 

24 

The rate base of $37,571,133 for 2008 Actual increased over 2007 Actual by $962,760. This 

increase is made up of a change in average net assets of $1,154,855 as a result of capital 

expenditures. The working capital allowance decreased by $192,095. 

25


EB-2009-0263 

Exhibit 2 

Tab 1 

Schedule 2 



1 

 

2007 Actual vs. 2006 Actual: 

2 

3 

4 

The rate base of $36,608,373 for 2007 Actual increased over 2006 Actual by $522,471. This 

increase is made up of a change in average net assets of $463,561 as a result of capital 

expenditures. The working capital allowance increased by $58,910. 

5 

 

2006 Actual vs. 2006 Board Approved: 

6 

7 

8 

9 

10 

11 

The rate base of $36,085,902 for 2006 Actual was higher than the 2006 Board Approved by 

$1,086,075. The difference reflects the fact that the 2006 Board Approved amounts were 

calculated as the average of the 2003 and 2004 actual amounts. 

The variance between the 2006 Actual and the 2006 Board Approved included the difference 

between the 2004 actual and the 2006 Board Approved amounts as well as the 2005 normal 

investments.


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 1 



CONTINUITY STATEMENTS: 

Table 1 

FHI 

Fixed Asset Continuity Schedule 

December 31, 2004 

Cost 

Accumulated Depreciation 

Opening 

Closing Opening 

Closing 

OEB 

Description 

Balance Additions Disposals Balance Balance Additions Disposals Balance Net Book Value 

1805 Land - Substations 345,471 5,351 340,120 -154,479 138,766 -293,245 633,365 

1808 Buildings - Substations 1,617,414 1,617,414 758,947 30,793 789,740 827,674 

1810 Leasehold Improvements 0 0 0 

1815 Transformer Station Equipment > 50 kV 0 0 0 

1820 Substation Equipment 1,697,625 1,697,625 1,067,249 45,674 1,112,923 584,702 

1825 Storage Battery Equipment 0 0 0 

1830 Poles, Towers & Fixtures 6,100,793 575,980 106 6,676,667 2,512,928 257,883 2,770,811 3,905,856 

1835 OH Conductors & Devices 6,956,649 847,901 7,804,550 2,731,388 303,026 3,034,414 4,770,136 

1840 UG Conduit 5,121,390 102,970 5,224,360 2,371,089 191,549 2,562,638 2,661,722 

1845 UG Conductors & Devices 13,166,363 291,854 327 13,457,890 6,467,498 494,852 6,962,350 6,495,540 

1850 Line Transformers 10,826,010 380,025 214 11,205,821 5,374,853 378,949 5,753,802 5,452,019 

1855 Services (OH & UG) 3,455,710 222,544 3,678,254 1,543,669 138,267 1,681,936 1,996,318 

1860 Meters 2,815,736 281,410 3,097,146 1,600,027 112,097 1,712,124 1,385,022 

1861 Smart Meters 0 0 0 

1905 Land 17,041 17,041 0 17,041 

1906 Land Rights 0 0 0 

1908 Buildings & Fixtures 132,289 34,284 166,573 55,567 4,862 60,429 106,144 

1910 Leasehold Improvements 21,798 21,798 13,079 4,360 17,439 4,359 

1915 Office Furniture & Equipment 325,132 2,792 327,924 275,978 14,421 290,399 37,525 

1920 Computer - Hardware 691,060 27,975 719,035 588,655 52,038 640,693 78,342 

1921 Computer - Hardware post Mar 22/04 0 0 

1921 Computer - Hardware post Mar19/07 0 0 

1925 Computer - Software 368,100 21,100 389,200 319,333 25,483 344,816 44,384 

1930 Transportation Equipment 2,065,571 223,260 2,288,831 1,873,220 99,591 1,972,811 316,020 

1935 Stores Equipment 36,199 36,199 36,199 0 36,199 0 

1940 Tools, Shop & Garage Equipment 528,545 24,902 3,397 550,050 421,414 31,641 3,397 449,658 100,392 

1945 Measurement & Testing Equipment 13,413 13,413 1,881 1,881 11,532 

1950 Power operated Equipment 0 0 0 

1955 Communications Equipment 103,582 103,582 67,259 5,191 72,450 31,132 

1960 Miscellaneous Equipment 0 0 0 

1965 Water Heater Rental Units 0 0 0 

1970 Load Management controls 0 0 0 

1975 Load Management Controls Utility Premises 0 0 0 

1980 System Supervisory Equipment 190,671 12,299 202,970 19,067 20,297 39,364 163,606 

1985 Sentinel Lighting Rental Units 0 0 0 

1996 Hydro One S/S Contribution 0 0 0 

1995 Contributions & Grants -1,138,190 -492,361 -1,630,551 -117,525 -65,209 -182,734 -1,447,817 

Total before Work in Process 55,458,372 2,556,935 9,395 58,005,912 27,825,415 2,147,646 142,163 29,830,898 28,175,014 

Work in Process 0 0 

Total after Work in Process 55,458,372 2,556,935 9,395 58,005,912 27,825,415 2,147,646 142,163 29,830,898 28,175,014


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 1 



Table 2 

FHI 



Cost 


Opening 


Closing 

OEB 

Description 


1805 Land - Substations 340,120 340,120 -293,245 181,982 -475,227 815,347 

1808 Buildings - Substations 1,617,414 10,764 1,606,650 789,740 30,091 7,000 812,831 793,819 

1810 Leasehold Improvements 0 0 0 0 0 

1815 Transformer Station Equipment > 50 kV 0 0 0 0 0 

1820 Substation Equipment 1,697,625 48,271 1,745,896 1,112,923 45,737 1,158,660 587,236 

1825 Storage Battery Equipment 0 0 0 0 0 

1830 Poles, Towers & Fixtures 6,676,667 521,905 7,198,572 2,770,811 274,949 3,045,760 4,152,812 


1840 UG Conduit 5,224,360 163,988 5,388,348 2,562,638 198,108 2,760,746 2,627,602 

1845 UG Conductors & Devices 13,457,890 387,516 13,845,406 6,962,350 510,354 7,472,704 6,372,702 

1850 Line Transformers 11,205,821 467,723 11,673,544 5,753,802 397,415 6,151,217 5,522,327 

1855 Services (OH & UG) 3,678,254 215,198 3,893,452 1,681,936 145,982 1,827,918 2,065,534 

1860 Meters 3,097,146 131,367 3,228,513 1,712,124 117,352 1,829,476 1,399,037 

1861 Smart Meters 0 0 0 0 0 

1905 Land 17,041 17,041 0 0 17,041 

1906 Land Rights 0 0 0 0 0 


1910 Leasehold Improvements 21,798 2,195 23,993 17,439 4,360 21,799 2,194 

1915 Office Furniture & Equipment 327,924 327,924 290,399 12,234 302,633 25,291 


1921 Computer - Hardware post Mar 22/04 0 0 0 0 

1921 Computer - Hardware post Mar19/07 0 0 0 0 


1930 Transportation Equipment 2,288,831 319,129 366,768 2,241,192 1,972,811 150,789 336,203 1,787,397 453,795 

1935 Stores Equipment 36,199 36,199 36,199 0 36,199 0 

1940 Tools, Shop & Garage Equipment 550,050 39,514 589,564 449,658 21,561 471,219 118,345 

1945 Measurement & Testing Equipment 13,413 13,413 1,881 1,881 3,762 9,651 

1950 Power operated Equipment 0 0 0 0 0 

1955 Communications Equipment 103,582 2,584 106,166 72,450 5,162 77,612 28,554 

1960 Miscellaneous Equipment 0 0 0 0 0 

1965 Water Heater Rental Units 0 0 0 0 0 

1970 Load Management controls 0 98,897 98,897 0 9,890 9,890 89,007 

1975 Load Management Controls Utility Premises 0 0 0 0 0 


1985 Sentinel Lighting Rental Units 0 0 0 0 0 

1996 Hydro One S/S Contribution 0 0 0 0 0 






EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 1 



Table 3 

FHI 


As at December 31, 2006 

Opening 


Closing 

OEB 

Description 


1805 Land - Substations 340,120 0 340,120 0 0 0 340,120 

1808 Buildings - Substations 1,697,947 0 1,697,947 862,739 33,214 895,954 801,993 

1810 Leasehold Improvements 0 0 0 

1815 Transformer Station Equipment > 50 kV 0 0 0 


1825 Storage Battery Equipment 0 0 0 


1835 OH Conductors & Devices 8,384,480 597,468 8,981,948 2,881,083 341,692 146,752 3,076,023 5,905,926 

1840 UG Conduit 5,388,348 125,318 5,513,666 2,760,747 203,121 2,963,868 2,549,798 



1855 Services (OH & UG) 3,893,452 242,015 4,135,467 1,827,918 154,793 1,982,712 2,152,755 

1860 Meters 3,228,513 29,069 3,257,582 1,829,475 102,823 1,932,299 1,325,283 

1861 Smart Meters 0 0 0 

1905 Land 0 0 0 

1906 Land Rights 0 0 0 


1910 Leasehold Improvements 21,798 21,798 21,798 0 21,798 0 

1915 Office Furniture & Equipment 330,118 1,674 331,792 302,633 7,287 309,920 21,872 



1921 Computer - Hardware post Mar19/07 0 0 



1935 Stores Equipment 36,199 36,199 36,199 36,199 0 



1950 Power operated Equipment 0 0 0 



1965 Water Heater Rental Units 0 0 0 

1970 Load Management controls 76,841 0 76,841 9,890 20,454 30,344 46,497 

1975 Load Management Controls Utility Premises 22,056 105,646 127,702 0 127,702 


1985 Sentinel Lighting Rental Units 0 0 0 

1996 Hydro One S/S Contribution 0 0 0 






EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 1 



Table 4 

FHI 



Opening 

Opening 

Closing 

OEB 

Description 

Balance Additions Disposals Closing Balance Balance Additions Disposals Balance Net Book Value 

1805 Land - Substations 340,120 0 5,321 334,798 0 0 0 334,798 

1808 Buildings - Substations 1,697,947 0 1,697,947 895,954 33,628 929,582 768,365 






1835 OH Conductors & Devices 8,981,948 456,789 9,438,738 3,076,023 354,904 196,036 3,234,891 6,203,847 

1840 UG Conduit 5,513,666 152,695 5,666,361 2,963,868 209,229 3,173,097 2,493,264 


1850 Line Transformers 12,274,284 920,195 1,673 13,192,806 6,571,443 457,216 335 7,028,324 6,164,481 

1855 Services (OH & UG) 4,135,467 240,533 4,376,000 1,982,712 163,343 2,146,054 2,229,946 

1860 Meters 3,257,582 86,369 3,343,951 1,932,299 106,506 2,038,805 1,305,146 

1861 Smart Meters 0 0 0 0 0 

1905 Land 0 0 0 0 0 

1906 Land Rights 0 0 0 0 0 


1910 Leasehold Improvements 21,798 21,798 21,798 21,798 0 



1921 Computer - Hardware post Mar 22/04 0 0 0 0 0 

1921 Computer - Hardware post Mar19/07 0 0 0 0 0 




1940 Tools, Shop & Garage Equipment 613,367 34,157 6,372 641,152 500,692 26,981 6,372 521,301 119,851 



1955 Communications Equipment 106,166 362 106,528 82,775 5,199 87,973 18,555 



1970 Load Management controls 76,841 40,576 117,417 30,344 23,768 54,113 63,305 

1975 Load Management Controls Utility Premises 127,702 127,702 0 0 127,702 






Work in Process 0 0 0 0 0 0 0 0 



EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 1 



Table 5 

FHI 



OEB 

Description 

Opening 

Balance Additions Disposals Closing Balance Opening Balance Additions Disposals 

Closing 

Balance Net Book Value 

1805 Land - Substations 334,798 5,321 796 339,323 0 0 339,323 

1808 Buildings - Substations 1,697,947 -5,321 8,528 1,684,098 929,582 33,450 7,249 955,783 728,315 






1835 OH Conductors & Devices 9,438,738 1,882,567 11,321,305 3,234,891 420,555 -818,014 4,473,460 6,847,845 

1840 UG Conduit 5,666,361 353,091 6,019,452 3,173,097 218,167 3,391,263 2,628,188 



1855 Services (OH & UG) 4,376,000 216,274 4,592,275 2,146,054 171,661 2,317,715 2,274,559 

1860 Meters 3,343,951 85,876 3,429,828 2,038,805 109,955 2,148,760 1,281,067 

1861 Smart Meters 0 0 0 0 0 

1905 Land 0 0 0 0 0 

1906 Land Rights 0 0 0 0 0 














1960 Miscellaneous Equipment 0 7,842 7,842 0 784 784 7,058 


1970 Load Management controls 117,417 117,417 54,113 24,512 78,624 38,793 





1995 Contributions & Grants -3,166,416 -411,910 -3,578,326 -483,782 -143,133 (626,915) -2,951,411 

Total before Work in Process 65,198,393 5,063,167 194,316 70,067,244 35,520,874 2,579,897 -625,773 38,726,543 31,340,701 

2105 Accum amortization - EL Utility PL Property 0 0 

Work in Process 0 0 0 0 0 

Total after Work in Process 65,198,393 5,063,167 194,316 70,067,244 35,520,874 2,579,897 -625,773 38,726,543 31,340,701


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 1 



Table 6 

FHI 



OEB 

Description Opening Balance Additions Disposals Closing Balance Opening Balance Additions Disposals 

Closing 

Balance Net Book Value 

1805 Land - Substations 339,323 339,323 0 0 0 339,323 

1808 Buildings - Substations 1,684,098 1,684,098 955,783 33,628 989,411 694,687 






1835 OH Conductors & Devices 11,321,305 1,068,000 12,389,305 4,473,460 460,722 4,934,182 7,455,123 

1840 UG Conduit 6,019,452 203,000 6,222,452 3,391,263 226,286 3,617,549 2,604,902 



1855 Services (OH & UG) 4,592,275 228,000 4,820,275 2,317,715 180,241 2,497,956 2,322,318 

1860 Meters 3,429,828 75,000 3,504,828 2,148,760 112,955 2,261,715 1,243,112 

1861 Smart Meters 0 0 0 0 0 

1905 Land 0 0 0 0 0 

1906 Land Rights 0 0 0 0 0 








1930 Transportation Equipment 2,562,270 355,000 2,917,270 1,665,365 222,994 1,888,359 1,028,911 






1960 Miscellaneous Equipment 7,842 7,842 784 784 1,568 6,274 


1970 Load Management controls 117,417 117,417 78,624 24,512 103,136 14,281 




1996 Hydro One S/S Contribution 0 0 0 0 0 0 

1995 Contributions & Grants (3,578,326) (360,000) (3,938,326) (626,915) (157,533) (784,448) (3,153,878) 

Total before Work in Process 70,067,244 3,402,000 0 73,469,244 38,726,543 2,735,858 0 41,462,401 32,006,843 

2105 Accum amortization - EL Utility PL Property 0 0 0 

Work in Process 0 0 0 0 0 0 

Total after Work in Process 70,067,244 3,402,000 0 73,469,244 38,726,543 2,735,858 0 41,462,401 32,006,843


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 1 



Table 7 

OEB 

Description 


2009 Bridge Year Additions to June 30th, 2009 

Opening Balance 

Total Budgeted 

Additions 

Actual Additions 

to June 30th 

Remaining 

Additions 

Closing Balance 

1805 Land - Substations 339,323 339,323 

1808 Buildings - Substations 1,696,506 1,696,506 

1810 Leasehold Improvements 0 0 

1815 Transformer Station Equipment > 50 kV 0 0 

1820 Substation Equipment 1,745,896 1,745,896 

1825 Storage Battery Equipment 0 0 

1830 Poles, Towers & Fixtures 9,336,575 710,500 397,442 313,058 10,047,075 

1835 OH Conductors & Devices 11,321,305 1,068,000 324,752 743,248 12,389,305 

1840 UG Conduit 6,019,452 203,000 18,572 184,428 6,222,452 

1845 UG Conductors & Devices 15,287,819 162,500 138,083 24,417 15,450,319 

1850 Line Transformers 13,870,225 658,500 310,414 348,086 14,528,725 

1855 Services (OH & UG) 4,592,275 228,000 62,600 165,400 4,820,275 

1860 Meters 3,429,828 75,000 17,609 57,391 3,504,828 

1861 Smart Meters 0 0 

1905 Land 0 0 

1906 Land Rights 0 0 

1908 Buildings & Fixtures 389,838 151,500 28,529 122,971 541,338 

1910 Leasehold Improvements 21,798 21,798 

1915 Office Furniture & Equipment 331,792 331,792 

1920 Computer - Hardware 883,757 45,000 63,308 (18,308) 928,757 



1925 Computer - Software 454,162 25,000 8,316 16,684 479,162 

1930 Transportation Equipment 2,562,270 355,000 64,116 290,884 2,917,270 

1935 Stores Equipment 36,199 36,199 

1940 Tools, Shop & Garage Equipment 696,644 60,000 23,338 36,662 756,644 

1945 Measurement & Testing Equipment 13,413 13,413 

1950 Power operated Equipment 0 0 

1955 Communications Equipment 106,528 106,528 

1960 Miscellaneous Equipment 7,842 7,842 

1965 Water Heater Rental Units 0 0 

1970 Load Management controls 117,417 117,417 

1975 Load Management Controls Utility Premises 127,702 127,702 

1980 System Supervisory Equipment 257,006 20,000 19,354 646 277,006 

1985 Sentinel Lighting Rental Units 0 0 

1996 Hydro One S/S Contribution 0 0 

1995 Contributions & Grants (3,578,326) (360,000) (360,000) (3,938,326) 

Total before Work in Process 70,067,244 3,402,000 1,476,433 1,925,567 73,469,244


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 1 



Table 8 

FHI 



Closing 

OEB 

Description 

Opening Balance Additions Disposals Closing Balance Opening Balance Additions Disposals Balance Net Book Value 

1805 Land - Substations 339,323 0 339,323 0 0 339,323 

1808 Buildings - Substations 1,684,098 0 1,684,098 989,411 33,628 1,023,039 661,059 

1810 Leasehold Improvements 0 

1815 Transformer Station Equipment > 50 kV 0 

1820 Substation Equipment 1,745,896 0 1,745,896 1,325,666 40,423 1,366,089 379,807 

1825 Storage Battery Equipment 0 



1840 UG Conduit 6,222,452 259,500 6,481,952 3,617,549 233,307 3,850,856 2,631,095 



1855 Services (OH & UG) 4,820,275 220,000 5,040,275 2,497,956 185,233 2,683,189 2,357,085 

1860 Meters 3,504,828 20,000 3,524,828 2,261,715 113,755 2,375,470 1,149,357 

1861 Smart Meters 0 

1905 Land 0 

1906 Land Rights 0 





1921 Computer - Hardware post Mar 22/04 0 

1921 Computer - Hardware post Mar 19/07 0 


1930 Transportation Equipment 2,917,270 300,000 3,217,270 1,888,359 254,836 2,143,195 1,074,075 



1945 Measurement & Testing Equipment 13,413 13,413 11,286 1,881 13,167 246 

1950 Power operated Equipment 0 


1960 Miscellaneous Equipment 7,842 0 7,842 1,568 784 2,352 5,490 

1965 Water Heater Rental Units 0 

1970 Load Management controls 117,417 0 117,417 103,136 24,512 127,648 -10,231 

1975 Load Management Controls Utility Premises 127,702 127,702 127,702 


1985 Sentinel Lighting Rental Units 0 

1996 Hydro One S/S Contribution 0 


Total before Work in Process 73,469,244 3,357,000 0 76,826,244 41,462,401 2,874,831 0 44,337,232 32,489,012 

Work in Process 0 0 0 0 0 0 

Total after Work in Process 73,469,244 3,357,000 0 76,826,244 41,462,401 2,874,831 0 44,337,232 32,489,012

GROSS ASSETS TABLE: 


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 2 



Description 

2006 Board 

Variance from 2006 Board 

Variance from 

Approved ($) 2006 Actual ($) Approved 

2007 Actual ($) 2006 Actual 2008 Actual ($) 

Variance from 2007 

Actual 

2009 Bridge ($) 


Actual 

Land and Buildings 

1805-Land 342,796 340,120 (2,676) 334,798 (5,322) 339,323 4,525 339,323 0 339,323 

1806-Land Rights 

1808-Buildings and Fixtures 1,708,710 1,697,947 (10,763) 1,710,355 12,408 1,696,506 (13,849) 1,684,098 (12,408) 1,684,098 

1905-Land 


1810-Leasehold Improvements 

Sub-Total-Land and Buildings 2,051,506 2,038,067 (13,439) 2,045,153 7,086 2,035,829 (9,324) 2,023,422 2,023,422 

2010 Test ($) 


Bridge 

TS Primary Above 50 


Sub-Total-TS Primary Above 50 

DS 

1820-Distribution Station Equipment - Normally Primary below 50 kV 1,697,625 1,745,896 48,271 1,745,896 1,745,896 (0) 1,745,896 1,745,896 

Sub-Total-DS 1,697,625 1,745,896 48,271 1,745,896 1,745,896 (0) 1,745,896 1,745,896 

Poles and Wires 

1830-Poles, Towers and Fixtures 6,388,730 7,867,167 1,478,437 8,435,198 568,031 9,336,575 901,377 10,047,075 710,500 10,787,575 740,500 

1835-Overhead Conductors and Devices 7,380,600 8,981,948 1,601,349 9,438,738 456,790 11,321,305 1,882,567 12,389,305 1,068,000 13,219,305 830,000 

1840-Underground Conduit 5,172,875 5,513,666 340,791 5,666,361 152,695 6,019,452 353,091 6,222,452 203,000 6,481,952 259,500 

1845-Underground Conductors and Devices 13,312,127 14,122,014 809,888 14,627,240 505,226 15,287,819 660,579 15,450,319 162,500 15,971,319 521,000 

Sub-Total-Poles and Wires 32,254,331 36,484,795 4,230,464 38,167,537 1,682,742 41,965,151 3,797,614 44,109,150 2,143,999 46,460,150 2,351,000 

Line Transformers 

1850-Line Transformers 11,015,915 12,274,284 1,258,369 13,192,806 918,522 13,870,225 677,419 14,528,725 658,500 15,179,725 651,000 

Sub-Total-Line Transformers 11,015,915 12,274,284 1,258,369 13,192,806 918,522 13,870,225 677,419 14,528,725 658,500 15,179,725 651,000 

Services and Meters 

1855-Services 3,566,982 4,135,467 568,485 4,376,000 240,533 4,592,275 216,275 4,820,275 228,000 5,040,275 220,000 

1860-Meters 2,956,441 3,257,582 301,141 3,343,951 86,369 3,429,828 85,877 3,504,828 75,000 3,524,828 20,000 

1861-Smart Meters 50,000 (50,000) 

Sub-Total-Services and Meters 6,573,423 7,393,049 819,626 7,719,951 326,902 8,022,103 302,152 8,325,102 302,999 8,565,102 240,000 

General Plant 

1908-Buildings and Fixtures 75,176 186,359 111,183 337,712 151,353 389,838 52,126 553,746 163,908 653,746 100,000 

1910-Leasehold Improvements 21,798 21,798 21,798 21,798 21,798 0 21,798 

Sub-Total-General Plant 96,974 208,157 111,183 359,510 151,353 411,636 52,126 575,544 163,908 675,544 100,000 

IT Assets 

1920-Computer Equipment - Hardware 705,048 766,734 61,687 849,823 83,089 883,757 33,934 928,757 45,000 953,757 25,000 

1921-Computer Equipment 

1921-Computer Equipment - Hardware post March 22, 2005 

1925-Computer Software 378,650 417,671 39,022 426,847 9,176 454,162 27,315 479,162 25,000 504,162 25,000 

Sub-Total-IT Assets 1,083,697 1,184,405 100,708 1,276,670 92,265 1,337,919 61,249 1,407,919 70,000 1,457,919 50,000 

Equipment 

1915-Office Furniture and Equipment 326,528 331,792 5,264 331,792 331,792 331,792 0 331,792 

1930-Transportation Equipment 2,177,201 2,164,274 (12,927) 2,256,201 91,927 2,562,270 306,069 2,917,270 355,000 3,217,270 300,000 

1935-Stores Equipment 36,199 36,199 36,199 36,199 36,199 0 36,199 

1940-Tools, Shop and Garage Equipment 539,298 613,367 74,070 641,152 27,785 696,644 55,492 756,644 60,000 791,644 35,000 

1945-Measurement and Testing Equipment 13,413 13,413 13,413 13,413 13,413 (0) 13,413 

1950-Power Operated Equipment 

1955-Communication Equipment 103,582 106,166 2,585 106,528 362 106,528 106,528 (0) 106,528 

1960-Miscellaneous Equipment 7,842 7,842 7,842 7,842 

Sub-Total-Equipment 3,196,220 3,265,211 68,991 3,385,285 120,074 3,754,688 369,403 4,169,688 415,000 4,504,688 335,000 

Other Distribution Assets 

1825-Storage Battery Equipment 

1970-Load Management Controls - Customer Premises 138,310 76,842 (61,468) 117,417 40,575 117,417 117,417 0 117,417 

1975-Load Management Controls - Utility Premises 127,702 127,702 127,702 127,702 127,702 0 127,702 

1980-System Supervisory Equipment 196,821 206,424 9,603 226,882 20,458 257,006 30,124 277,006 20,000 297,006 20,000 

1985-Sentinel Lighting Rental Units 

1990-Other Tangible Property 

1995-Contributions and Grants - Credit (1,384,370) (2,411,290) (1,026,920) (3,166,416) (755,126) (3,578,326) (411,910) (3,938,326) (360,000) (4,328,326) (390,000) 

1996-Hydro One S/S Contribution 

Sub-Total-Other Distribution Assets (1,049,240) (2,000,322) (951,082) (2,694,415) (694,093) (3,076,201) (381,786) (3,416,201) (340,000) (3,786,201) (370,000) 

GROSS ASSET TOTAL 56,920,451 62,593,542 5,673,091 65,198,393 2,604,851 70,067,246 4,868,853 73,469,244 3,414,406 76,826,244 3,357,000 

The 2006 board approved total is not the same as the 2004 actual gross asset total per Table 1 in Tab 2, 

Schedule 1 as the board approved total consists of the average of 2003 and 2004 actual gross asset figures.


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



1 

2 

3 

VARIANCE ANALYSIS ON FIXED ASSETS BY PROJECT: 

The Fixed Asset Variances are provided below for year over year project cost increases or 

decreases of $50,000. 

4


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



1 

2 

3 

4 

5 

Capital Assets by Project 


Uniform System of Accounts # 

1830 1835 1840 1845 1850 1855 1860 1908 1915 1920 1925 1930 1940 1980 1995 

Project 

Buildings & Office Furniture & 

Contributed 

Poles & Fixtures O/H Conductor U/G Conduit U/G Conductor Transformers Services Meters Fixtures 

Eqpt Hardware Software Transportation Tools SCADA Capital Total 

Stratford-M.S. #4 - Conversion 7,580 5,930 2,612 16,122 

Stratford-M.S. #5 - Conversion 122,128 131,411 5,850 166,013 71,055 496,457 

St. Marys-Substation Conversion 104,744 135,284 13,635 1,751 18,991 274,405 

Hensall-Substation Conversion 69,258 242,096 31,078 342,432 

Stratford-Erie-Lorne to Gibb-Rebuild 171,960 185,275 16,917 40,064 414,216 

Seaforth-Main St. Rebuild 5,022 1,065 29,975 36,062 

Hensall-Nelson St. Insulator upgrade 6,763 6,763 

Stratford-Gibb Road Extension 31,672 46,017 77,689 

Stratford-Jennann Subdivision 22,311 6,704 29,015 

Stratford-Huron & O'Loane Relocation 45,476 44,339 14,566 8,291 112,672 

Fault Indicators 756 756 

New Transformers 183,167 183,167 

Customer Driven Capital 23,163 50,031 49,489 56,034 12,747 57,897 249,360 

New/Upgraded Services 99,802 99,802 

Distribution Meters (inc. wholesale meters) 281,410 281,410 

SCADA enhancements 12,299 12,299 

Tools & Equipment 24,902 24,902 

Lands & Buildings 34,284 34,284 

Furniture & Equipment 2,792 2,792 

Vehicles & Trailers 223,260 223,260 

Hardware Upgrades 27,975 27,975 

Software Upgrades 21,100 21,100 

Contributed Capital -492,361 -492,361 

Subtotal 575,980 847,901 68,974 282,614 360,778 202,669 281,410 34,284 2,792 27,975 21,100 223,260 24,902 12,299 -492,361 2,474,578 

Capitialized Subdivision Asset Transfers 33,996 9,240 19,246 19,875 82,357 

TOTAL 575,980 847,901 102,970 291,854 380,025 222,544 281,410 34,284 2,792 27,975 21,100 223,260 24,902 12,299 -492,361 2,556,935 

Totals per G.L. 575,980 847,901 102,970 291,854 380,025 222,544 281,410 34,284 2,792 27,975 21,100 223,260 24,902 12,299 (492,361) 2,556,935 

6 

7 

8 

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19 

20 

21 

22 

23 

Stratford MS#4 Conversion (2004, 2005, 2006, 2007) 

This municipal substation was built in 1956 to supply the local area with 4 kV 

distribution. It was upgraded in 1968 to add capacity. The station was at end of life, and 

the majority of the 4 kV distribution system was also at end of life. Therefore, rather 

than replace both the station and distribution with 4 kV equipment, it was decided to 

convert the area to 27.6 kV to eliminate the need for the station and reduce system losses. 

This project spanned several USofA accounts, and was completed over a four year period 

from 2004 to 2007. The sections completed each year were selected based on physical 

condition, ease of conversion, and overall risk in relation to other sections of FHI’s 

assets. As each street was converted to 27.6 kV, it was immediately put into service. 

Stratford MS#5 Conversion (2004, 2005) 


distribution. The station was at end of life, and the majority of the 4 kV distribution 

system was also at end of life. Therefore, rather than replace both the station and 

distribution with 4 kV equipment, it was decided to convert the area to 27.6 kV to


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



1 

2 

3 

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44 

eliminate the need for the station and reduce system losses. This project spanned several 

USofA accounts, and was completed over a two year period in 2004 and 2005. As each 

street was converted to 27.6 kV, it was immediately put into service. 

St Marys MS Conversion (2004, 2005, 2006, 2007) 

This municipal substation was built in the mid-1950s to supply the local area with 4 kV 



distribution with 4 kV equipment, it was decided to convert the area to 13.8 kV to 


USofA accounts, and was completed over a four year period from 2004 to 2007. The 

sections completed each year were selected based on physical condition, ease of 

conversion, and overall risk in relation to other sections of FHI’s assets. As each street 

was converted to 13.8 kV, it was immediately put into service. 

Hensall MS Conversion (2004, 2005, 2006, 2007) 


distribution. Previously the town was supplied directly by Hydro One at 8 kV, but the 8 

kV system was insufficient to supply the growing load and the station was constructed. 

Most of the distribution system was at end of life when Festival Hydro acquired the 

assets in 2000, and it became necessary to replace the aging infrastructure. It was 

recognized at the time that this substation represented a high risk to the company, since a 

failure at the substation would result in a prolonged outage to 75% of the town, since the 

only backup was an 8 kV feeder from Hydro One with limited capacity. Therefore, it 

was decided that the distribution system would be converted to 27.6 kV to reduce the 

possibility of a prolonged outage and plan for the eventual removal of the substation 

when it reached end of life in approximately 2011. However, in late 2004, the substation 

transformer failed and required the use of a mobile unit rented from Hydro One. In early 

2005 a used replacement transformer was purchased from Hydro One but the plan to 

convert the system to 27.6 kV over a 10 year period was adjusted to be completed by 

2007. This project spanned several USofA accounts, and was completed over a four year 

period from 2004 to 2007. The sections completed each year were selected based on 

physical condition, ease of conversion, and overall risk in relation to other sections of 

FHI’s assets. As each street was converted to 27.6 kV, it was immediately put into 

service. 

Stratford – Erie – Lorne to Gibb – Rebuild 

This project replaced poles, crossarms and insulators that had reached end of life. The 

primary conductors were also replaced at the same time to accommodate planned growth 

in the area (several new factories scheduled to open in 2004, 2005, and 2006) and to 

allow for a feeder tie between the M2 and M3 feeders to improve reliability.


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



1 

2 

3 

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5 

6 

7 

8 

9 

10 

11 

12 

13 

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15 

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27 

28 

29 

30 

31 

32 

33 

34 

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36 

37 

38 

39 

40 

41 

42 

43 

Seaforth – Main Street – Rebuild 

This project replaced an existing overhead line that had reached end of life and was 

identified as a possible safety concern due to proximity to buildings. To reduce the risk 

of contact with the overhead lines, this section was placed underground. 

Hensall – Nelson Street – Insulator Upgrade 

This project replaced porcelain insulators with polymer insulators. The porcelain 

insulators had been identified by the manufacturer as potentially failing prematurely and 

were considered a safety risk. 

Stratford – Gibb Road – Extension 

This project extended an existing 27.6 kV feeder to connect a new industrial customer 

and create a feeder tie. A net present value calculation (as per the DSC) was conducted 

and no capital contribution from the customer was required. 

Stratford – Jennann Subdivision 

This project was a developer driven new residential subdivision. The costs are for 

primary cable terminations and service connections. A deposit from the developer was 

taken and later refunded (in 2008) after completing the final net present value calculation 

(as per the DSC). 

Stratford – Huron and O’Loane – Relocation 

This project was a relocation requested by the Ministry of Transportation (MTO) and 

City of Stratford to accommodate an intersection upgrade. Partial cost recovery (50% of 

labour and equipment) was obtained. 

Fault Indicators 

This project was to test devices that would assist in locating faults on the overhead 

system, to improve reliability by quickly identifying the affected area. This project 

became a multi-year project as various devices were tested over a period of time. 

New Transformers 

This line item represents the purchase of new transformers for all projects during the 

year. The labour associated with installation is included in the project cost.


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

26 

27 

28 

29 

30 

31 

32 

33 

34 

35 

36 

37 

38 

39 

40 

Customer Driven Capital 

This line item represents 52 small projects completed during the year that were triggered 

by customer requirements – this includes new commercial and industrial service 

connections (which may or may not require new primary extensions and transformation), 

line relocations (requested by MTO or City), single pole relocations (to accommodate 

new or expanded driveways), new subdivisions (which may or may not require line 

extensions), in-fill projects (which typically require new or upgraded transformers), and 

make-ready work for third party attachments. In some cases, portions of the project cost 

are recoverable as a connection fee or capital contribution as determined by the Net 

Present Value calculation (as per the DSC). The average cost of these projects was 

$4,544 and the largest individual project was $35,000. 

New/Upgraded Services 

This line item represents all new services and service upgrades completed during the year 

due to customer requests. Typically, two thirds of these requests are associated with new 

residential subdivisions that fill in over a two to three year period. The remaining 

requests are split between commercial service upgrades and various residential service 

upgrades. 

Distribution Meters 

Most of the cost in this category for 2004 is for upgrades to seven wholesale meter points 

at an average cost of $35,000 to meet the requirements of the IESO. The remaining 

expenses are for planned meter changes that have reached seal expiry, upgraded meters 

triggered by customer demand, or new meters for new customers. 

SCADA Enhancements 

This project is to upgrade various hardware and software components associated with the 

SCADA system to improve reliability, security, and usability, and to add new data points 

or functionality. 

Tools and Equipment 

This line item represents various tools and equipment purchased during the year, 

primarily to replace existing devices that have reached end of life or failed beyond repair.


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

26 

27 

28 

29 

30 

31 

32 

33 

34 

Lands and Buildings 

This project was to replace an existing HVAC unit in the Stratford Service Centre that 

was at end of life and the replacement unit was much more efficient than repairing the 

existing unit. 

Furniture and Equipment 

This line item represents various office furniture and equipment replacements. 

Vehicles and Trailers 

One small vehicle (minivan) at end of life (1994 vintage) was replaced with a new 

vehicle (pickup truck). Two single bucket trucks at end of life (1991 vintage) were 

replaced with one new single bucket truck. 

Hardware Upgrades (Computer) 

This line item represents various computer upgrades required during the year to replace 

existing units at end of life or that have failed beyond repair. 

Software Upgrades 

This line item represents various computer software upgrades required during the year as 

part of maintenance agreements (e.g. AutoCad) or to update to newer versions of existing 

software that offer greater flexibility and improved performance. 

Capitalized Subdivision Asset Transfers 

This represents the transfer of assets provided by the customer which were assumed by 

Festival Hydro upon the completion of the economic evaluation. During the year, 

Festival Hydro assumed the assets associated with one residential subdivision in the City 

of Stratford for a total of $82,357.


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 


2005 


1820 1830 1835 1840 1845 1850 1855 1860 1908 1915 1920 1925 1930 1940 1955 1970 1980 1995 

Project 

Buildings & Office Furniture & 

Communication Load Management 

Contributed 

Dist. Stn. Equipment Poles & Fixtures O/H Conductor U/G Conduit U/G Conductor Transformers Services Meters Fixtures 

Eqpt Hardware Software Transportation Tools Equipment 

Controls SCADA Capital Total 

Stratford-M.S. #1 - Conversion 23,730 35,029 6,369 2,750 $67,878 

Stratford- M.S. #4 Conversion 43,529 56,296 33,541 $133,366 

Stratford-M.S. #5 - Conversion 99,621 109,744 37,629 17,781 $264,775 

St. Marys- Substation Conversion 219,683 195,835 60,288 125,833 60,017 $661,656 

Hensall Substation Rebuild 48,271 $48,271 

Hensall-Substation Conversion 58,485 107,982 9,625 795 20,836 $197,723 

Stratford-College St Rebuild 7,008 3,598 $10,606 

Stratford-Insulator Upgrade 5,496 30,555 $36,051 

St. Marys-James St S - Conversion 5,046 $5,046 

Seaforth-George St. Rear Yard Conv. 11,431 14,910 $26,341 

Fault Indicators 2,143 $2,143 

Hensall & Seaforth-Neutral Installations 25,207 $25,207 

New Transformers 221,291 $221,291 

Customer Driven Capital 96,451 58,526 28,892 131,888 65,809 $381,566 

New/Upgraded Services 151,823 $151,823 

Distribution Meters (inc. wholesale meters) 131,367 $131,367 

SCADA enhancements 98,897 1,363 $100,260 

Tools & Equipment 39,514 $39,514 

Lands & Buildings 43,064 $43,064 

Office Furniture & Equipment 2,195 $2,195 

Vehicles & Trailers 319,129 $319,129 

Communication Equipment 2583.79 $2,584 

Hardware Upgrades 20,443 $20,443 

Software Upgrades 17,375 $17,375 

Contributed Capital -376,053 -$376,053 

Subtotal 48,271 521,905 579,931 142,334 363,856 425,623 151,823 131,367 43,064 2,195 20,443 17,375 319,129 39,514 2,584 98,897 1,363 -376,053 2,533,621 

Capitialized Subdivision Asset Transfers 21654 23660 42100 63375 150,789 

TOTAL 48,271 521,905 579,931 163,988 387,516 467,723 215,198 131,367 43,064 2,195 20,443 17,375 319,129 39,514 2,584 98,897 1,363 -376,053 $2,684,410 

Totals per G.L. 48,271 521,905 579,931 163,988 387,516 467,723 215,198 131,367 43,064 2,195 20,443 17,375 319,129 39,514 2,584 98,897 1,363 (376,053) 2,684,410 

Stratford MS#1 Conversion (2005, 2007, 2008, 2009, 2010) 

This municipal substation was rebuilt in 1962 to supply the local area with 4 kV 

distribution. It was upgraded in 1979 to add capacity. The station is approaching end of 

life, and the majority of the 4 kV distribution system is also approaching end of life. 

Therefore, rather than replace both the station and distribution with 4 kV equipment, it 

was decided to convert the area to 27.6 kV to eliminate the need for the station and 

reduce system losses. This project will span several USofA accounts, and will be 

completed over a six year period from 2005 to 2010. The sections completed each year 

were selected based on physical condition, ease of conversion, and overall risk in relation 

to other sections of FHI’s assets. This station supplies much of the downtown core along 

with a relatively large residential area, making it more difficult to work on particularly 

during summer months that are the height of tourist season in Stratford. Therefore, it was 

decided to spread this project across six years rather than three or four to minimize the 

impact each year to the downtown core. As each street was converted to 27.6 kV, it was 

immediately put into service.


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



1 

2 

3 

4 

5 

6 

7 

8 

9 

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This project is year 2 of a four year municipal substation conversion project. See 2004 

write-up for details. 


This project is year 2 of a two year municipal substation conversion project. See 2004 





Hensall Substation Rebuild 

This project replaced the failed substation transformer with a used transformer purchased 

from Hydro One. Some alterations to the existing station were required to fit the 

replacement transformer. 




Stratford – College Street – Rebuild 

This project was a rebuild of a section of 27.6 kV that was at end of life. Only poles and 

transformers were changed. 

Stratford – Insulator – Upgrade 

This project replaced porcelain insulators on the M2 feeder with polymer insulators. The 

porcelain insulators had been identified by the manufacturer as potentially failing 

prematurely and were considered a safety risk. 

St Marys – James St S – Conversion 

This project converted a small section of overhead primary to underground, at the request 

of a customer who required distribution poles to be relocated. The customer installed all 

conduit and FHI supplied the primary conductors.


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



1 

2 

3 

4 

5 

6 

7 

8 

9 

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42 

43 

44 

Seaforth – George St – Rear Yard Conversion 

This project relocated 27.6 kV overhead primary from the rear yards of residential homes 

to the front yard. The distribution system in this area was at end of life and represented a 

safety hazard and difficult access for maintenance and repairs. 


This project was a continuation of the project started in 2004 to test overhead fault 

indicators. 

Hensall and Seaforth – Neutral Installations 

This project installed a neutral (4 th wire) for the 27.6 kV supply to Hensall and Seaforth. 

The neutral was required in Hensall to facilitate the conversion to 27.6 kV, and it was 

required in Seaforth to install two new wholesale meter points and to allow for the 

possibility of future conversion to 27.6 kV. 



year. The labour associated with installation is included in the project cost. 











$8554 and the largest individual project was $21,000. 






upgrades.


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



1 

2 

3 

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8 

9 

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Most of the cost in this category for 2005 is for upgrades to four wholesale meter points 

at an average cost of $25,000 and one spare unit to meet the requirements of the IESO. 

The remaining expenses are for planned meter changes that have reached seal expiry, 

upgraded meters triggered by customer demand, or new meters for new customers. 




or functionality. In 2005, the majority of this work was the installation of a load 

management system to control electric water heaters and central air conditioners to 

reduce system demand (most of the cost for this was recovered through the third tranche 

CDM funding). 



primarily to replace existing devices that have reached end of life or failed beyond repair. 


This line item represents five small projects – a lighting upgrade to the Stratford Service 

Centre (to improve energy efficiency), the replacement of the roof on the garage portion 

of the Stratford Service Centre (over 30 years old), additional ventilation added to the 

garage to improve air quality, the replacement of flooring in a section of the Stratford 

Administration Building (tiles had lifted creating trip hazard), and the replacement of the 

furnace in the residential building (150 Wellington) that was at end of life and beyond 

reasonable repair. 





vehicle (minivan). Two radial boom derrick (RBD) trucks (one 1988 at end of life and 

one 1999 with a de-rated boom) were replaced with one new radial boom derrick (RBD) 

truck. Two small trailers at end of life were also replaced with new trailers.


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

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20 












of Stratford and two residential subdivisions in the Town of St. Marys for a total of 

$150,789.


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



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2 

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9 

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2006 


1830 1835 1840 1845 1850 1855 1860 1908 1915 1920 1925 1930 1940 1970 1980 1955 

Project 

Buildings & Office Furiture & 

Contributed 

Poles & Fixtures O/H Conductor U/G Conduit U/G Conductor Transformers Services Meters Fixtures Equipment Hardware Software Transportation Tools Load Management SCADA Capital Total 

Stratford-M.S. #4 Conversion 226,410 147,867 8,039 61,673 73,601 517,590 

St. Marys-Substation Conversion 195,682 158,521 22,726 32,552 409,481 

Hensall Substation Conversion 158,659 111,878 8,032 12,242 34,251 325,062 

Stratford-Insulator Upgrade 1,817 1,817 

Stratford-Delamere Ave. LBS 19,519 19,519 

Stratford-Fault Indicators 4,186 4,186 

Stratford-Automated Switches (2) 122,451 122,451 




Distribution Meters 29,069 29,069 




Office Furntiture & equipment 1,674 1,674 




Load Management 105,646 105,646 


Subtotal 668,595 597,468 82,322 256,069 549,340 199,640 29,069 50,976 1,674 27,255 11,097 41,673 23,803 105,646 2,091 -404,686 2,242,032 

Capitialized Subdivision Asset Transfers 42996 20540 51400 42375 0 157,311 

TOTAL 668,595 597,468 125,318 276,609 600,740 242,015 29,069 50,976 1,674 27,255 11,097 41,673 23,803 105,646 2,091 -404,686 2,399,343 

Totals per G.L. 668,595 597,468 125,318 276,609 600,740 242,015 29,069 50,976 1,674 27,255 11,097 41,673 23,803 105,646 2,091 (404,686) 2,399,343 

2,399,343 










Stratford – Insulator – Upgrade 

This project replaced the remaining porcelain insulators on the M2 feeder with polymer 

insulators. The porcelain insulators had been identified by the manufacturer as 

potentially failing prematurely and were considered a safety risk.


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



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This project was a continuation of the project started in 2004 to test overhead fault 

indicators. 

Stratford – Automated Switches 

This project was initiated to improve the reliability to the worst performing feeder in 

Stratford that had industrial loads located at the end of the feeder. The feeder was 

experiencing between two to four sustained outages every year lasting 20 minutes to two 

hours. This project installed two automated switches that would transfer this section of 

the feeder to an alternate supply in the event of a sustained outage. This project was 

considered a pilot project to determine if this type of automated switching would improve 

the reliability of the feeder. As of June 2009, this section of the feeder has only had one 

sustained outage (greater than one minute) since these two automated switches were 

placed into service. 



year. The labour associated with installation is included in the project cost. 











$16,800 and the largest individual project was $77,000 for a short line extension and new 

service for the Stratford Recreation Complex (based on the NPV calculation, no capital 

contribution was required). 






upgrades.


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



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Most of the cost in this category for 2006 is for planned meter changes that have reached 

seal expiry, upgraded meters triggered by customer demand, or new meters for new 

customers. 









This line item represents four small projects – the replacement of the loading dock at the 

Stratford Service Centre (concrete deteriorated after 50 years of service), the replacement 

of one of the five HVAC units at the Stratford Administration Building (end of life and 

beyond reasonable repair), the replacement of flooring in the Stratford Administration 

Building (tiles had lifted creating a trip hazard, and worn carpets), and repainting the 

walls at the Stratford Administration Building. 




One small vehicle (pickup truck) at end of life (1996 vintage) was replaced with a new 

vehicle (pickup truck). One small trailer at end of life was also replaced with a new 

trailer. 



existing units at end of life or that have failed beyond repair.


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



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Load Management 

This line item represents the new load controllers added to the system to control electric 

water heaters and central air conditioners as part of the CDM program. 





of Stratford and one residential subdivision in the Town of St. Marys for a total of 

$157,311.


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



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2007 


1808 1830 1835 1840 1845 1850 1855 1860 1908 1920 1925 1930 1940 1955 1970 1980 1995 

Project 

Buildings - 

Buildings & 

Commuincation 

Contributed 

Substations Poles & Fixtures O/H Conductor U/G Conduit U/G Conductor Transformers Services Meters Fixtures Hardware Software Transportation Tools Equipment Load Management SCADA Capital Total 

Stratford-M.S. #1 Conversion 38,056 7,461 45,517 

Stratford-M.S. #2 Conversion 135,995 94,920 25,262 25,037 281,214 


St. Marys-Substation Conversion 143,474 112,899 15,140 19,295 290,808 

Hensall Substation Conversion 92,947 105,202 20,685 39,075 54,013 311,922 

Buildings - Substations 0 

Stratford-Gibb Road Extension 21,007 26,760 47,767 

St. Marys-Water St. N. Tie Circuit 2,521 5,035 3,335 12,158 23,049 







Lands & Buildings (incl. roof replacement) 163,761 163,761 


Hardware Upgrades (incl. new phone system) 83,089 83,089 


Communication Equipment 362 362 

Load Management Equipment 40576 40,576 


Subtotal 0 568,031 456,789 56,060 449,554 829,585 179,154 86,369 163,761 83,089 9,176 296,125 34,157 362 40,576 20,459 -755,127 2,518,120 

Capitialized Subdivision Asset Transfers 96635 55671 90609 61379 0 304294 

TOTAL 0 568,031 456,789 152,695 505,225 920,194 240,533 86,369 163,761 83,089 9,176 296,125 34,157 362 40,576 20,459 -755,127 2,822,414 

Totals per G.L. 12,408 568,031 456,789 152,695 505,225 920,195 240,533 86,369 151,353 83,089 9,176 296,124 34,157 362 40,576 20,459 (755,127) 2,822,415 


This project is year 2 of a five year municipal substation conversion project. See 2005 






distribution with 4 kV equipment, it was decided to convert the area to 27.6 kV to 


USofA accounts, and was completed over a two year period in 2007 and 2008. As each 

street was converted to 27.6 kV, it was immediately put into service. 






write-up for details.


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



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Stratford – Gibb Road – Extension 

This project extended an existing 27.6 kV feeder to connect a new industrial customer. A 

net present value calculation (as per the DSC) was conducted and no capital contribution 

from the customer was required. 

St Marys – Water Street N – Tie Circuit 

This project will create a feeder tie between the St Marys M2 and M4 circuits to improve 

reliability and operating flexibility. 



year. The labour associated with installation is included in the project cost. The amount 

is higher than previous years due to a significant increase in customer driven projects 

requiring new transformers. 











$14,500 and the largest projects were $152,000 for a line relocation to facilitate a new 

residential subdivision (based on the NPV calculation, a capital contribution was 

required), and $122,000 for a new residential subdivision (based on the NPV calculation, 

a capital contribution was required but may be refunded in 2009 if there is sufficient 

growth).


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



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upgrades. 


Included in this line item are the cost of one wholesale meter point upgrade to meet IESO 

requirements for $24,000, and the replacement of a group of interval meters that are at 

end of life for $30,000. The remainder is for planned meter changes that have reached 


customers. 




or functionality. In 2007, this included approximately $20,000 in enhancements to add 

the automated switches to the SCADA system so they could be remotely monitored and 

controlled. 





This line item represents the replacement of the roof of the Stratford Administration 

Building that had reached end of life (47 years old) for $149,000, and the completion of 

flooring replacement in the Stratford Administration Building started in 2006. 


One small vehicle (pickup truck) at end of life (1998 vintage) was replaced with a new 

vehicle (pickup truck). One double bucket truck at end of life (1994 vintage) was 

replaced with a new double bucket truck.


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



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existing units at end of life or that have failed beyond repair. This includes the 

replacement of the telephone system at end of life (1996 vintage) for $85,000, with a new 

system that integrates with the computer system and offers interactive voice response 

(IVR). 





Load Management 

This line item represents the new load controllers added to the system to control electric 

water heaters and central air conditioners as part of the CDM program. 





of Stratford and one residential subdivision in the Town of St. Marys for a total of 

$304,294.


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



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2008 


1830 1835 1840 1845 1850 1855 1860 1908 1920 1925 1930 1940 1960 1980 1995 

Project 

Buildings & 

Miscealleous 

Contributed 

Poles & Fixtures O/H Conductor U/G Conduit U/G Conductor Transformers Services Meters Fixtures Hardware Software Transportation Tools Equipment SCADA Capital Total 

Stratford-M.S. #1 Conversion 100,798 7,843 92,806 57,248 28,181 286,876 

Stratford-M.S. #2 Conversion 79,352 150,592 23,954 253,898 

Zurich-Substation Conversion 109,275 188,185 40,788 48,306 65,221 451,775 

Hensall-York St. LBS (isolation pnt) 1,583 20,738 22,321 

St. Marys-Water St. Ph1 Rebuild 100,911 61,361 9,975 8,710 8,727 189,684 

St. Marys-Reinsulate Poles 9M4 Feeder 57,290 57,290 

St. Marys-Ingersoll St N - Rebuild 3,751 2,361 6,112 

St. Marys-Thames Rd. Feeder Tie 15,756 21,478 2,198 2,577 42,009 

St. Marys-Jones/Elgin-Rear Lot Conv. 11,783 7,887 19,670 

St. Marys-Reclosers 101,068 101,068 












Miscellaneous Equipment 7842 7,842 


Subtotal 642,076 913,443 109,007 374,286 618,509 176,254 85,876 52,126 33,934 27,315 491,061 55,492 7,842 30,123 -411,910 3,205,434 

Capitialized Subdivision Asset Transfers 114434 27806 58910 40020 241,170 

CICA Handbook Sect xxxx Spare Parts Inv 259302 194476 129650 64825 648,253 

Reclassification of Disposals to Capital 774648 193662 968,310 

TOTAL 901,378 1,882,567 353,091 660,579 677,419 216,274 85,876 52,126 33,934 27,315 491,061 55,492 7,842 30,123 -411,910 5,063,167 

Totals per G.L. 901,377 1,882,567 353,091 660,579 677,419 216,274 85,876 52,126 33,934 27,315 491,061 55,492 7,842 30,123 (411,910) 5,063,167 







Zurich MS Conversion (2008, 2009) 

This project is similar to the Hensall conversion project (8 kV distribution system with 

limited backup from Hydro One), although the substation is newer – constructed in 1986. 

When the Hensall substation transformer failed in 2004, it became apparent that an 

isolated pocket of 8 kV distribution with only a single source of supply (27.6 kV to 8 kV 

substation) posed a real risk to FHI. Therefore, it was decided that the Zurich system 

should be converted to 27.6 kV even though the substation had at least another 10 to 15 

years of useful life. The condition of the distribution system was similar to Hensall – at


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



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or approaching end of life – therefore the distribution was scheduled for conversion over 

a two year period. As with other conversion projects, this project will span several 

USofA accounts and as each street is converted to 27.6 kV, it will be placed into service. 

Hensall – York St – LBS Isolation Point 

This project installed a load break switch (LBS) on York Street to allow the Town of 

Hensall to be isolated from the rest of Hydro One’s distribution system in the event there 

is a fault on the system in Hensall that prevents restoration of the Hydro One feeder, or to 

allow FHI crews to work on the Hensall system de-energized if necessary. Previously, 

the only way to isolate the Hensall system was to lift single phase line taps which created 

unbalanced phase problems for the three phase customers in Hensall, and required a two 

person crew in a bucket truck. The new switch opens all three phases simultaneously and 

can be operated by one person from the ground. 

St Marys – Water St – Rebuild (2008, 2009) 

This two year project will replace infrastructure (poles, wires, transformers) that has 

reached end of life and poses a reliability and possible safety risk. This project and the 

Reinsulated Poles project contributed to the improvement in reliability of the M4 Feeder. 

St Marys – Reinsulate Poles – M4 Feeder 

This feeder (St Marys M4) has been identified as one of the top 3 worst performing 

feeders in FHI’s area several years. It was identified that many of the outages were due 

to inadequate clearance between the 13.8 kV overhead wires and the concrete poles. This 

project installed fiberglass insulator extensions that increased the clearances to the poles. 

It was anticipated that this project and the Water Street rebuild project should reduce the 

frequency and duration of outages on this feeder. Following completion of this project 

and the first phase of the Water Street project, feeder lockouts on the feeder dropped from 

5 in 2006 and 2007, to only 1 in 2008. The number of momentary outages also dropped 

from 41 and 34 in 2006 and 2007, to only 16 in 2008. SAIDI dropped from 4.93 and 3.1 

in 2006 and 2007, to 0.19 in 2008. SAIFI dropped from 5.35 and 6.4 in 2006 and 2007, 

to 1.17 in 2008. 

St Marys – Ingersoll St N – Rebuild 

This small project was a rebuild to a small section of the distribution feeder that was at 

end of life and supplied a farm service. 

St Marys – Thames Rd – Feeder Tie 

This project rebuilt and extended a portion of a feeder to create a feeder tie point to allow 

the St Marys M4 feeder to be re-routed in the west ward, to improve operating flexibility


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



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and enable faster restoration. This tie point may become part of a future automated 

restoration system by installing an automated switch at this location. The infrastructure 

on this street was at end of life and was completely rebuilt. 

St Marys – Jones/Elgin – Rear Lot Conversion 

This project relocated secondary services from the rear lot of homes to the front lot to 

improve access and remove deteriorated infrastructure. 

St Marys – Reclosers 

This project installed three reclosers in St Marys to improve the reliability of the St 

Marys M2 feeder and M4 feeder. The reclosers divide the feeder into smaller sections 

and prevent the entire feeder from experiencing an outage. Once operational, it is 

expected that the one recloser on the M2 feeder will reduce sustained outages by 25% 

(current 5 year average is 13,770 customer minutes per year, expect new average to be 

10,328 per year), and will reduce momentary outages by 25% (current 5 year average is 8 

per year, expect the new average to be 6 per year). It is expected that the two reclosers 

on the M4 feeder will reduce sustained outages by 50% (current 5 year average is 220700 

customer minutes per year, expect the new average to be 110350 per year), and will 

reduce momentary outages by 50% (current 5 year average is 29 per year; expect the new 

average to be 15 per year). 


This project builds on the success of the first automated switch project installed in 2007. 

In 2008, two pairs of automated switches (four total) were added to the system. One pair 

(team) was installed on the Stratford M8 feeder which has the two largest industrial 

customers. This team will automatically transfer this industrial/commercial section to an 

alternate feeder if the feeder experiences and outage. While the M8 feeder is statistically 

one of the better performing feeders with less than two feeder lockouts per year on 

average, any outage to this feeder affects the two largest industrial customers and the 

entire east end commercial district. It is expected that these switches will reduce the 

number of sustained outages from an average of two per year to less than one. The 

second pair of switches was installed on the Stratford M3 feeders which have been 

identified as the worst performing feeder for several years. The area selected was the 

south-west industrial area that has eight medium sized industrial customers and one large 

residential subdivision. These switches (along with two additional switches to be 

installed in 2009) are expected to reduce the sustained outages to this area from an 

average of four per year to one or fewer.


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



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is higher than previous years but consistent with the 2007 amount due to the continued 

increase in customer driven projects requiring new transformers. 











$10,270 and the largest project was $42,000 for a line extension for a new industrial 

subdivision in St Marys (based on the NPV calculation, no capital contribution was 

required). 






upgrades. 


Included in this line item are the cost of one wholesale meter point upgrade to meet IESO 

requirements for $35,000, and the replacement of a group of interval meters that are at 

end of life for $25,000. The remainder is for planned meter changes that have reached 


customers. 




or functionality. In 2008, this included approximately $30,000 in enhancements to add 

the additional automated switches to the SCADA system (so they could be remotely


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



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monitored and controlled), as well as upgrades to the firewall and router for increased 

security. 





This line item represents three main projects - the replacement of an HVAC unit at the 

Stratford Administration Building that had reached end of life for $16,000, the 

installation of motion sensors in the Stratford Service Centre and Administration 

Building to turn off unnecessary lights for $10,800, upgrading the security cameras and 

video recorder for $6,000 – and several small projects associated with the Stratford 

Service Centre. 



vehicle (minivan). One single bucket truck at end of life (1989 vintage) was replaced 

with a new single bucket truck. One panel van at end of life (1994 vintage) was replaced 

with a new panel van. The tension stringing equipment at end of life (1970s vintage) was 

replaced with new tension stringing equipment. 








Miscellaneous Equipment 

This line item is for the purchase of automated electronic defibrillators (AEDs) which 

will be taken by work crews to work sites, and will be available for use in emergencies to 

provide first response to injured workers or others in the area.


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



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This represents the transfer of assets provided by the customer which were assumed by Festival 

Hydro upon the completion of the economic evaluation. During the year, Festival Hydro 

assumed the assets associated with one residential subdivision in the City of Stratford and two 

residential subdivisions in the Town of St. Marys for a total of $241,170. 

Spare Parts Inventory Reclassification 

In 2008 spare parts totaling $648,253 were reclassified from inventory to capital assets. 

Effective January 1, 2008, FHI adopted CICA Handbook section 3031, Inventories. 

Major spare parts are to be classified as capital assets under this Handbook section as 

they are held for the development and construction of other utility capital assets. These 

assets are not amortized until put into use. This policy is being applied on a prospective 

basis. 

Asset Disposal Reclassification 

During the 2008 audit, FHI’s auditors indicated a difference in our accounting practice 

for plant disposal and retirement costs as compared to practices followed by other 

electrical utilities in the industry. FHI auditors indicated that other utilities follow the 

general industry practice of capitalizing such costs to the relevant asset account and 

amortizing these costs over the life of the new asset. In order to be consistent with the 

industry, FHI management decided to follow industry standards and adopt recognition of 

these disposal costs as asset additions. As a result, at 2008 year end, $968,310 was 

transferred from the non depreciable Asset disposal cost account to the respective 

Property, Plant and Equipment accounts.


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



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2009 


1830 1835 1840 1845 1850 1855 1860 1908 1920 1925 1930 1940 1980 1995 

Project 

Buildings & 

Contributed 

Poles & Fixtures O/H Conductor U/G Conduit U/G Conductor Transformers Services Meters Fixtures Hardware Software Transportation Tools SCADA Capital Total 


Zurich-Substation Conversion 120,000 265,000 4,000 6,000 72,000 467,000 

Stratford-Douro Ph1-Rebuild 52,000 39,000 9,000 100,000 

Stratford-Reinsulate Poles 68M3 Feeder 50,000 50,000 

Stratford-Ontario St.-Rebuild 23,000 15,500 7,000 45,500 

Stratford-Campbell Court-S/G Replacement 7,000 7,000 

Stratford-Wright Blvd Ph 1-Extension 80,000 104,000 184,000 

Stratford-Cap Banks (68M2 Feeder) 70,000 70,000 


St. Marys-Church St. - Extension 7,500 14,000 2,000 23,500 

St. Marys-Victoria St.-Rebuild 31,000 57,000 7,000 95,000 

St. Marys-Water St. Ph2 Rebuild 74,000 58,000 19,000 151,000 

St Marys-Huron St-Rear Lot Conversion 15,000 26,000 5,500 46,500 


Customer Driven Capital 110,000 75,000 100,000 75,000 40,000 400,000 





Lands & Buildings - Administration Building 57,750 57,750 

Lands & Buidlings - Service Centrte 93,750 93,750 





Subtotal 710,500 1,068,000 119,000 162,500 610,500 150,000 75,000 151,500 45,000 25,000 355,000 60,000 20,000 -360,000 3,192,000 

Capitialized Subdivision Asset Transfers 84000 48000 78000 210,000 

TOTAL 710,500 1,068,000 203,000 162,500 658,500 228,000 75,000 151,500 45,000 25,000 355,000 60,000 20,000 3,402,000 

Totals per G.L. 710,500 1,068,000 203,000 162,500 658,500 228,000 75,000 151,500 45,000 25,000 355,000 60,000 20,000 (360,000) 3,402,000 




Zurich MS Conversion (2008, 2009) 



Stratford – Douro Phase 1– Rebuild (2009, 2010) 

This project will replace a section of overhead feeder that has reached end of life. The 

project will take place over two years. The wooden poles, crossarms, transformers, and 

porcelain insulators are over 40 years old and will be replaced with new. The primary 

overhead conductors will be re-used. Portions of the secondary conductors will be 

replaced as needed (depending on physical condition). Replacing this aging


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



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infrastructure that has reached end of life will maintain the safety and reliability of this 

feeder. 

Stratford – Reinsulate Poles – 68M3 Feeder (2009, 2010) 

This feeder has been identified as the worst performing feeder for several years. Analysis 

of the outage causes indicates that animal contacts are the major cause of outages, and 

further inspection of the feeder suggests the clearance from primary conductor to pole is 

insufficient to prevent squirrel contacts. This project will begin the installation of 

fiberglass extension brackets on the insulators to increase the clearance to poles. It is 

anticipated that when this project is complete in 2010, the number of squirrel contacts 

will be reduced from an average of 8 per year to 1 or fewer. 

Stratford – Ontario Street – Rebuild 

This project will rebuild a small section of overhead feeder on Ontario Street, to replace 

infrastructure that has reached end of life. The wooden poles, crossarms, transformers, 

and porcelain insulators are over 40 years old and will be replaced with new underground 

cables and padmount transformers. The City of Stratford will fund the cost differential 

(between overhead and underground) associated with this option. 

Stratford – Campbell Court – Switchgear Replacement (2009, 2010) 

The three padmount switchgear units that supply this residential subdivision are at end of 

life (1979 vintage) and have both been identified with “hot-spots” in recent infrared 

inspections (2004, 2006). While the “hot-spots” have been repaired, the overall condition 

of the switchgear has deteriorated (barriers are brittle and tracking, internal and external 

rusting, cable terminations cracking) and poses a reliability risk. These three units will be 

replaced over the next two years (two in 2009 and one in 2010) with new or refurbished 

units. 

Stratford – Wright Blvd Ph 1 – Extension (2009, 2010) 

The City of Stratford is creating a new industrial subdivision by extending Wright Blvd. 

This subdivision will also be the location of the second transformer station that is 

expected to be required sometime between 2013 and 2020 depending on load growth. To 

service the future load in this subdivision, and accommodate the future feeders that will 

originate from the new transformer station, FHI will install poles and primary conductors 

(with room for additional circuits in the future) over a two year period. As new industrial 

customers are connected to this extension, a net present value calculation will be done to 

determine if a capital contribution is required for their portion of the feeder extension. 

The timing of this project is subject to the City of Stratford’s schedule for extending 

Wright Blvd. As of June 30, 2009, the City has indicated this project will not start until


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



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the fourth quarter of 2009 which may require a portion of this project to be deferred to 

2010, depending on when the City has completed the road base. 

Stratford – Capacitor Banks – 68M2 Feeder (2009, 2010) 

This feeder is the longest and most heavily loaded feeder in the system, and during peak 

periods, the voltage at the feeder end approaches 95% of nominal and during light load 

periods it can approach 103% of nominal. While this voltage range is within industry 

guidelines (CSA CAN3-235) of + or – 5%, industrial customers have indicated they have 

some issues dealing with the lower voltage during peak periods. The power factor of the 

feeder is around 85%, compared to 90% for the other Stratford feeders. This project will 

install capacitor banks on the feeder to improve the power factor and stabilize the 

voltage. The project will be done over two years so that the improvements from the first 

set of capacitors can be measured and evaluated to optimize the size and location of the 

capacitors for 2010. It is expected that when this project is complete in 2010, the power 

factor will be at or better than 90% and the voltage at the feeder end during peak periods 

will be 98% or better. 


This project is a continuation of the 2008 project to improve the reliability of the 

Stratford M3 feeder. Two additional automated switches will be added to the M3 feeder 

to improve the ability to transfer load to the M2 feeder if an outage occurs. Once all four 

automated switches have been installed, it is expected that this area will see a reduction in 

sustained outages from an average of 4 per year, to one or fewer. 

St Marys – Church Street – Extension 

This project will extend the feeder on Church Street a short distance to accommodate an 

expansion to a commercial service. A net present value calculation was performed and 

no capital contribution is required. 

St Marys – Victoria Street – Rebuild 

This project will replace overhead distribution that has reached end of life and poses a 

reliability risk to the main trunk of the M4 feeder. 

St Marys – Water St – Rebuild (2008, 2009) 

This is the second year of a two year project to replace infrastructure that has reached end 

of life.


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



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St Marys – Huron Street – Rear Lot Conversion 

This project will relocate distribution infrastructure from the rear lot of homes to the front 

lot to improve access and remove deteriorated infrastructure. 




is consistent with previous years. 


This line item represents an estimated 40 small projects completed during the year that 

will be triggered by customer requirements – this includes new commercial and industrial 

service connections (which may or may not require new primary extensions and 

transformation), line relocations (requested by MTO or City), single pole relocations (to 

accommodate new or expanded driveways), new subdivisions (which may or may not 

require line extensions), in-fill projects (which typically require new or upgraded 

transformers), and make-ready work for third party attachments. In some cases, portions 

of the project cost are recoverable as a connection fee or capital contribution as 

determined by the Net Present Value calculation (as per the DSC). The average cost of 

these projects is expected to be $10,000 and the largest project is expected to be $75,000 

for the installation of duct for a new large commercial development in the 4 th quarter of 

2009, with primary cable not required until 2010. 






upgrades. 


Included in this line item are the costs to replace two primary metering units (used to 

meter large customers) that have reached end of life, at a cost of $22,500 each. There are 

12 of these units in service, with 8 approaching end of life. The remaining 6 will be 

replaced over the next three years. Also included in this line item is $30,000 for the 

replacement of meters that are at end of life, meters that have reached seal expiry, 

upgraded meters triggered by customer demand, or new meters for new customers.


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



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or functionality. In 2009, this includes approximately $20,000 in enhancements to add 

the additional automated switches to the SCADA system (so they could be remotely 

monitored and controlled). 




Lands and Buildings – Administration Building 

This line item represents several small projects – the replacement of the mail insertion 

machine (for billing) at $25,000, the replacement of an HVAC unit that had reached end 

of life for $16,000, upgrading the HVAC control system for $10,000 – and several other 

small projects. 

Lands and Building – Service Centre 

This line item represents one major upgrade to the structural portion of the building, 

which has deteriorated and requires replacement. Six vertical columns have deteriorated 

extensively and a civil engineer has recommended portions of them to be replaced at a 

cost of approximately $92,000. 


Two small vehicles (one pickup truck and one sedan) at end of life (both 1996 vintage) 

will be replaced with a new. One double bucket truck at end of life (1991 vintage) will 

be replaced with a new single bucket truck (equipped with a two person bucket). One 

new utility trailer will be purchased for transporting material to work sites. 



existing units at end of life or that have failed beyond repair. This also includes the 

replacement of the AS 400 mainframe computer.


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 3 



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of Stratford and two residential subdivisions in the Town of St. Marys for a total of 

$210,000.


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 4 



ACCUMULATED DEPRECIATION: 

Table 1 


Table 1 


Description 

2006 Board 

Approved ($) 2006 Actual ($) 


Board Approved 2007 Actual ($) 

Variance from 

2006 Actual 

2008 Actual ($) 

Variance from 

2007 Actual 

2009 Bridge ($) 

Variance from 

2008 Actual 

Land and Buildings 

1805-Land 


1808-Buildings and Fixtures 825,502 895,954 70,452 929,582 33,628 955,783 26,202 989,411 33,628 1,023,039 33,628 

1905-Land 


1810-Leasehold Improvements 

Sub-Total-Land and Buildings 825,502 895,954 70,452 929,582 33,628 955,783 26,202 989,411 33,628 1,023,039 33,628 

2010 Test ($) 

Variance from 

2009 Bridge 

TS Primary Above 50 


Sub-Total-TS Primary Above 50 

DS 

1820-Distribution Station Equipment - Normally Primary below 50 kV 1,090,086 1,204,397 114,311 1,244,820 40,423 1,285,243 40,423 1,325,666 40,423 1,366,089 40,423 

Sub-Total-DS 1,090,086 1,204,397 114,311 1,244,820 40,423 1,285,243 40,423 1,325,666 40,423 1,366,089 40,423 

Poles and Wires 

1830-Poles, Towers and Fixtures 2,585,904 3,343,629 757,726 3,659,506 315,877 3,999,599 340,093 4,362,709 363,110 4,755,439 392,730 

1835-Overhead Conductors and Devices 2,826,936 3,076,023 249,087 3,234,891 158,868 4,473,460 1,238,569 4,934,182 460,722 5,424,858 490,676 

1840-Underground Conduit 2,410,898 2,963,868 552,969 3,173,097 209,229 3,391,263 218,167 3,617,549 226,286 3,850,856 233,307 

1845-Underground Conductors and Devices 6,658,959 7,994,123 1,335,163 8,535,749 541,627 9,101,206 565,457 9,673,163 571,957 10,265,960 592,797 

Sub-Total-Poles and Wires 14,482,698 17,377,643 2,894,945 18,603,243 1,225,600 20,965,528 2,362,286 22,587,603 1,622,075 24,297,113 1,709,510 

Line Transformers 

1850-Line Transformers 5,564,328 6,571,443 1,007,116 7,028,324 456,881 7,512,637 484,313 8,023,290 510,653 8,556,261 532,971 

Sub-Total-Line Transformers 5,564,328 6,571,443 1,007,116 7,028,324 456,881 7,512,637 484,313 8,023,290 510,653 8,556,261 532,971 

Services and Meters 

1855-Services 1,612,803 1,982,712 369,909 2,146,054 163,343 2,317,715 171,661 2,497,956 180,241 2,683,189 185,233 

1860-Meters 1,656,076 1,932,299 276,223 2,038,805 106,506 2,148,760 109,955 2,261,715 112,955 2,375,470 113,755 

1861-Smart Meters 

Sub-Total-Services and Meters 3,268,878 3,915,011 646,132 4,184,860 269,849 4,466,476 281,616 4,759,672 293,196 5,058,660 298,988 

General Plant 

1908-Buildings and Fixtures 6,840 30,506 23,666 41,195 10,689 53,621 12,427 71,098 17,477 88,575 17,477 

1910-Leasehold Improvements 15,259 21,798 6,539 21,798 21,798 21,798 21,798 

Sub-Total-General Plant 22,098 52,304 30,206 62,993 10,689 75,419 12,427 92,896 17,477 110,373 17,477 

IT Assets 

1920-Computer Equipment - Hardware 614,673 712,216 97,543 753,226 41,010 791,766 38,540 833,710 41,944 876,566 42,856 

1921-Computer Equipment 

1921-Computer Equipment - Hardware post March 22, 2005 

1925-Computer Software 332,074 388,799 56,725 401,678 12,880 418,891 17,212 436,883 17,992 456,400 19,517 

Sub-Total-IT Assets 946,747 1,101,015 154,268 1,154,904 53,889 1,210,656 55,752 1,270,592 59,936 1,332,965 62,373 

Equipment 

1915-Office Furniture and Equipment 283,188 309,920 26,732 315,264 5,344 319,124 3,860 322,984 3,860 326,844 3,860 

1930-Transportation Equipment 1,923,016 1,758,197 (164,819) 1,670,427 (87,770) 1,665,365 (5,062) 1,888,359 222,994 2,143,195 254,836 

1935-Stores Equipment 36,199 36,199 0 36,199 36,199 36,199 36,199 

1940-Tools, Shop and Garage Equipment 435,536 500,692 65,156 521,301 20,609 550,212 28,911 579,338 29,126 611,213 31,875 

1945-Measurement and Testing Equipment 940 5,643 4,702 7,524 1,881 9,405 1,881 11,286 1,881 13,167 1,881 

1950-Power Operated Equipment 

1955-Communication Equipment 69,854 82,775 12,920 87,973 5,199 93,172 5,199 98,317 5,145 103,462 5,145 

1960-Miscellaneous Equipment 784 784 1,568 784 2,352 784 

Sub-Total-Equipment 2,748,734 2,693,425 (55,309) 2,638,689 (54,736) 2,674,262 35,573 2,938,052 263,790 3,236,433 298,381 

Other Distribution Assets 

1825-Storage Battery Equipment 

1970-Load Management Controls - Customer Premises 30,344 30,344 54,113 23,768 78,624 24,512 103,136 24,512 127,648 24,512 

1975-Load Management Controls - Utility Premises 

1980-System Supervisory Equipment 29,216 80,440 51,224 103,128 22,688 128,829 25,701 156,530 27,701 186,231 29,701 

1985-Sentinel Lighting Rental Units 

1990-Other Tangible Property 

1995-Contributions and Grants - Credit (150,129) (359,424) (209,295) (483,782) (124,358) (626,915) (143,133) (784,448) (157,533) (957,581) (173,133) 

1996-Hydro One S/S Contribution 

Sub-Total-Other Distribution Assets (120,914) (248,640) (127,726) (326,541) (77,901) (419,462) (92,921) (524,782) (105,320) (643,702) (118,920) 

ACCUMULATED DEPRECIATION TOTAL 28,828,157 33,562,551 4,734,394 35,520,874 1,958,322 38,726,543 3,205,670 41,462,401 2,735,858 44,337,232 2,874,831


EB-2009-0263 

Exhibit 2 

Tab 2 

Schedule 5 



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VARIANCE ANALYSIS ON ACCUMULATED DEPRECIATION: 

Changes in accumulated depreciation are directly affected by changes in fixed assets due to 

additions, the removal of fully depreciated assets from the grouped asset classes, and the 

disposition of identifiable assets. The 2006 Board Approved closing balance for accumulated 

depreciation is based on FHI’s 2004 year end account balances, plus Tier 1 capital adjustments 

approved in FHI’s 2006 EDR Application. As such, the variance between 2006 Board Approved 

and 2006 Actual represents two years of depreciation changes, and in order to arrive at the 

annual impact, the variance must be divided by two. 

From 2006 Actual to the 2010 Test Year the above table shows that the change in accumulated 

depreciation, which is a representation of the depreciation expense in the year for each of the 

above accounts, has not changed materially from year to year. The change in accumulated 

depreciation is a result of capital expenditures over a four year period. Since a detailed analysis 

of capital expenditures has been provided in this Exhibit, no further explanation of the changes in 

accumulated depreciation accounts is required.


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 1 



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CAPITAL BUDGET: 

Capital Project Description 

FHI has been, and continues to be, focused on maintaining the adequacy, reliability, and quality 

of service to its distribution customers through effective capital spending. The capital spending 

by account is broken down by project in the table below. As projects can be charged to different 

OEB capital accounts, additional accounts have been identified where required. 


2010 


1830 1835 1840 1845 1850 1855 1860 1908 1920 1925 1930 1940 1980 1995 

Project 

Buildings & 

Contributed 

Poles & Fixtures O/H Conductor U/G Conduit U/G Conductor Transformers Services Meters Fixtures Hardware Software Transportation Tools SCADA Capital Total 

Stratford-M.S. #1 Conversion 88,000 140,000 6,500 55,000 38,500 328,000.00 

Stratford-M.S. #8 Conversion 10,000 70,000 10,000 90,000.00 

Stratford-Wright Blvd Ph 2-New industrial 77,500 47,500 125,000.00 

Stratford-Gibb Rd.-Tie Line 30,000 20,000 50,000.00 

Stratford-Delamere-Rebuild 116,000 90,000 18,000 224,000.00 

Stratford-Douro Ph 2-Rebuild 88,000 70,000 20,000 30,000 10,000 218,000.00 

Stratford-Campbell Court-S/G Replacement 10,000 10,000.00 

Stratford-Reinsulate Poles 68M3 Feeder 50,000 50,000.00 

Stratford-Reclosers (68M5 Feeder) 70,000 70,000.00 

Stratford-Automated Switches 190,000 190,000.00 

Stratford-Cap Banks (68M2 Feeder) 50,000 50,000.00 

St. Marys-Ontario St N Area - Rebuild 100,000 71,000 16,000 187,000.00 

St. Marys-St. George St. Rebuild 44,000 35,000 7,000 86,000.00 

St. Marys-Tracy St. Rebuild 23,000 18,500 3,500 45,000.00 

Seaforth-West William-Rear Lot Conversion 9,000 52,000 6,000 67,000.00 

Seaforth-Brantford-Rear Lot Conversion 22,000 31,000 3,000 56,000.00 

Dashwood-Helen St-Secondary Rebuild 81,000 81,000.00 

New Transformers 450,000 450,000.00 

Customer Driven Capital 115,000 85,000 125,000 85,000 45,000 455,000.00 

New/Upgraded Services 150,000 150,000.00 

Distribution Meters 20,000 20,000.00 

SCADA enhancements 20,000 20,000.00 

Tools & Equipment 35,000 35,000.00 

Lands & Buildings - Administratin Building 50,000 50,000.00 

Lands & Buidlings - Service Centrte 50,000 50,000.00 

Vehicles & Trailers 300,000 300,000.00 

Hardware Upgrades 25,000 25,000.00 

Software Upgrades 25,000 25,000.00 

Contributed Capital -390,000 (390,000.00) 

Subtotal 740,500 830,000 183,500 471,000 607,000 150,000 20,000 100,000 25,000 25,000 300,000 35,000 20,000 -390,000 3,117,000 

Capitialized Subdivision Asset Transfers 76000 50000 44000 70000 0 0 240,000.00 

TOTAL 740,500 830,000 259,500 521,000 651,000 220,000 20,000 100,000 25,000 25,000 300,000 35,000 20,000 -390,000 3,357,000 

Totals per G.L. 740,500 830,000 259,500 521,000 651,000 220,000 20,000 100,000 25,000 25,000 300,000 35,000 20,000 (390,000) 3,357,000 

3,357,000


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 1 



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The scope of this year’s portion of the project will be overhead work on Cobourg from 

Front Street to Waterloo Street, Ballantyne from North Street to Queen Street, and Water 

Street from Front Street to Waterloo Street (about 1400m total length). This will be a 

complete rebuild – new poles, insulators, transformers, and conductors – for an area of 

about 150 customers (residential and small commercial). The infrastructure in this area is 

in excess of 40 years old. 

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The purpose of this project is to replace distribution infrastructure that is at end of life, 

convert the remaining 4 kV load currently supplied by Municipal Station #1 to 27.6 kV 

supply, and allow the Station (which is also at end of life) to be decommissioned in 2011. 

Replacing infrastructure that is at end of life will maintain safety and reliability. 

Converting from 4 kV to 27.6 kV will have a small reduction in system losses and allow 

for the elimination of a municipal substation. 

The cost of this project is estimated at $328,000. 

If this project is not completed, the Municipal Station (47 years old) will need to be 

upgraded with new transformation, switchgear, primary cabling, and the structure will 

need to be rebuilt at an estimated cost of approximately $5,000,000. In addition, the 

existing 4 kV circuits will still need to be replaced with new 4 kV equipment at an 

estimated cost of $300,000, bringing the total cost of the alternative to $5.3 million. One


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 1 



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alternative is to place all affected infrastructure underground. The estimated cost of this 

alternative is $1,500,000. 

This project is expected to be started in March 1, 2010 and be in service by October 30, 

2010. 



distribution. The station is approaching end of life, and the majority of the 4 kV 

distribution system is also nearing end of life. Therefore, rather than replace both the 

station and distribution with 4 kV equipment, it was decided to convert the area to 27.6 

kV to eliminate the need for the station and reduce system losses. This project will span 

several USofA accounts, and will be completed over a five year period from 2010 to 

2014. As each street is converted to 27.6 kV, it will be immediately put into service. 

The scope of this year’s portion of the project is Demille and Makins Streets (each about 

250m long) which is an underground subdivision installed in 1983. There are seven 

submersible style transformers (connecting 51 residential customers) that have 

deteriorated (due to be in frequent contact with water) and are deemed unsafe for crews 

to work on while energized. The underground primary cable is 26 years old and 

approaching end of life, and will be replaced. 

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The purpose of this project is to replace distribution infrastructure that is at end of life, 

convert the 4 kV load to 27.6 kV supply, and allow the Station to be decommissioned in 

2014. 

The cost of this portion of the project is estimated at $90,000. 

If this project is not completed, the 4 kV equipment (transformers and cables) will need 

to be replaced with 4 kV equipment at a cost of $81,000 and the Station will need to be 

replaced in approximately 2014 at a cost of approximately $3,000,000. The alternative of


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 1 



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converting this area to overhead distribution was not investigated as the City will not 

allow new overhead distribution in residential subdivisions. 

This project is expected to be started on March 1, 2010 and be in service by October 30, 

2010. 

Stratford – Wright Blvd Ph 2 – Extension (2009, 2010) 

This project is year 2 of a two year project to install distribution into a new industrial 

subdivision in the City of Stratford. See the write-up in 2009 for more details. 

The scope of this portion of the project is to provide servicing to new industries 

(proposed 23 lots) that are expected to be built on a new street (about 650m long) to be 

created off of the Wright Blvd. extension. Poles and overhead conductors will be used to 

provide servicing at 27.6 kV. 

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The cost of this portion of the project is estimated to at $125,000. 

If this project is not completed, new industrial customers will not be able to locate to in 

this subdivision due to the lack of servicing. One alternative is to wait until the first 

customer makes a decision to construct in this area, and construct the pole line at that 

time. This would require FHI to be able to accommodate a fairly large project into a busy 

capital program and would likely require other projects to be deferred. The cost of 

installing this line at a later date will be higher due to costs associated with restoration of 

boulevards (approximately $10,000) which is avoided when the electrical infrastructure is 

installed at the same time as the other municipal services. The City of Stratford – 

Economic Development Office has indicated they have turned away businesses in the 

past due to lack of suitable properties, and they fully expect businesses to start locating in 

this new subdivision within the first two years of completion. According to the 

Economic Development Office, properties that are pre-serviced with utilities are more


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 1 



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attractive to customers than ones that require servicing. The option of placing all 

infrastructure underground was investigated and the cost of this alternative has been 

estimated at $500,000. 

This project is expected to be started on September 1, 2010 and be in service by 

December 30, 2010, subject to the City of Stratford’s scheduling of their portion of this 

project. As noted in the 2009 write-up for this project, the City portion of the Wright 

Blvd extension may not be completed in 2009 and this may defer a portion of the 2009 

line extension into 2010. This would decrease the capital budget for 2009 and increase 

the budget for 2010. 

Stratford – Gibb Road – Tie Line 

This project is related to the Wright Blvd extension project, and it will create a loop-feed 

for the new industrial subdivision by connecting Gibb Road to the Wright Blvd 

extension. This overhead feeder tie will allow power to be re-routed in the event of an 

outage which will improve reliability to the area. This feeder tie will also become part of 

the new feeders that will emanate from the proposed new Transformer Station that will be 

constructed in the Wright Blvd area sometime in the near future. 

The scope of this project is to extend the overhead line on Gibb Road to the point where 

Wright Blvd will be extended to intersect with Gibb Road (about 200m). Poles will be 

framed for a double 27.6 kV circuit to allow room for future feeders from the new 

Transformer Station, but only one circuit will be installed at this time. 

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The cost of this project is estimated at $50,000.


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 1 



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If this project is not completed, this area will be on a radial supply and at risk for 

extended outages. The alternative of placing this section underground was estimated to 

be $250,000. 

This project is expected to be started on September 1, 2010 and be in service by 

December 30, 2010, subject to the City of Stratford’s scheduling of their portion of this 

project. 

Stratford – Delamere – Rebuild 

This project will replace aging infrastructure that has been identified as a potential risk 

for failure in the near future. 

The scope of this project is an overhead line on Delamere Avenue (about 1000m long) on 

the M5 feeder that has reached end of life. Poles, wooden crossarms, porcelain 

insulators, and transformers are 35 to 45 years old and in relatively poor condition. The 

existing conductors will be re-used. This portion of the feeder directly supplies 52 

residential customers (along Delamere) and is part of the main feeder route that supplies 

another 1500 customers downstream. 

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The cost of this project is estimated at $224,000.


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 1 



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If this project is not completed, the Stratford M5 feeder will be at risk of future outages 

due to equipment failure. The M5 feeder has been one of the worst performing feeders 

for the past several years, and this project will prevent future outages due to failed 

equipment. The option of placing all infrastructure underground was investigated and the 

cost of this alternative has been estimated at $1,000,000. 

This project is expected to start on March 1, 2010 and be in service by October 31, 2010. 

Stratford – Douro Phase 2– Rebuild (2009, 2010) 

This project is year 2 of a two year project to replace a section of overhead feeder that has 

reached end of life. 

The scope of this project is an overhead line on Douro Street (Stratford M8 feeder) from 

the 115 kV transmission line to CH Meier Blvd (about 600m). The wooden poles, 

crossarms, transformers, and porcelain insulators are over 40 years old and will be 

replaced with new. The primary overhead conductors will be re-used. Portions of the 

secondary conductors will be replaced as needed (depending on physical condition). The 

section that crosses under the 115 kV transmission line will be placed underground as the 

existing overhead line crosses over Douro Street and under the transmission line creating 

very tight clearances for working on this line, and several of the numerous guy and 

anchor locations have been damaged in the past due to large trucks entering and exiting 

the industries at this location. 


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due to equipment failure. The M8 feeder is one of the better performing feeders for the 

past several years; this project will maintain this level of reliability by preventing future


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 1 



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outages due to failed equipment. The option of placing all infrastructure underground 

was investigated and the cost of this alternative has been estimated at $1,100,000. 


Stratford – Campbell Court – Switchgear Replacement (2009, 2010) 

This project is year 2 of a two year project to replace padmount switchgear units that are 

at end of life (1979 vintage). 

The scope of this project is to replace the third switchgear unit that has been identified 

with “hot-spots” in recent infrared inspections (2004, 2006). While the “hot-spots” have 

been repaired, the overall condition of the switchgear has deteriorated (barriers are brittle 

and tracking, internal and external rusting, cable terminations cracking) and poses a 

reliability risk to the customers in this area (about 200 customers including 5 apartment 

buildings) which are on the Stratford M5 feeder. 

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equipment. 


Stratford – Reinsulate Poles – 68M3 Feeder (2009, 2010) 

This project is year 2 of a two year project to upgrade the insulators on the Stratford M3 

feeder, which has been identified as the worst performing feeder for several years. 

Analysis of the outage causes indicates that animal contacts are the major cause of 

outages, and further inspection of the feeder suggests the clearance from primary 

conductor to pole is insufficient to prevent squirrel contacts.


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 1 



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This scope of this project is to install fiberglass extension brackets on the existing 

insulators to increase the clearance to poles. It is anticipated that when this project is 

complete in 2010, the number of squirrel contacts for the M3 feeder will be reduced from 

an average of 8 per year to 1 or fewer. The area where this project takes place will affect 

approximately 2000 customers over the two year period. 



due to animal contacts. The M3 feeder has been one of the worst performing feeders for 

the past several years, and this project will prevent future outages due to animal contacts. 

Other alternatives have been investigated (such as various types of “squirrel guards”) but 

have not been as effective as the use of these fiberglass extension brackets. 

This project is expected to start on March 1, 2010 and be in service by December 31, 

2010. 

Stratford – Reclosers – 68M5 Feeder 

This project will improve the reliability of the Stratford M5 feeder by installing reclosers 

along the feeder to divide it into zones. The M5 feeder has 5000 customers (almost 25% 

of all FHI’s customers) and covers a large area. Due to geographic restrictions, this is the 

only feeder currently available to service these customers. 

The scope of this project is to install two reclosers on the M5 feeder to divide it into three 

distinct protection zones. Currently the entire feeder is supplied by a single feeder 

breaker at the transformer station on Devon Street, and any line fault causes the entire 

feeder to be subjected to an outage (either momentary or sustained in the case of a feeder 

lockout). Two reclosers will be installed at strategic locations and programmed to 

operate before the station breaker so that only a portion of the feeder (downstream from 

the recloser) is affected for faults that are downstream from the recloser. It is expected 

that the momentary outages on this feeder will be reduced from the five year average of 

89,000 customers impacted to 44,500 customers impacted, SAIDI should reduce from the 

five year average of 0.75 hours per year per customer to 0.50 hours per year per 

customer, and SAIFI should reduce from the five year average of 1.72 outages per year 

per customer to 1.0 outages per year per customer. 


If this project is not completed, the Stratford M5 feeder will continue to be one of the 

worst performing feeders in the system. The only alternative to this project is to bring 

another feeder to this area which would require upgrades to the distribution system for at 

least 3 km at a cost of at least $3M and the addition of a new feeder breaker at the Devon


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 1 



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Transformer station at a cost of $500,000 (assuming available space at the station for an 

additional breaker). 

This project is expected to start on May 1, 2010 and be in service by August 31, 2010. 


This project will improve the reliability of the Stratford M4 feeder by installing two 

automated switches that will transfer load to the M5 feeder if an outage occurs. These 

two switches will work with the original two automated switches installed on the M4 

feeder in 2006, to further enhance the flexibility of this feeder. 

The scope of this project is to install two padmounted automated switches in the 

underground section of the M4 feeder that extends along Lakeside Drive from Romeo 

Street to Waterloo Street. These two switches will be strategically located to allow the 

downtown section to be automatically restored if the fault is upstream of the downtown 

core. Once the automated switches have been installed, it is expected that this area will 

see a reduction in sustained outages from an average of 2 per year, to one or fewer. This 

area is primarily commercial customers along with high density residential customers, 

and a few institutional customers (schools, municipal buildings, federal buildings).


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 1 



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If this project is not completed, the reliability of this area will not improve. The only 

alternative to this project is to bring another feeder to this area which would require 

upgrades to the distribution system for at least 3 km at a cost of at least $6M and the 

addition of a new feeder breaker at the Devon Transformer station at a cost of $500,000 

(assuming available space at the station for an additional breaker). 


Stratford – Capacitor Banks – 68M2 Feeder (2009, 2010) 

This project is year 2 of a two year project to improve the voltage on the longest and most 

heavily loaded feeder in the system. See detailed write-up under 2009 projects.


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 1 



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The scope of this project is to add additional capacitors to the M2 feeder to improve the 

voltage during peak periods, and improve the power factor. Depending on the results of 

the 2009 project (amount of voltage improvement achieved), and the actual load on the 

feeder, this phase of the project may be deferred or eliminated. 


If this project is not completed, the voltage at the feeder end will continue to be lower 

than what is tolerable to the industrial customers (95% of nominal during peak periods) 

and may worsen if additional load is added to the feeder. Alternatives to this project that 

were considered were: re-conductoring the feeder with a large conductor (less of a 

voltage drop) but this would require most of the 5 km feeder to be rebuilt at a cost of over 

$5 million, installing a voltage regulating station partway down the feeder at a cost of 

$100,000 to $300,000 (assuming suitable property could be obtained), or the construction 

of a new Transformer Station at the end of the feeder at a cost of $16 to $20 million. It is 

expected that when this project is complete in 2010, the power factor will be at or better 

than 90% and the voltage at the feeder end during peak periods will be 98% or better. 


St Marys – Ontario Street North Area – Rebuild 



The scope of this project is the overhead lines on Ontario Street, William Street, Salina 

Street, Markham Street, and Ingersoll Street north of Queen and south of Widder, Widder 

Street from Ingersoll to Ontario, and Maiden Lane from Ingersoll to Robinson Street 

(about 2400m total) on the St Marys M4 feeder that has reached end of life. Poles, 

wooden crossarms, porcelain insulators, and transformers are 35 to 45 years old and in 

relatively poor condition. The existing primary conductors will be re-used. This portion 

of the feeder directly supplies about 150 residential customers.


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 1 



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The cost of this project is estimated at $187,000. Much of this area is only single phase 

primary or secondary. 

If this project is not completed, the St Marys M4 feeder will be at risk of future outages 




cost of this alternative has been estimated at $500,000. 


St Marys – St George Street – Rebuild 



The scope of this project is an overhead line on St George Street (about 200m long) on 

the St Marys M4 feeder that has reached end of life. Poles, wooden crossarms, porcelain 



residential customers (along St George Street) and is part of the main feeder route that 

supplies another 1200 customers downstream.


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 1 



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St Marys – Tracy Street – Rebuild 



The scope of this project is an overhead line on Tracy Street (about 300m long) on the St 

Marys M4 feeder that has reached end of life. Poles, wooden crossarms, porcelain 



residential customers.


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 1 



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Seaforth – West William Street – Rear Lot Conversion 


for failure in the near future, and it will remove primary distribution from rear lots of 

residential homes and thereby improve access for maintenance and improve public safety. 

The scope of this project is to re-locate existing primary overhead conductors and 

transformers from the rear lot of homes to the street front, on West William Street from 

Centre Street to Duke Street (about 100m). New poles, insulators, conductors and 

transformers will be installed on West William Street, and the existing infrastructure 

(approximately 35 years old) in the rear lots will be removed. This portion of the feeder 

supplies about 25 customers.


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 1 



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If this project is not completed, the Seaforth area will be at risk of future outages due to 

equipment failure. The option of placing all infrastructure underground was investigated 

and the cost of this alternative has been estimated at $300,000. 

This project is expected to start on May 1, 2010 and be in service by October 31, 2010. 

Seaforth – Brantford Street – Rear Lot Conversion 


for failure in the near future, and it will remove primary distribution from rear lots of 

residential homes and thereby improve access for maintenance and improve public safety. 

The scope of this project is to re-locate existing primary overhead conductors from the 

rear lot of homes to the street front, on Brantford Street from Isabella Street to Sparling 

Street. New underground primary conductor will be installed along Brantford Street, and 

the existing infrastructure (approximately 35 years old) in the rear lots will be removed. 

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If this project is not completed, the Seaforth area will be at risk of future outages due to 


and the cost of this alternative has been estimated at $250,000.


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 1 



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Dashwood – Helen Street – Secondary Rebuild 



The scope of this project is to replace overhead secondary bus along Helen Street from 

Rinker to Centre Street and Centre Street to the north and south limits (about 700m total). 

The existing secondary conductors are “open” style (partially insulated, physically 

separated and attached to the poles with insulated spools) that is at end of life and 

deteriorated to the point where failures can be expected. The secondary will be replaced 

with new “spun bus” style secondary to improve reliability and safety. 

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If this project is not completed, the Dashwood area will be at risk of future outages due to 


and discounted as it would require the complete rebuilding of the primary system and 

transformation. 




year.


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 1 



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The scope of the project is strictly the purchase cost of all transformers needed 

throughout the year. Any labour associated with installation is included in the various 

project costs. 

The estimated amount is $450,000 based on known projects and expected customer 

driven projects based on previous years’ activity. 

Whenever possible, transformers removed from service are re-used (after being 

inspected), sent for re-furbishment, or sent for complete recycling into new units. 

Transformers are purchased throughout the year, typically in three or four orders, to meet 

expected requirements. 


This line item represents an estimated 40 small projects completed during the year that 

will be triggered by customer requirements. 

The scope of this project includes new commercial and industrial service connections 

(which may or may not require new primary extensions and transformation), line 

relocations (requested by MTO or City), single pole relocations (to accommodate new or 

expanded driveways), new subdivisions (which may or may not require line extensions), 

in-fill projects (which typically require new or upgraded transformers), and make-ready 

work for third party attachments. In some cases, portions of the project cost are 

recoverable as a connection fee or capital contribution as determined by the Net Present 

Value calculation (as per the DSC). 

The estimated cost for 2010 is $455,000, based on previous years’ experience. The 

average cost of these projects is expected to be $10,000 and the largest project is 

expected to be $75,000 for the installation of primary cable for a new large commercial 

development in the 2nd quarter of 2010. 

If these projects are not completed, FHI will be in violation of the Distribution System 

Code by failing to connect customers in a reasonable amount of time. 



due to customer requests. 

The scope of this project is typically two thirds of these requests are associated with new 



upgrades.


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 1 



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The estimated cost for 2010 is $150,000 based on previous years’ experience. 

If these projects are not completed, FHI will be in violation of the Distribution System 



This line item represents the purchase and installation of new meters (excluding smart 

meters). 

The scope of this project includes the replacement of meters that are at end of life, meters 

that have reached seal expiry, upgraded meters triggered by customer demand, or new 

meters for new customers. 

The estimated cost for 2010 is $20,000 based on previous years’ experience. 

If these projects are not completed, FHI will be in violation with Measurement Canada 

for using meters that do meet requirements, and in violation of the Distribution System 






The scope of this project for 2010, this includes enhancements to add the additional 

automated switches to the SCADA system (so they could be remotely monitored and 

controlled). 

The estimated cost for this project is $20,000 based on previous years’ experience. 

If this project is not completed, the new automated switches may not operate 

appropriately and may either switch into a fault or attempt to pick up more load than the 

system is capable of which could lead to brownouts, outages, and equipment damage. 




The estimated cost for this project is $35,000 based on previous years’ experience.


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 1 



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If this project is not completed, workers will not be able to fulfill their duties or work 

safely. 

Lands and Buildings – Administration Building 

This line item represents several small projects to maintain and upgrade the 

Administration Building. 

The scope of the project includes furniture upgrades, minor office renovations, and 

replacements of failed components such as plumbing fixtures. 

The estimated cost for this project is $50,000 based on previous years’ experience and the 

planned renovation of the metering department to remove obsolete testing boards and 

create new office and storage space. 

If these projects are not completed, the building will continue to deteriorate to the point 

where additional damage occurs requiring a much larger capital investment. The 

renovations to the metering department will make more effective use of the office space 

and allow the spare meters and equipment to be stored in closer proximity to the meter 

technician making the workflow more efficient. 

Lands and Building – Service Centre 

This line item represents several small projects to maintain and upgrade the Service 

Centre. 

The scope of the project includes furniture upgrades, minor renovations, and 

replacements of failed components such as plumbing fixtures. 

The estimated cost for this project is $50,000 based on previous years’ experience and the 

planned addition of a covered storage area (unserviced) in the yard. 

If these projects are not completed, the building will continue to deteriorate to the point 

where additional damage occurs requiring a much larger capital investment. The 

additional covered storage will allow more inventory to be stored indoors, protecting 

them from the elements and making them easier to access during the winter. 


The scope of this project includes the replacement of a radial boom derrick truck (# 4 - 

1994 vintage), a minivan (#13 - 1997 vintage), and one sedan (#20 - 1999 vintage). 

These three vehicles are deemed to be at end of life based on physical condition, cost to 

maintain, in-field failure frequency, and maintainability.


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 1 



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For the radial boom derrick truck, it is in overall fair condition but has body frame issues 

(repairs done in the past). Of the three radial boom derrick trucks, it has the highest 

operating cost per km of use (over 4 times higher than average). 

Van #13 is the oldest small vehicle in the fleet and is the least functional. Car #20 is the 

next oldest small vehicle and is becoming more costly to maintain. 

The estimated cost for replacements is $300,000. 

If these vehicles are not replaced, they are expected to fail in use and require extensive 

repairs to keep them roadworthy. If the bucket truck fails in-service, it could be a safety 

hazard to the workers, cause damage to the system, and create an inefficiency (vehicle 

unavailable for use until repaired). 




The estimated cost for replacements is $25,000, based on previous years’ experience. 





The estimated cost for upgrades is $25,000, based on previous years’ experience. 




Festival Hydro assumed the assets associated with three residential subdivisions in the 

Town of St. Marys for a total of $240,000.


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 1 



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Budgeted capital additions for fiscal 2011 and 2012 are as follows: 

2011 2012 

Lands and Buildings $ 21,500 $ 22,000 

Overhead Distribution Projects $ 1,425,000 $ 1,450,000 

Underground Distribution Projects $ 260,000 $ 265,000 

Distribution Transformers $ 410,000 $ 415,000 

Customer Driven Projects $ 450,000 $ 450,000 

New/Upgraded Services $ 165,000 $ 170,000 

Distribution Meters* $ 10,000 $ 25,000 

Vehicles and Trailers $ 370,000 $ 330,000 

Computer Equipment $ 53,000 $ 54,000 

Scada + Automated Switches $ 200,000 $ 200,000 

Tools & Misc. Equipment $ 27,000 $ 28,000 

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$ 3,391,500 $ 3,409,000 

A summary of budgeted capital expenditures for 2011 and 2012 is provided in the table above. 

The amounts are based upon the completion of multi-year capital projects identified in this 

Application and Festival Hydro’s expected capital requirements related to sustainable funding 

for year of life asset replacement, compliance with applicable codes and safety requirements and 

customer driven capital expenditures. Capital spending is determined, in part, using the Asset 

Management Plan included herein. Festival Hydro anticipates that capital spending during the 

next four years will be consistent.

1 

ASSET MANAGEMENT PLAN SUMMARY: 


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 2 



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FHI is an infrastructure-based business with its distribution system assets the key element in the 

delivery of electricity to its existing and new customers. FHI distribution assets range in age 

from new to over 60 years old. 

Asset management is the professional management of physical infrastructure with a systematic 

methodology integrating best practices in all aspects of selection, design, construction, operation, 

maintenance, replacement and disposition. The goal is to use an Asset Management Plan to 

optimize the whole life business impact of costs, performance and risk exposures of FHI’s 

physical assets. Performance of the assets is directly related to reliability of the distribution 

system which is another key regulatory and customer satisfaction measure second only to rates. 

Accompanying this Schedule as Appendix A is a 2009 document titled “Asset Management”. 

The Asset Management Report represents the most recent document containing a high level 

description of FHI’s assets, their condition, the criteria used to determine when replacement 

should occur, and a five year financial forecast for the necessary capital and maintenance 

required to meet FHI’s objectives. The reliability of the distribution system is the major driver 

of the Asset Management plan, and maintaining or improving the level of reliability is of primary 

importance to FHI. 

The annual replacement costs, found in the Five Year Plan (section 5 of the Asset Management 

Report), are engineering estimates only and the actual expenditure levels in the capital budgets 

for each year will vary somewhat based on project scope, prevailing construction costs and other 

outside influences (e.g. relocation requests, system expansions, etc.). The Asset Management 

system and Five Year Plan has been in use at FHI for approximately ten years, and has been an 

effective tool for prioritizing projects and accurately forecasting the capital and maintenance 

costs over the rolling five year horizon.

1 


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 2 

Appendix A 


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Appendix A 

FHI_ Asset Management Plan 

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EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 2 

Appendix A 



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ASSET MANAGEMENT 

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FESTIVAL HYDRO’S ASSET MANAGEMENT PLAN 

2009 EDITION


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 2 

Appendix A 



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ASSET MANAGEMENT 

1.0 Philosophy 

Festival Hydro will maintain (repair, replace, or enhance) all assets such that they deliver the 

appropriate level of safety and reliability, while performing their intended function under 

reasonably expected conditions. 

2.0 Criteria 

When planning changes to the assets (repairs, replacements, or enhancements), the following 

criteria will be used (as appropriate): 

Age (relative to expected life) 

Physical condition 

Performance history 

Maintenance records (repair frequency and cost) 

Maintainability (availability of parts, comparison to new technology) 

Safety impacts (worker and public) 

Future use (local and regional planning) 

External demands (customer driven, road relocations) 

Efficiency opportunities (voltage conversions, new technology, cost reduction) 

Many of these have been derived from FHI’s Mission, Vision, and Values Statements (see 

Appendix 1) and incorporated into policies such as the Capital Investment – Replacement Policy 

(see Appendix 2), the Maintenance Policy (see Appendix 3), and the Tree Trimming Policy (see 

Appendix 4). 

3.0 Categories 

The assets are divided into the following main categories: computer hardware and software, 

vehicles and related equipment, tools, SCADA and automated equipment, buildings and fixtures, 

revenue metering, and distribution equipment.


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 2 

Appendix A 



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3.1 Computer Hardware and Software 

Computer hardware and related devices (printers, plotters, telecom equipment, etc.) have 

a typical useful life of five years. The decision to maintain, replace or upgrade these 

assets is primarily driven by performance history, maintainability, and efficiency 

opportunities. 

Computer software generally only requires upgrades that are part of maintenance 

agreements (for example SCADA software) or on as needed basis but typically every five 

years. These expenses are relatively minor and upgrades are based on maintainability 

and efficiency opportunities. 

Computer hardware and software upgrades or replacements are considered annually as 

part of the overall Annual Capital Budget preparation. Annual maintenance on computer 

hardware is minimal and is usually driven by a component failure. The Annual 

Maintenance Budget for this category is normally based on prior year’s experience. 

3.2 Vehicles and Related Equipment 

The fleet assets consist of the large construction vehicles (such bucket trucks), passenger 

vehicles, and trailers. The upgrading or replacement of these assets is based on the 

physical condition, performance history, maintenance records, and maintainability. The 

physical condition is monitored by employees (workers and fleet mechanic) and annual 

independent testing and inspections. The performance history and maintenance records 

are tracked on a software program by asset and the status is reviewed annually to set 

priorities and a five year replacement schedule. Maintainability is assessed annually by 

the fleet mechanic to ensure parts are readily available. Each asset has a set maintenance 

schedule based on either manufacturer recommendations or good utility practice. During 

the Annual Capital Budget preparation, all the criteria are reviewed to set priorities and 

determine the replacement schedule. This review is summarized in Appendix 5 with 

supporting information from inspections in Appendix 6. Due to the long lead time 

required for the larger vehicles, replacements are ordered approximately 18 months 

before they are expected to be required. A vehicle is scheduled for replacement when the 

physical condition is rated as “fair” or “poor”, the performance history indicates it failed 

in use more than twice in the past 12 months, and the maintenance records show a trend 

to increasing repair costs (above the average for that type of asset). The Annual 

Maintenance Budget for this category is based on the average of prior years plus any 

known major repairs that are expected.


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 2 

Appendix A 



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3.3 Tools 

Tools and miscellaneous equipment includes devices used to assist in various aspects of 

the operation. Purchases that exceed $1000 are generally capitalized, with the remainder 

being charged to maintenance. During the Annual Capital Budget preparation, tools and 

other equipment are identified for replacement or purchase, primarily based on physical 

condition. Typically, these tend to be several relatively low cost items that are replacing 

existing units that have reached the end of their useful life. Most of these items are 

formally inspected annually as well as being inspected prior to use by the worker. When 

the item requires a significant repair that approaches half the cost of replacement, the 

item is then replaced. Due to the unpredictable nature of these types of equipment 

failures, specific items are not always identified in the Budget, but may be grouped into 

categories such as replacement of safety equipment, replacement of operations tools, etc. 

The Annual Maintenance Budget for this category is normally based on prior year’s 

experience. 

3.4 SCADA and Automated Equipment 

FHI has an existing SCADA system that provides real time data on the distribution 

systems in Stratford and St Marys. This system typically requires annual upgrades to 

either hardware or software to improve system security, and integrate new devices. 

These annual upgrades are estimated when the Annual Capital Budget is prepared. FHI 

has been installing automated switches on the distribution system for the past several 

years. These switches are able to determine where a fault has occurred on the distribution 

system, and reconfigure the system to minimize the number of affected customers. 

Initially, FHI conducted a pilot project with two of these switches, and when the project 

was deemed successful, a plan was created for additional switches to be added during the 

next 5 years. The location and quantity of switches is finalized during the Annual Capital 

Budget preparation, and is based on performance history (feeder reliability statistics – 

targeting the worst performing feeders) and future use (load growth considerations). A 

small portion of maintenance is done the SCADA system, and this is set in the Annual 

Maintenance Budget. 

3.5 Buildings and Fixtures 

These include two main buildings (Stratford Administration building and the Stratford 

Service Centre) as well as three municipal substation buildings, a storage building, a 

residential building, and a leased service depot in Seaforth. These assets are inspected


EB-2009-0263 

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monthly by staff, and major components (such as HVAC units) are inspected by external 

contractors annually. Major upgrades such as HVAC replacements and roof 

replacements are included as part of the Annual Capital Budget submission. In most 

cases, replacements or upgrades are determined based on physical condition, 

maintainability, and safety impacts, but where possible, upgrades that improve energy 

efficiency (such as occupancy sensors) and security enhancements are also considered. 

Repairs or replacements that do not meet the capitalization policy are put into the Annual 

Maintenance Budget for this category (which also includes tasks such as snow removal, 

lawn care, etc). 

3.6 Revenue Metering 

This category includes wholesale meter points, interval meters, and non-interval meters 

but excludes smart meters. Replacement or upgrades are primarily based on age (when 

meters reach their seal expiry date and require re-verification or replacement) or external 

demands (new customers or customer upgrades). The estimated number of meters to be 

replaced is done as part of the Annual Capital Budget. The Annual Maintenance Budget 

for this category is based on prior year’s experience and consists primarily of routine 

inspections, repairs, and trouble calls. 

3.7 Distribution Equipment 

This category contains the majority of the assets (poles, wires, transformers, etc.) and 

represents the largest portion of the maintenance and capital budgets. There are three 

main drivers for the annual capital and maintenance plans for the distribution plant – the 

physical condition of the system, the performance (reliability) of the system, and the 

expected future use of the system (customer demand and load forecast). When an area of 

the system is selected for upgrade or replacement, further analysis is conducted to review 

options available (replace poles only, upgrade conductor size, replace insulators, convert 

to underground, right-size transformers, etc.) and opportunities for improvement (such as 

voltage conversions to reduce losses or re-locating rear-yard distribution to front yard to 

improve access or extending a line to create a feeder tie). 

3.7.1 Physical Condition 

The physical condition of the system is assessed by scheduled inspections, 

planned maintenance, and unplanned inspections and repairs. Data from 

all three processes is accumulated and reviewed when setting priorities for 

capital replacements. Since FHI’s system is relatively small, this data is 

currently kept in paper form. It is expected that this data will be migrated 

to a graphical interface system (GIS) at some point in the future.


EB-2009-0263 

Exhibit 2 

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3.7.1.1 Scheduled Inspections 

Substations are inspected monthly by qualified staff, and every 2 to 

5 years by an external contractor. The entire overhead primary 

system and all three phase padmounted equipment (transformers 

and switchgear) are checked with an infrared camera every two 

years (see most recent report in Appendix 7). During this 

inspection, a visual check is also performed. All single phase 

padmounted transformers are visually checked (externally) twice 

each year during the installation and removal of snow 

identification markers. All below grade vaults are inspected every 

six months. All complex metering installations are inspected every 

six years or when changes are needed. Other metering installations 

are visually checked monthly by meter readers. 

Problems or potential concerns are identified, documented, and 

scheduled for repair or replacement depending on severity. 

3.7.1.2 Planned Maintenance 

Vegetation control takes place on a three year cycle, with 

inspections done before and after to ensure quality of work. This 

is performed by a combination of external contractors and internal 

staff (see Appendix 4 for the Policy). Padmounted switchgear is 

cleaned with dry ice every 2 to 4 years, depending on the results of 

the infrared inspection. Overhead three phase switchgear is 

maintained every 5 to 7 years, depending on frequency of 

operation. Before the maintenance process begins, the overall 

physical condition of the asset is assessed. In some cases, the 

condition of the asset may be determined to be in at such a state 

that replacement or refurbishment is preferred to maintenance (see 

Appendix 3 for the Maintenance Policy). 

3.7.1.3 Un-planned Inspections and Repairs 

After severe weather activity, automatic reclosing of breakers, or 

motor vehicle accidents, the affected area is inspected to check for 

damage. During this inspection, repairs will be made as needed or 

noted for follow-up. The information obtained from these ad hoc 

inspections is also used to determine the overall condition of an 

area (e.g. if there are numerous repairs required to one area after a


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storm, it may indicate the infrastructure in that area is approaching 

end of life). 

3.7.2 System Reliability 

The outage frequency and duration by area and feeder is tracked monthly 

and reported on annually (see Appendix 8 for the most recent edition of 

the annual reliability report). The annual report identifies trends, and 

highlights the worst performing feeders. At a minimum, the overall 

system reliability is expected to be at the three year average level. The 

target for each feeder is set as the best of the past five years, excluding 

Loss of Supply and Planned outages. An in depth analysis of each feeder 

that does not meet the reliability target is conducted to determine if the 

deviation is the result of an anomaly (such as one severe storm or one 

motor vehicle accident), or if a trend is developing. The report creates 

recommendations for either improved maintenance (such as better tree 

trimming) or capital upgrades (such as a line rebuild or addition of 

automated switches). 

3.7.3 Future Planning 

The expected usage of the distribution system is done in two stages – short 

term plans (this year and next year), and long term plans (the next five to 

fifteen years). Monthly meetings with the area utility coordinating 

committees (UCCs) keep FHI apprised of projects such as new 

subdivisions or road widening projects that will be coming on stream in 

the next six to 18 months. This information, along with direct inquiries 

from builders and developers are used to form the projected upgrades and 

expansions needed in the short term. Information from the local economic 

development departments is also used to project the amount of customer 

driven activity (such as home upgrades or new commercial construction) 

that can be expected in the next 12 to 24 months. Most of these customer 

driven projects are accommodated with minimal changes to the 

distribution system. These projects fit into the Annual Capital Budget 

directly, and are used to allocate the customer driven portion of the five 

year capital budget. Overarching this short term plan is the longer term 

plan that is focused on what the system needs to look like in 15 years. 

With the exception of Stratford, no significant changes are expected to the 

distribution system in the next 15 years, other than replacement of 

depreciated plant which will often include voltage conversions (from 4 kV 

to 27.6 kV) whenever practical. The Stratford system continues to expand 

both geographically (requiring feeder extensions to reach new 

developments) and with new load growth (although growth has declined in 

the past 12 months). While there is some uncertainty associated with


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future load growth, a joint planning study conducted with Hydro One 

revealed the existing transformer station will become overloaded (above 

LTR) sometime in the next 5 to 15 years. Therefore, plans have been 

made as to the likely location for a second transformer station, and the 

configuration of new feeders to provide for this new load. 

4.0 Assessment 

Overall, FHI assets have been assessed as “sustainable”, meaning that for the foreseeable future, 

the assets can be maintained and replaced with similar financial contributions as prior years (see 

Five Year Plan). The two exceptions to this are the smart meter project which will require up to 

$3 to $4 million in new capital investment by the end of 2010, and the addition of a second 

transformer station in Stratford to meet load growth requirements. Depending on the load 

forecast, station cost, and contribution from Hydro One, the financial impact of the new 

transformer station may range from no upfront capital required, to an investment of upwards of 

$15 million. The timing of the new transformer station could be as soon as 2013 to as late as 

2023. During 2009, a detailed study into the need for a transformer station will be completed, 

and impacts to future capital and maintenance budgets will be available by the end of 2009. 

4.1 Overhead System 

The overhead distribution system consists of approximately 185 km of line, of which 

over 80% is located in Stratford and St Marys. Inspections by staff and external 

consultants indicate the overhead system is in good condition, with few areas of concern. 

4.1.1 Poles and Crossarms 

Over 25 years ago, the Stratford PUC made a decision to standardize on concrete 

poles with steel crossarms. This standard was extended to the six other areas 

purchased when Festival Hydro was formed in 2000. As a result, the vast 

majority of poles in the system are concrete, which has an expected life of 40 to 

50 years. In 1993, an external contractor was hired to conduct pole testing on the 

remaining wood poles in Stratford. From that testing, poles that were in 

unacceptable or fair condition were replaced with concrete poles on a priority 

basis. The remaining poles were monitored and many have been replaced as part 

of other projects. In 2005, the remaining wood poles were re-inspected and 

determined to be acceptable for another five years, or scheduled for replacement. 

This pattern of detailed inspections every five years for the remaining wood poles 

will continue until all wood poles have been eliminated from the system. The 

only exceptions to this are areas where poles are not readily accessible by bucket 

truck, in which case wood poles are still used (to allow workers to climb them 

with spurs).


EB-2009-0263 

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Over the past five years, there have been no pole failures that were not caused by 

either motor vehicle accidents, lightning strikes, or trees falling into lines. Visual 

inspections have not identified any areas of immediate concern regarding the 

condition of poles. There are several sections of the distribution system where all 

components (poles, insulators, transformers, conductors) are approaching end of 

life and these have been slated for complete rebuilds in coming years. 

Steel crossarms were changed to fiberglass crossarms about five years ago as the 

reliability analysis identified that the steel crossarms were contributing to the 

number of squirrel and bird related outages. Both the steel and fiberglass 

crossarms are expected to have a useful life of 40 to 50 years and there are no 

plans to replace these in the near future. 

There are approximately 4500 poles in the system, of which 3400 are concrete. 

Since concrete is impervious to rot and insect damage, a visual inspection is 

sufficient to determine if repair or replacement is needed. To date, the only 

concrete poles that have required repair or replacement have been those damaged 

by motor vehicle accidents. During the system inspection process, concrete poles 

are visually checked for obvious damage including excessive cracking. At the 

present time, there are no plans to begin proactively replacing concrete poles 

when they reach the age of 50, which will start in approximately 25 years. By 

that time, it is expected that some of the older concrete poles will have been 

removed from service due to other reasons (such as line relocations or upgrades) 

and a sample of these older concrete poles will be sent away for testing to 

determine if they are reaching end of life or if the 50 year life span was 

conservative. Therefore, no financial forecast has been prepared for the eventual 

replacement of concrete poles. 

Of the remaining 1100 wood poles in the system, between 50 and 200 are 

replaced each year as part of rebuild or relocation projects. At this rate, the wood 

poles will be substantially eliminated from the system within 10 years. Since 

these replacements are normally part of the rebuild or relocation projects, an 

average of 150 replacements per year has been used for the five year capital plan, 

which amounts to about $225,000 per year for the cost of concrete poles 

(excluding labour). 

4.1.2 Insulators 

The system has a mix of older, porcelain insulators and newer polymer insulators. 

Over the past ten years, most of the porcelain insulators have been replaced as the 

system has been upgraded, and in a proactive manner based on field failure 

warnings from suppliers. The remaining porcelain insulators have been inspected 

and will be replaced when the poles are replaced (most porcelain insulators are on 

wood poles and crossarms). The polymer insulators are expected to last up to 50


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years, and experience has so far confirmed they are reliable. Therefore, no 

financial forecast has been prepared for insulator replacements. 

However, a detailed look at the reliability of the 13.8 kV system in St Marys 

revealed that the 15 kV rated insulators were not providing enough clearance 

between the conductor and crossarm or pole, and as a result, the system was 

experiencing frequent interruptions due to squirrels and birds. To increase this 

clearance, insulated brackets were added to the problem feeders in St Marys, 

which increases the clearance by approximately 15 cm. This has dramatically 

improved the reliability in St Marys and therefore, these insulated brackets will be 

added to the problem feeders in Stratford starting in 2009. The cost of this project 

has been set at $50,000 per year for the next 5 years. 

4.1.3 Primary Conductors 

Bare overhead primary conductors have a life expectancy that exceeds 50 years. 

Failures tend to occur at connections and attachment points, and are detectable in 

advance of failure through infrared thermography. There are no plans in the 

foreseeable future to replace any primary overhead conductors, except as part of 

an overall line rebuild. When an area is targeted for a rebuild, the conductor size 

is evaluated and upgraded only if it will not handle the expected load in the next 

15 years. 

There have been no recorded failures of primary overhead conductors that were 

not related to failures of splices and terminations, or related to tree damage. 

Almost all splice and terminator failures have been prevented through infrared 

inspections conducted every other year. Therefore, no financial forecast has been 

prepared for solely for primary conductor replacements. 

4.1.4 Secondary Conductors 

Insulated secondary conductors have a life expectancy of 30 years, but many will 

last longer if lightly loaded and not damaged by trees and weather. Since a failure 

of a secondary conductor is a low risk event (only one or a few customers 

affected), FHI does not plan to proactively replace secondary conductors. When 

failures do occur, the first step is to make a repair using a splice, and if multiple 

failures occur in a single section or area, the conductor will be replaced. 

Generally, these costs are captured in the overhead line maintenance section of 

the general ledger. 

From the reliability report, failures of secondary connections are one of the more 

frequent causes of outages, but they typically only affect one or a few customers. 

With a failure rate of less than 0.03% per year, it would not seem prudent to spend 

money replacing these before failure. When line rebuilds occur, the secondary 

conductors are evaluated and replaced (if necessary) as part of the overall rebuild


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project. Therefore, no financial forecast has been prepared for secondary 

conductor replacements. 

4.2 Underground System 

The underground system consists of approximately 90 km of line, primarily in newer 

underground subdivisions and the downtown cores of the City of Stratford and the Town 

of St Marys. The downtown core of Stratford also contains equipment in below grade 

vaults, and both areas have padmounted switchgear. 

Of the 90 km of cable, 65% is less than 20 years old, and only 13% is 30 years and older. 

The chart below shows the quantities of cable by year. 

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Essentially all of the cable that is older than 30 years is 4 kV cable in Stratford that is 

scheduled for replacement through voltage conversions (MS #8 and MS #9) in the next 

10 years. These voltage conversions will also replace the remaining 4 kV cable that is 

currently 16 to 30 years old. 

The life expectancy of underground primary cable is 30 years, and it has been FHI’s 

experience that this is a conservative number. There have been few cable failures that 

were not attributed to manufacturing defects, poor workmanship (at splices and 

terminators), or physical damage (due to dig ins). Over 90% of the underground primary 

system is a loop feed so a cable fault would only create a relatively short outage until the 

power is re-routed, and the section of the damaged cable can then be repaired or replaced


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the next work day. The majority of the underground system is lightly loaded (relative to 

cable ampacity rating) and is expected to last longer than the typical 30 years. Over 95% 

of the primary cable is installed in ducts making replacement a relatively easy process. 

Based on these factors, FHI does not anticipate proactively replacing underground 

primary cable that reaches a specific age. Each section of cable will be replaced after it 

has experienced two cable faults (i.e. the first time it faults it will be repaired, the second 

time it faults it will be replaced). 

FHI has investigated a method of extending the life of some of the older 27.6 kV cables 

through a process of “cable injection” where a dielectric liquid is forced through the cable 

under pressure, removing any traces of water and filling in the small gaps that are created 

as the cable deteriorates. Based on the cost of this process and expected improvement in 

life expectancy, FHI does not plan to use this technology except for sections of cable that 

are direct buried and have a past history of failures. 

To provide a future projection of cable replacement costs, it has been assumed that cables 

will be replaced by age 40. Currently, the oldest cables are only 34 years old, so the 

projection of replacements will start in 2015. Through voltage conversions and other 

rebuild projects, current spending on cable replacements is around $130,500 per year 

which is slightly below the projected average of $143,000 per year needed to sustain 

cable replacements over a 40 year cycle. Below is the projection by year, with the peak 

at only around $267,000 per year starting in 2035. It is expected that by that time, a 

better understanding of cable failures and life expectancy will allow for a more accurate 

forecast on replacement costs. 

26


EB-2009-0263 

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4.3 Transformers 

There are approximately 2400 distribution transformers in service or in stock. Of these, 

about 70% are less than 16 years old. The chart below shows the quantities of 

transformers by age, in groups of 5 years. 

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While the typical life expectancy of a transformer is 30 years, FHI’s experience has been 

that many will surpass this age, especially those that are lightly loaded and see relatively 

few downstream faults. The frequent inspections of the system will identify transformers 

that have external damage (chipped insulators, oil leaks, or surface rust) and these are 

either repaired in the field or replaced with new and the old unit is sent for refurbishment. 

Most of the transformers that are older than 30 years have historically been replaced as 

part of a voltage conversion. 

FHI does not replace transformers solely based on age. Unless the physical condition is 

poor, the infrared inspection identifies unusual heating, or other work is taking place in 

the area (such as the transformer pole being replaced or relocated), transformers are kept 

in service indefinitely. However, assuming the majority of transformers are replaced by 

the time they are 40 years old, a long range projection of replacement cost has been 

created. Our current level of transformer replacements is approximately $335,000 per 

year, but as the graph below indicates, this will need to increase to over $500,000 per 

year in 2030. To effectively manage the forecasted workload between 2026 and 2035, 

the budget for transformer replacements will be ramped up by 3% per year starting in 

2014, then increased by 5% between 2026 and 2029, then leveling off and eventually 

declining by 3% per year starting in 2035. This schedule will replace some transformers 

before they reach 40 years old (between 30 and 39 years old) and some may be in service 

longer than 40 years, but the schedule will make the annual workload manageable.


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4.4 Substations 

There are only 6 distribution substations remaining in the system. Over the past ten 

years, voltage conversions have resulted in the decommissioning of 6 municipal 

substations and this trend is expected to continue. As each substation and associated 

distribution assets approach end of life, the area is reviewed to determine if the station 

and lower voltage distribution should be replaced, or if an upgrade to a higher voltage is 

warranted. In most cases, a higher voltage circuit (typically 27.6 kV) is readily available 

above the lower voltage circuit, and the conversion will require the replacement of 

distribution transformers. At that time, the condition of the poles and insulators are 

assessed to determine if they should be replaced at the same time as the voltage upgrade 

to minimize future costs and service disruptions. Depending on existing and future 

loading of the system, the conductors may be upgraded as well. 

The remaining substations are listed in the table below, with comments regarding the 

assessed condition and future plans. The costs associated with decommissioning a 

substation are relatively minor and in most cases, the land is sold for residential 

development which more than offsets the decommissioning cost. 

STATION TYPE AGE CONDITION FUTURE 

Seaforth MS#1 

27.6 kV to 4 

kV 

Outdoor, fused 22 years Excellent 

condition, no 

concerns 

Maintain 

Seaforth MS#2 

27.6 kV to 4 

Outdoor, fused 22 years Excellent 

condition, no 

Maintain


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kV 

Stratford MS#1 

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kV 


27.6 kV to 4 

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27.6 kV to 4 

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Zurich MS#1 

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concerns 

Indoor, switchgear 30 years Poor condition, Decommission 

subject to water in 2011 

damage 

Indoor, switchgear 30 years Good condition Decommission 

in 2015* 

Indoor, switchgear 19 years Good condition Decommission 

in 2019* 

Outdoor, 

switchgear 

23 years Fair condition Decommission 

in 2009 

* These substations and 4 kV distribution area will be re-assessed several times before 2015 and the decommission date may be 

adjusted based on physical condition and reliability issues. 

The Town of Seaforth is serviced entirely by the two municipal substations at 4 kV. 

There is no 27.6 kV available within the town limits to facilitate a voltage conversion. 

Each substation is capable of supplying the entire load in the event the other station is not 

available. Due to the light load (3 MW) and the negligible load growth (less than 1% per 

year), it is expected that the 4 kV system can handle the future load without issue. Since 

both stations are in excellent condition, it has been decided that the Town of Seaforth will 

remain at 4 kV for the foreseeable future. The station transformers have an expected life 

to 30 to 40 years, but since they are lightly loaded, they may last longer. For the 

foreseeable future, these units will be maintained and monitored, and replacements will 

be scheduled in approximately 18 years, at a cost of $100,000 each. 

The distribution area serviced by Stratford MS#1 is at end of life and is being replaced in 

2009 and 2010. During the replacement, the system will be converted from 4 kV to 27.6 

kV to reduce system losses and allow for the substation to be decommissioned. The 

costing for this conversion is $450,000 in 2009 and $328,000 in 2010. 

The distribution areas serviced by Stratford MS#8 and MS#9 are between 15 and 35 

years old and primarily underground distribution. Since the cable and transformers are 

reaching end of life, they will be replaced with new and converted to 27.6 kV in the next 

5 to 10 years. This will reduce system losses and allow the substations to be 

decommissioned. The costing for the conversion of MS#8 is $90,000 in 2010, and 

approximately $180,000 each year for 2011 to 2014. The costing for the conversion of 

MS#9 is approximately $1,000,000 that will be spent over a period of five years starting 

in 2015 and ending in 2019. 

The distribution system in Zurich is supplied by a single substation with no backup 

capability. Most of the system has been identified as end of life and is currently being


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rebuilt over a two year period. With the substation also approaching end of life, it was 

decided that the voltage would be converted to 27.6 kV during the rebuild process to 

reduce system losses and allow for the substation to be decommissioned. This will also 

allow for a future alternate supply/feeder tie with Hydro One, who indicated plans to 

extend their 27.6 kV system in the area. The cost of this conversion is $451,775 in 2008, 

and $398,500 in 2009. 

4.5 Vehicles and Equipment 

The fleet consists of 13 larger vehicles used for the construction and maintenance of the 

distribution system, and 12 passenger vehicles used for light construction and general 

use. There are also 18 trailers of various types (pole trailers, reel trailers, stringing 

trailers, equipment trailers, etc). The inventory and assessment is summarized in 

Appendix 5. 

When Festival Hydro was formed in 2000 with the purchase of the six smaller utilities, 

the fleet acquisitions were generally older vehicles (typically early 1990s) but with 

limited usage. Since 2000, the fleet quantity has been reduced from 31 to 25 by trading 

in or selling many of the older vehicles and replacing them with new vehicles that are 

more suited to use across the system. 

While the replacement of vehicles and trailers is based on a combination of factors (see 

Section 3.2 and Appendix 5), a long range forecast would require the replacement of one 

large vehicle each year (average age would be 12 years), and three small vehicles every 

two years (average age would be 10 years). This will require average spending on new 

vehicles of $330,000 per year for the foreseeable future. The actual amount each year 

will depend on the final selection of vehicles to be replaced in the coming year. 

4.6 Buildings and Fixtures 

FHI owns seven buildings and leases one other building. Of the seven owned buildings, 

one is a metal utility building (unserviced) and is not expected to require any capital 

improvements in the foreseeable future, and three buildings are municipal substations that 

are expected to be decommissioned in the next 5 to 10 years and are not expected to incur 

any significant capital or maintenance expenses before decommissioning. The leased 

building in Seaforth is a service depot, and no leasehold improvements are anticipated in 

the foreseeable future and building maintenance costs are the responsibility of the 

landlord. 

The three remaining buildings are the Stratford Administration building, the Stratford 

Service Centre, and a residential house located adjacent to the Administration building. 

The major components that require regular capital replacements are the roof and HVAC 

units.


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The administration building was constructed in 1959. The roof was replaced in 2007 and 

is expected to last 30 to 40 years. All but one of the HVAC units have been replaced in 

the past 7 years, and each is expected to last 15 to 20 years (the remaining older HVAC 

unit will be replaced in 2009). Recent inspections by staff and external consultants 

(HVAC contractors, air quality expert) did not identify any deficiencies that will require 

significant financial investments in the next 5 years. The section of the building allocated 

to the metering department includes a large area that was used for meter reverification 

which has been outsourced for over 5 years and FHI has no plans to do this work 

internally in the foreseeable future. Therefore, in 2010, the area will undergo a minor 

renovation to create more office space and create better storage for the meters and related 

equipment. 

The service centre was constructed in 1957 and has undergone several changes since that 

time. The roof on the garage portion was replaced in 2005 and is expected to last 15 to 

20 years. The roof on the remaining portion was replaced in 1981 and is expected to last 

until approximately 2016, based on recent inspections. The HVAC units have been 

replaced in the past 5 years, and should last another 10 to 15 years. A structural defect 

was identified in 2008 (excessive rusting on support columns) and evaluated by a 

structural engineer, who recommended the replacement of the damage portions. This 

work has been scheduled for 2009 at a cost of approximately $92,000. No other 

deficiencies have been identified that would require significant financial investments in 

the next 5 years. There are many relatively small items (such as crossarms, small 

transformers, and switchgear) that are stored outdoors in the storage yard and are difficult 

to locate in the winter and some have been damaged in the past during snow removal. To 

alleviate this problem, a small covered storage area (small unserviced building) will be 

constructed in 2010 to house the smaller items. 

The residential house is a multi-unit building with one unit currently rented out as a 

residence. The remaining units are used for office storage. The roof was replaced in 

2005 and expected to last another 15 years. The furnace (for the tenant portion) was 

replaced in 2005 and is expected to last another 10 years. There are no identified 

deficiencies with this building that would require significant financial investments in the 

next 5 years. 

5.0 Five Year Plan 

FHI maintains a Five Year Capital Plan that is updated annually and reviewed by the Board of 

Directors. It provides a high level forecast of the financial investment required in capital to keep 

the assets sustainable. The estimates for each year are based on the Asset Management Plan 

projections that have been refined using specific project estimates for the next two years, and 

high level estimates for the subsequent three years. The amounts for Customer Driven Projects 

and New/Upgraded Services are based on historical information combined with forecasts from


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Economic Development departments across the service area. The latest version is shown 

below. 

FIVE YEAR PROJECTION - CAPITAL BUDGET 

2009 2010 2011 2012 2013 

Lands and Buildings $ 151,500 $ 100,000 $ 21,500 $ 22,000 $ 23,000 

Overhead Distribution Projects $ 1,617,000 $ 1,389,875 $ 1,425,000 $ 1,450,000 $ 1,500,000 

Underground Distribution Projects $ 143,500 $ 277,125 $ 260,000 $ 265,000 $ 270,000 

Distribution Transformers $ 400,000 $ 450,000 $ 410,000 $ 415,000 $ 420,000 

Customer Driven Projects $ 400,000 $ 455,000 $ 450,000 $ 450,000 $ 450,000 

New/Upgraded Services $ 150,000 $ 150,000 $ 165,000 $ 170,000 $ 175,000 

Distribution Meters* $ 75,000 $ 20,000 $ 10,000 $ 25,000 $ 25,000 

Vehicles and Trailers $ 355,000 $ 300,000 $ 370,000 $ 330,000 $ 295,000 

Computer Equipment $ 70,000 $ 50,000 $ 53,000 $ 54,000 $ 55,000 

Scada + Automated Switches $ 130,000 $ 280,000 $ 200,000 $ 200,000 $ 200,000 

Tools & Misc. Equipment $ 60,000 $ 35,000 $ 27,000 $ 28,000 $ 30,000 

Total (typical year) $ 3,552,000 $ 3,507,000 $ 3,391,500 $ 3,409,000 $ 3,443,000 

Details 

2009 2010 2011 2012 2013 

Overhead Distribution Projects $ 1,457,000 $ 1,389,875 $ 1,425,000 $ 1,450,000 $ 1,500,000 

Voltage Conversions 823500 256875 300000 300000 250000 

Rebuilds 361000 958000 975000 1000000 1000000 

Extensions 272500 175000 150000 150000 250000 

Underground Distribution Projects $ 103,500 $ 277,125 $ 260,000 $ 265,000 $ 270,000 

Voltage Conversions 33000 161125 200000 205000 210000 

Rebuilds 69000 116000 60000 60000 60000 

Extensions 1500 0 0 0 0 

Meters (Distribution & Wholesale) $ 67,000 $ 20,000 $ 10,000 $ 25,000 $ 25,000 

Retail Meters 32000 20000 10000 25000 25000 

Zurich - Wholesale Meter 35000 


Replace Pickup/Minivan/Car 50000 40000 30000 

Replace Panel Van 

Replace Backhoe 80000 

Replace Trailers 15000 

Replace Single Bucket 260000 

Replace Double Bucket 290000 300000 

Replace RBD 290000 295000 

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Note: Due to extended delivery times for large vehicles, orders take place 1 year in advance. 

* Meters excludes Smart Meter costs. 

FHI maintains a Five Year Operations and Maintenance Plan that is updated annually and 

reviewed by the Board of Directors. It provides a high level forecast of the financial investment


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required in operations and maintenance to keep the assets sustainable. The latest version is 

shown below. 

FIVE YEAR PROJECTION - O&M BUDGET 

2009 2010 2011 2012 2013 

Distribution Station Equipment 37,158 38,273 39,230 40,014 40,814 

Overhead Distribution 774,092 797,315 817,248 833,593 850,264 

Underground Distribution 154,232 158,859 162,830 166,087 169,409 

Distribution Transformers 76,652 78,952 80,925 82,544 84,195 

Distribution Meters 229,194 236,070 241,972 246,811 251,747 

Customer Premises 158,507 163,262 167,344 170,691 174,104 

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Total (typical year) $1,429,835 $1,472,730 $1,509,548 $1,539,739 $1,570,534 

The figures in the table above are consistent with the information approved by the FHI Board of 

Directors in January of 2009, and may not be consistent with the figures presented in this rate 

application as various minor changes were applied after the January board meeting took place.


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6.0 Conclusion 

Based on the overall assessment of the assets, the Five Year Capital and O&M budgets are 

reasonable and should be sustainable for the foreseeable future. Some flexibility year over year 

will be required to address customer requirements and unanticipated deterioration, but overall the 

capital and maintenance spending is expected to be relatively smooth.


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Appendix 1 – FHI Mission, Vision, Values 

Mission, Vision & Value Statements 

October 2004 

MISSION STATEMENT: 

FESTIVAL HYDRO INC, IS THE DISTRIBUTOR OF RELIABLE AND SAFE ELECTRIC 

POWER AND RELATED PRODUCTS AND SERVICES FOR THE CITY OF STRATFORD AND 

SURROUNDING COMMUNITIES. WE FOCUSED ON DELIVERING DEPENDABLE, COST- 

EFFECTIVE AND QUALITY SERVICES TO OUR CUSTOMERS. 

FESTIVAL HYDRO CONDUCTS THE OPERATIONS OF THE BUSINESS PRUDENTLY TO 

PROVIDE PROFITS FOR OUR SHAREHOLDER THROUGH STRONG FINANCIAL 

PERFORMANCE, ENSURING GROWTH AND SUSTAINABILITY FOR THE FUTURE 

OUR EMPLOYEES ARE ONE OF OUR STRONGEST ASSETS. FESTIVAL HYDRO 

FOSTERS AN ORGANIZATIONAL CULTURE THAT ENCOURAGES EMPLOYEE GROWTH AND 

DEVELOPMENT AND RECOGNIZES INDIVIDUAL AND TEAM CONTRIBUTIONS. WE OPERATE 

WITH A STRONG COMMITMENT TO MAINTAIN A HEALTHY AND SAFE WORKING 

ENVIRONMENT FOR EMPLOYEES AND THE COMMUNITY. 

VISION STATEMENT: 

FESTIVAL HYDRO WILL INCORPORATE THE LATEST APPROPRIATE 

TECHNOLOGICAL INNOVATIONS IN THE DISTRIBUTION AND DELIVERY OF ITS PRODUCTS. 

WE WILL GROW INTERNALLY AND EXTERNALLY THROUGH A PHILOSOPHY THAT 

ENCOURAGES ACCOUNTABILITY, AND CONTINUOUS IMPROVEMENT AT ALL LEVELS OF OUR 

ORGANIZATION BY CONTINUING TO CREATE ECONOMIC VALUE-ADDED SERVICES AND 

THROUGH IDENTIFICATION OF OPPORTUNITIES FOR GROWTH. 

VALUE STATEMENT: 

BUILDING ON SAFETY…. BY FOLLOWING THE BEST PRACTICES AND PROCEDURES 

WE STRIVE TO BE ABOVE INDUSTRY AVERAGES AND TO CONTINUOUSLY IMPROVE OUR 

SAFETY RECORD FOR THE WORKPLACE AND ELECTRICAL SYSTEMS. WE PROVIDE 

ONGOING TRAINING AND EDUCATION TO CHALLENGE OURSELVES TO BE BETTER AND TO 

ENSURE SAFETY FOR ALL. 

PROACTIVE IN ALL THAT WE DO….WE ARE DEDICATED TO PROVIDING THE 

HIGHEST QUALITY SERVICES THAT NOT ONLY MEETS THE NEEDS, BUT EXCEEDS THE 

REQUIREMENTS OF INTERNAL AND EXTERNAL CUSTOMERS. WE ARE COMMITTED TO 

CONTINUOUS IMPROVEMENT AND ARE OPEN TO SUGGESTIONS AND OPTIONS. WE 

CREATE A LEARNING ENVIRONMENT LEADING TO THE MOST EFFICIENT AND EFFECTIVE


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WORK PROCESSES. WE ANTICIPATE NEEDS AND LEARN QUICKLY WHEN FACING NEW 

CHALLENGES; WE ANALYZE OUR ACTIONS TO IMPROVE THE WAY WE FIND SOLUTIONS. 

ACTING WITH INTEGRITY… PERSONAL AND CORPORATE INTEGRITY IS 

FUNDAMENTAL TO OUR SUCCESS. WE WILL BE DIRECT, TRUSTWORTHY AND TRUTHFUL 

AND WILL PRESENT THE UNVARNISHED TRUTH IN AN APPROPRIATE AND HELPFUL 

MANNER. WE ARE ACCOUNTABLE FOR OUR ACTIONS AND AS SUCH WE WILL DO WHAT WE 

SAY; WE WILL KEEP CONFIDENCES AND BUILD TRUST; WE WILL ADMIT MISTAKES AND WE 

WILL NOT MISREPRESENT OURSELVES FOR PERSONAL GAIN. 

CREATING POSITIVE SOLUTIONS… AT FESTIVAL HYDRO, WE CREATE A CLIMATE 

IN WHICH PEOPLE WANT TO DO THEIR BEST. WE EMPOWER OTHERS AND INVITE INPUT 

FROM EACH PERSON. WE SHARE OWNERSHIP AND VISIBILITY FOR OUR SUCCESS AND 

CONVEY THAT EACH INDIVIDUAL’S CONTRIBUTION IS IMPORTANT. WE FOSTER TWO-WAY 

DIALOGUE WITH OTHERS AND FIND POSITIVE SOLUTIONS FOR WORK AND RESULTS; WE 

BRING OUT THE BEST IN PEOPLE. AS SUCH, WE BUILD RAPPORT AND RELATE WELL WITH 

ALL KINDS OF PEOPLE, INSIDE AND OUTSIDE THE ORGANIZATION. WE DEVELOP 

CONSTRUCTIVE AND EFFECTIVE RELATIONSHIPS AND USE DIPLOMACY AND TACT WITH 

OTHERS.


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Appendix 2 – Capital Investment – Replacement Policy 

CAPITAL INVESTMENT/REPLACEMENT POLICY 

October 2006 

Festival Hydro will provide a safe, reliable, and cost-effective electrical system for our 

customers while retaining and enhancing shareholder value. 

All physical assets depreciate over time; therefore, it is necessary to continually reinvest 

in the system to maintain value and integrity. The timing of capital investment 

should be such that safety, reliability, and economics are not compromised. That is, 

replacements of depreciated assets should occur before they become unsafe, 

unreliable, and uneconomical. 

New technology will be utilized when appropriate, and the system will be enhanced and 

expanded to accommodate load growth. New capital investments must enhance 

shareholder and customer value by improving safety, reliability, customer service, and 

meeting projected load growth. Investments must be made prudently, using proven 

technology and based on sound business principles. 

A Five Year Plan will be maintained, which identifies major projects and anticipated 

spending levels for the next five years. As indicated in the Dividend Policy, capital 

expenditures will be at least equal to the rolling average depreciation during the period. 

Prepared by the Engineering Department, the Five Year Plan will take into account the 

physical condition of the assets (based on inspections and test results), historical 

reliability information, age of components, system loading and load growth projections 

(including planning information from local municipalities), and input from employees. 

From the Five Year Plan, an Annual Capital Budget will be prepared and presented to 

the Board of Directors for approval. 

The annual budget for capital replacement projects will be, at a minimum, equal to the 

amount of depreciation anticipated for the year. The budget for new infrastructure 

projects will reflect the projected load growth, using best available information. 

Investments in new technology will be presented to the Board with an outline of the 

expected improvements in safety, reliability, and customer service. 

Management is expected to pre-screen and prioritize all projects before presenting the 

Annual Capital Budget to the Board. The screening process will use the following 

criteria: safety, reliability, capacity (load and voltage), forecasted growth, costeffectiveness, 

and customer service. The Finance & Audit Subcommittee will review the 

annual capital budget prior to Board approval of the budget.


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Board approval is required in the event that unexpected additions to the Capital Budget 

will exceed approved amounts. 

Appendix 3 – Maintenance Policy 

MAINTENANCE POLICY 

Oct. 5/06 



All Festival Hydro assets will be maintained in accordance with applicable legislation, 

manufacturers’ recommendations, and good utility practice. 

The overall goal of maintenance is to prevent problems and damage from occurring. 

Regular inspections and testing are necessary to determine the condition of the assets. 

The frequency of maintenance and inspection cycles will depend on the expected life of 

the asset, actual use of the asset, physical conditions, risk of failure, consequences of 

failure, and the health and safety of the public and workers. 

Inspection and maintenance cycles will be planned, whenever possible, to take place 

during winter months, when fewer capital projects are in progress. Also, schedules and 

spending will be balanced, as much as possible, so that an equivalent amount is spent 

each year. 

For the distribution system, the following specific schedules will be used: 

Tree trimming – three year cycle (amount to be trimmed as per EUSA guidelines) 

Infra-red Inspection – two year cycle 

Dry-ice Cleaning – four year cycle 

Substation Inspections – monthly 

Substation Maintenance – five year cycle 

Padmount Transformer Inspections – five year cycle 

Records of the above will be retained in Engineering. Replacement of distribution 

assets will be based on age, physical condition, reliability, and safety. Generally, 

distribution assets are expected to have a useful life of 30 years. Most planned 

replacements will take place as capital projects, budgeted annually. 

For vehicles, equipment, and buildings, maintenance will follow manufacturers’ 

recommendations. Any items in these categories that require excessive maintenance 

will be reviewed by Senior Management to determine if it should be replaced. Vehicle


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replacements will be tentatively planned 5 years in advance, as part of the Five Year 

Capital Plan, but not finalized until the annual budget is prepared. 

Appendix 4 – Tree Trimming Policy 

TREE TRIMMING POLICY 

August 2006 



Festival Hydro overhead distribution circuits need to be kept free from vegetation to 

ensure safety and reliability. With the exception of the City of Stratford, Festival Hydro 

is the prime contractor responsible for tree trimming. The City of Stratford administers a 

tree trimming/removal contract within Stratford on an annual basis with input from 

Festival Hydro regarding line clearing requirements. 

To be cost effective, tree trimming should be done on a cyclical basis, with the cycle 

lasting 3 years. The amount to be trimmed is dependent on the tree growth rate. 

Deciduous trees (such as maple and oak) grow relatively quickly while coniferous trees 

(such as pine) grow slower. 

Festival Hydro will follow the EUSA Safe Practice Guide for Line Clearing, latest edition. 

The Guide gives pruning clearances required for different voltage levels and cycle 

length. These clearances are a guideline only, and in general, the amount pruned 

should be the maximum amount possible while still maintaining a viable and somewhat 

aesthetic tree. If a tree cannot be adequately pruned without causing significant 

damage, it should be removed. The different municipalities have different requirements 

regarding tree removals, and they must be consulted prior to removing a tree. 

Tree trimming should be scheduled for January and February while the trees are 

dormant and workers are more readily available. Where possible, the amount spent on 

tree trimming should be approximately the same year to year. 

Tentative Schedule 

St. Marys Seaforth Area Stratford* 

Year 1 West Ward Brussels, Seaforth East Zone 1 

Year 2 North East Ward Seaforth West, Hensall Zone 2 

Year 3 South East Ward Zurich, Dashwood Zone 3


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* - Stratford Zones to be determined in consultation with the City.


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Appendix 5 – 2008 Vehicle Inventory & Replacement Plan 

FESTIVAL HYDRO - 2008 LARGE VEHICLE INVENTORY AND REPLACEMENT PLAN 

Total Maint Avg Average Inspection Other 

Vehicle Type Year Odometer $ to date Cost/km Cost/yr Defects Comments 

22 Backhoe 1990 6357 $ 28,600 $ 4.50 $ 1,505 

fair condition 

Replacement Plan: Replace in 2011 or 2012. 

21 Crane/Flatbed 1993 22911 $ 25,700 $ 1.12 $ 1,606 

good condition 

Replacement Plan: maintain until costs become excessive/major repair required, then replace with same. 

26 Double Bucket 2000 56920 $ 81,880 $ 1.44 $ 9,098 


3 Double Bucket 1990 36355 $ 59,500 $ 1.64 $ 3,132 


5 Double Bucket 2007 15157 $ 13,039 $ 0.86 $ 6,520 

new 

42 Double Bucket 50' 1991 124103 $ 63,621 $ 0.92 $ 3,535 needs some body work fair condition 

Replacement Plan: replace #42 with one new single in 2009 (ordered in 2008), replace #3 in 2012 (order in 2011). 

frame repaired; overall 

4 Single Bucket 1994 61074 $ 76,278 $ 1.25 $ 5,085 


6 Single Bucket 2005 48110 $ 35,400 $ 0.16 $ 8,850 none new 

45 Single Bucket 42' 2008 10530 $ 2,961 $ 0.28 $ 2,961 


Replacement Plan: replace #4 in 2010 (order in 2009). 

24 RBD 1996 57714 $ 52,885 $ 1.73 $ 4,068 needs some body work fair condition 

43 RBD 1992 58231 $ 45,680 $ 1.17 $ 2,687 


1 RBD 2005 17785 $ 27,066 $ 1.52 $ 6,767 


Replacement Plan: replace #24 in 2011 (order in 2010) & #43 in 2013 (order in 2012) 

18 Panel Van - UG 2008 14722 $ 3,682 $ 0.25 $ 3,682 

new 

Replacement Plan: replace #18 in 2020+. 

FESTIVAL HYDRO - SMALL VEHICLE INVENTORY AND REPLACEMENT PLAN 

Total Maint Average Inspection Other 

Vehicle Type Year Odometer $ to date Cost/km Cost/yr Defects Comments 

14 Pickup 2002 121093 $ 35,405 $ 0.29 $ 5,058 

very good condition 

7 Pickup 1996 106734 $ 28,216 $ 0.26 $ 2,170 

propane-fails etest 

8 Pickup 2004 96250 $ 26,142 $ 0.27 $ 5,228 

very good condition 

25 Pickup 2007 19882 $ 8,169 $ 0.41 $ 4,085 

new 

40 Pickup 1997 161777 $ 28,975 $ 0.33 $ 2,415 


41 Pickup 2006 87242 $ 15,960 $ 0.18 $ 5,320 


Replacement Plan: replace #7 (and sell #40) in 2009. 

20 Sedan 1999 126976 $ 18,018 $ 0.14 $ 1,802 


15 Sedan 1996 108628 $ 17,858 $ 0.16 $ 1,374 body rusting fair condition 

Replacement Plan: replace #15 in 2009 and #20 in 2010. 

17 Van - Engineering 1999 70322 $ 17,154 $ 0.24 $ 1,715 


11 Van - Metering 2008 14154 $ 1,639 $ 0.12 $ 1,639 

new 

9 Van - Locator 2005 47655 $ 16,775 $ 0.35 $ 4,194 

excellent condition 

13 Van - Maintenance 1997 76560 $ 28,072 $ 0.37 $ 2,339 


Replacement Plan: replace #13 in 2010, #17 in 2012. 

2009 2010 2011 2012 2013 


Replace Pickup/Minivan/Car 50000 40000 30000 

Replace Panel Van 

Replace Backhoe 80000 

Replace Trailers 15000 

Replace Single Bucket 260000 

Replace Double Bucket 290000 300000 

Replace RBD 290000 295000 

Note: Due to extended delivery times for large vehicles, orders take place 1 year in advance.


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Appendix 8 – 2008 Reliability Report 

2008 SYSTEM RELIABILITY 

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February 20, 2009 

prepared by: 

Jac Vanderbaan, P.Eng. 

Vice-President of Engineering & Operations 

Executive Summary 

This report reviews the reliability of the distribution system owned and operated by Festival Hydro, for the 

year 2008. Comparisons are made to provincial and international standards. Root causes are identified 

and recommendations made to improve the system reliability. This report is an annual report presented

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to Festival Hydro management and the Board of Directors. Comments or questions should be directed to 

the author.


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BACKGROUND 

Festival Hydro is required by the Ontario Energy Board (OEB) to achieve minimum performance 

standards regarding customer service and system reliability. The standards for reliability are not 

prescriptive, but the OEB expects utilities to maintain their systems to prevent degradation in the 

reliability. The OEB anticipates requiring minimum acceptable levels of reliability as part of the second 

generation of performance based rates. For the present time, a five year rolling average is used and five 

years worth of data is presented in this report. 

Data regarding outages is collected daily and reported every year to the OEB. For system reliability, five 

indicators are used, and the first two are reported to the OEB. 

The standard reliability indices are weighted by customer and presented as averages. For example, a 

SAIDI of 2.0 means the average customer was off for 2 hours during the entire year. Not all customers on 

that feeder or in that area were off for 2 hours – some were off for more, some were off for less. Likewise 

with SAIFI – a SAIFI of 3.2 means some customers had more than 3 outages while some had less. This 

concept is particularly important when looking a feeder specific data – it is still an average value. The 

way the indices are calculated means that a 15 minute outage to 5000 customers will have a much 

greater impact than a 15 minute outage to only 10 customers, even though both outages may have been 

caused by a tree contact. With a relatively small customer base, it only takes one or two outages to a 

main feeder in any given year to push the reliability indices higher than average. This could give the 

impression that the reliability is getting worse, when in reality the actual number of outages is declining 

and the increase in the reliability indices is more related to chance than poor performance. To account for 

this, data regarding the number of outages and causes of the outages is also examined and summarized 

below. 

RELIABILITY INDICIES 

A) System Average Interruption Duration Index (SAIDI) – this is the length of time in hours during 

the year that power was not available to the average customer. 

SAIDI – Historical Performance 

Outage Hours/Year 

Area 2004 2005 2006 2007 2008 

Ontario Avg 1 1.20 2.19 2.78 2.38 - 

Festival - Total 1.91 2.35 3.07 4.18 1.73 

Stratford 1.77 1.35 1.92 2.5 2.13 

68M2 1.28 0.88 2.4 4.6 1.15 

68M3 4.81 0.96 3.66 3.1 4.41 

68M4 0.58 1.45 1.10 3.9 0.26 

68M5 0.23 0.15 0.75 1.1 1.50 

68M8 0.03 4.00 2.01 2.9 1.56 

St Marys 0.77 2.79 5.18 2.2 0.15 

9M1 0.03 0.00 4.17 0.9 0.00 

9M2 5.03 7.29 10.75 0.4 0.05 

9M3 0.18 2.23 3.22 1.2 0.10 

9M4 0.38 2.29 4.93 3.1 0.19 

1 Ontario averages are based on responses to the MEARIE survey.

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For 2008, the average Festival Hydro customer would have been without power for a total of 1.73 

hours for the entire year. Stratford customers would have been without power for 2.13 hours 

while St. Marys customers would have been without power for 0.15 hours. 

The impact of “Loss of Supply” outages is usually negligible for Stratford and St. Marys 

customers, since both are supplied directly by transformer stations. However, in 2008 a Hydro 

One problem with the 68M3 feeder had an impact. Also, Seaforth, Brussels, Hensall, Dashwood, 

and Zurich are supplied by Hydro One distribution feeders and are much more affected by “Loss 

of Supply” issues. This can be seen in the reduction in the FHI-Total from 1.73 to 1.16 when 

Loss of Supply outages are excluded. 

SAIDI – Excluding Loss of Supply 

Outage Hours/Year 

Area 2004 2005 2006 2007 2008 

Ontario Average 0.84 1.34 1.27 1.59 - 

FHI – Total 1.49 0.98 2.17 2.54 1.16 


68M2 1.28 0.88 2.4 4.6 1.15 

68M3 4.81 0.96 3.66 3.1 2.66 

68M4 0.58 1.45 1.10 3.9 0.26 

68M5 0.23 0.15 0.75 1.1 1.5 

68M8 0.03 4.00 2.01 2.9 1.56 

St Marys 0.68 1.81 5.18 2.1 0.15 

9M1 0.03 0.00 4.17 0.8 0.00 

9M2 5.03 2.96 10.75 0.3 0.05 

9M3 0.18 2.23 3.22 1.1 0.10 

9M4 0.38 2.05 4.93 2.8 0.19 

B) System Average Interruption Frequency Index (SAIFI) – this is the number of outages (greater 

than 1 minute) during the year that affects the average customer. 

SAIFI – Historical Performance 

Number of Outages/Year 

Area 2004 2005 2006 2007 2008 


Festival 1.82 2.49 3.43 4.82 1.86 


68M2 1.15 1.11 4.14 3.1 1.26 

68M3 4.14 1.20 4.47 4.2 4.49 

68M4 1.05 1.64 2.06 3.1 0.26 

68M5 1.05 0.20 3.13 3.1 1.14 

68M8 0.05 3.56 2.10 3.2 1.07 

St Marys 1.71 5.38 4.82 4.8 0.76 

9M1 0.10 0.00 3.60 3.6 0


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9M2 1.58 4.15 6.02 1.4 0.06 

9M3 0.14 1.84 4.26 2.6 0.08 

9M4 1.07 3.37 5.35 6.4 1.17 

For 2008, the average Festival Hydro customer would have experienced 1.86 outages greater 

than 1 minute in length. As with SAIDI, SAIFI was impacted due to Loss of Supply. This can be 

seen in the reduction in the FHI-Total from 1.86 to 1.36 when Loss of Supply outages are 

removed. 

SAIFI – Excluding Loss of Supply 


Area 2004 2005 2006 2007 2008 


FHI – Total 1.49 1.13 3.06 2.81 1.36 


68M2 1.15 1.11 4.14 3.1 1.26 

68M3 4.14 1.20 4.47 4.2 3.49 

68M4 1.05 1.64 2.06 3.1 1.16 

68M5 1.05 0.20 3.13 3.1 1.14 

68M8 0.05 3.56 2.10 3.2 1.07 

St Marys 0.79 2.39 4.82 3.0 0.76 

9M1 0.10 0.00 3.60 1.8 0 

9M2 1.58 2.15 6.02 0.2 0.06 

9M3 0.14 1.84 4.26 1.6 0.08 

9M4 1.07 3.26 5.35 4.3 1.17 

C). Customer Average Interruption Duration Index (CAIDI) – this is the average length of an 

outage in hours seen by the average customer. 

CAIDI – Historical Performance 

Average Length of Outage in Hours 

Area 2004 2005 2006 2007 2008 

Ontario Avg 1.058 1.83 1.67 1.18 - 



68M2 1.12 0.79 0.58 1.5 0.91 

68M3 1.16 0.80 0.82 0.7 0.98 

68M4 0.55 0.88 0.53 1.3 0.23 

68M5 0.21 0.74 0.24 0.3 1.32 

68M8 0.58 1.12 0.96 0.9 1.45 

St Marys 0.45 0.52 1.07 0.5 0.193 

9M1 0.28 - 1.16 0.3 0 

9M2 3.18 1.76 1.79 0.3 0.89 

9M3 1.25 1.21 0.76 0.4 1.33 

9M4 0.36 0.68 0.92 0.5 0.16

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For 2008, the average length of an outage for Festival Hydro customers was .93 hours or 56 

minutes. 

CAIDI – Excluding Loss of Supply 

Average Length of Outage in Hours 

Area 2004 2005 2006 2007 2008 


FHI – Total 1.01 0.87 0.71 0.90 0.85 


68M2 1.12 0.79 0.58 1.5 0.91 

68M3 1.16 0.80 0.82 0.7 0.76 

68M4 0.55 0.88 0.53 1.3 0.23 

68M5 0.21 0.74 0.24 0.3 1.32 

68M8 0.58 1.12 0.96 0.9 1.45 

St Marys 0.85 0.76 1.07 0.7 0.193 

9M1 0.28 - 1.16 0.4 0 

9M2 3.18 1.37 1.79 1.4 0.89 

9M3 1.25 1.21 0.76 0.7 1.33 

9M4 0.36 0.63 0.92 0.7 0.16 

D) Index of Reliability – this identifies the percentage of the time that service was available 

during a given year. There are 8760 hours in one year; therefore, 1 hour is equal to 0.011%. 

Index of Reliability – Historical Performance 

Percentage of Time Available 

Area 2004 2005 2006 2007 2008 

Ontario 99.986 99.975 99.968 99.973 - 

Avg 



68M2 99.985 99.990 99.973 99.947 99.987 

68M3 99.945 99.989 99.958 99.965 99.950 

68M4 99.993 99.983 99.987 99.955 99.997 

68M5 99.997 99.998 99.991 99.987 99.983 

68M8 100.000 99.954 99.977 99.967 99.982 

St Marys 99.991 99.968 99.941 99.975 99.998 

9M1 100.000 100.000 99.952 99.990 100.000 

9M2 99.943 99.917 99.877 99.995 99.999 

9M3 99.998 99.975 99.963 99.986 99.999 

9M4 99.996 99.974 99.944 99.965 99.998 

In 2008, the average Festival Hydro customer could expect the power to be available 99.98% of 

the time.

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E) System Average Automatic Reclosure Index (SAARI) – this is the average number of 

momentary interruptions (less than 1 minute) seen by the average customer in one year. 

SAARI – Historical Performance 

Average Number of Momentary Interruptions/Year 

Area 2004 2005 2006 2007 2008 




68M2 3.0 8.0 13.0 5 9 

68M3 3.0 9.0 12.0 13 15 

68M4 6.0 7.0 4.0 0 3 

68M5 21.0 7.0 16.0 15 23 

68M8 0.0 4.0 0.0 4 2 

St Marys 2.12 16.29 30.15 26.8 14.14 

9M1 2.0 3.0 3 5 

9M2 3 12.0 23.0 16 6 

9M3 5 6.0 16.0 10 4 

9M4 24.0 41.0 34 16 


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In 2008, the average Festival Hydro customer would have experienced 11.7 outages of less than 

1 minute in length. (Note that very few Ontario utilities report this index.) 

DATA ANALYSIS 

To get a better understanding of what is happening to the distribution system, the data is 

analyzed excluding the number of affected customers, excluding Loss of Supply outages (which 

are upstream of the distribution system) and excluding Scheduled outages (which are not a result 

of problems with the distribution system). 

A) Number Of Outages – the quantity of outages greater than 1 minute in a given year, excluding 

Loss of Supply and Scheduled. Note that the number of outages does not mean the entire feeder 

experienced an outage, only that the outage occurred somewhere on that feeder. 


Area 2004 2005 2006 2007 2008 

Festival 147 158 160 130 93 

Stratford 69 72 85 75 60 

68M2 11 6 8 9 9 

68M3 26 28 30 25 20 

68M4 13 12 12 10 9 

68M5 16 15 30 22 19 

68M8 3 11 5 9 3 

St Marys 27 39 32 24 10 

9M1 2 0 2 2 0


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9M2 3 8 6 6 2 

9M3 7 7 8 5 2 

9M4 15 24 16 11 6 

B) Number Of Feeder Lockouts – the quantity of outages greater than 1 minute in a given year 

that affected the entire feeder (Feeder Lockout). 

Number of Feeder Lockouts/Year 

Area 2004 2005 2006 2007 2008 Total 

Festival 7 10 26 24 8 75 

Stratford 7 6 14 15 7 49 

68M2 1 1 4 3 1 10 

68M3 4 1 4 4 4 17 

68M4 1 1 2 3 1 8 

68M5 1 0 3 2 1 7 

68M8 0 3 1 3 0 7 

St Marys 0 4 12 9 1 26 

9M1 0 0 2 2 0 4 

9M2 0 0 1 0 0 1 

9M3 0 1 4 2 0 7 

9M4 0 3 5 5 1 14 

C) Number Of Outages by Cause – the quantity of outages greater than 1 minute for each cause 

in a given year, excluding Loss of Supply and Scheduled. 

TREND ANALYSIS 


Cause 2004 2005 2006 2007 2008 Total 

Adverse Weather 23 11 3 15 8 60 

Defective Equipment 58 74 60 46 39 275 

Foreign Interference 44 44 35 47 25 195 

Human Error 0 1 2 1 2 6 

Lightning 6 8 14 3 8 39 

Tree Contacts 10 9 27 14 9 69 

Unknown 6 11 19 4 2 42 

Total 147 158 160 128 93 686 

SAIDI (duration) 

The duration of the average outage had been increasing since 2004, but 2008 showed a 

significant improvement. Loss of Supply issues had a significant impact in the 2008 

results, accounting for 33% of the total.

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The frequency of outages had also been increasing since 2004, but 2008 was much 

better. Again Loss of Supply issues had a significant impact in the 2008 results, 

accounting for 27% of the total. 

SAARI (frequency of momentary outages) 

The frequency of momentary outages was unchanged from 2007, but was still higher 

than previous years. St Marys was much better while Stratford had more momentary 

outages than normal. 

Number of Outages (excluding Loss of Supply and Scheduled) 

The number of outages per year is showing a downward trend, with 2008 having the 

lowest number of outages in the past 5 years. 

Number of Feeder Lockouts (outages to entire feeder) 

The number of outages affecting entire feeders was showing an upward trend but this 

changed in 2008 with significantly fewer lockouts. 

Number of Outages by Cause (excluding Loss of Supply and Scheduled) 

Adverse weather outages have been declining over the past 5 years, although there was 

an increase in 2007. 

Defective equipment outages have been steadily decreasing over the past 5 years, with 

2008 the lowest on record. 

Foreign interference outages (animals, vehicles) have remained fairly constant over the 

past 5 years, although 2008 was better. 

Human error remains the lowest of the causes with a maximum of 2 in any given year. 

(For the 2 in 2008, one was a result of a homeowner knocking their own meter off with a 

trailer and the other outage was an employee who missed restoring power to a customer 

after a planned outage.) 

Lightning outages were down significantly in 2007 but this was due to the lack of lightning 

activity. For 2008, the number was back to typical. 

Tree contact outages are about average, although 2008 was lower than normal. 

Unknown outages were much lower in 2008, with only 2 outages where no cause was 

determined. 

The number of outages greater than 1 minute is decreasing in almost all categories, and in 2008 

the Reliability Indices improved. This indicates that outages in 2008 affected fewer customers 

than 2007, which is validated by the decrease in the number of outages affecting entire feeders. 

Better tree trimming, the addition of insulated brackets in St Marys, and continued preventative 

maintenance are contributing to the improved reliability.


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DETAILED ANALYSIS 

DURATION: 

SAIDI was adversely impacted by one Loss of Supply (Hydro One) outage in January 

due to a malfunction of the Stratford M3 breaker which resulted in an outage to 3400 

customers for almost 2 hours. Excluding this single outage, the SAIDI improves from 

1.73 to 1.41. SAIDI was also impacted by a feeder lockout in December to the Stratford 

M5 breaker which was caused by an insulator failure in the Glastonbury area. The 

outage affected 5000 customers for just over an hour. Excluding this outage, the SAIDI 

further improves to 1.07. 

FREQUENCY: 

SAIFI was also adversely impacted by the same outages that impacted SAIDI. Without 

the Loss of Supply outage, SAIFI improves from 1.86 to 1.68. If the insulator failure 

outage is excluded, SAIFI further improves to 1.42. 

OUTAGE CAUSES: 

In 2008, the quantity of outages decreased and the number of affected customers also 

decreased. 

Loss of Supply outages affect the most customers and result in the most customer 

hours of outage. In most cases in 2008, these Loss of Supply outages were due to 

severe weather affecting Hydro One distribution circuits that supply Seaforth, Brussels, 

Dashwood, Hensall, and Zurich. Recent discussions with Hydro One indicate that the 

supply to Festival Hydro is within their acceptable levels of reliability and no further 

improvements can be expected in the short term. 

The same storms affected our circuits and resulted in a few outages due to Adverse 

Weather. In 2008, this was less of an issue and the aggressive tree trimming program 

initiated two years ago has shown definite improvement in this area. 

Foreign Interference was down significantly in 2008. There were only 2 animal contacts 

in St Marys in 2008, down from 10 in 2007. In Stratford there were 20 animal contacts in 

2008, down from 35 in 2007. The installation of insulated brackets in St Marys along with 

the more aggressive tree trimming program is responsible for this improvement. The 

success of the insulated brackets in St Marys has led to the use of the brackets in 

Stratford and is included in the 2009 capital budget. 

Tree Contacts decreased from 14 in 2007 to only 9 in 2008. Only one of these contacts 

affected the whole feeder. Most were limited to a single customer or a side street. The 

aggressive tree trimming will continue and we expect to see improved performance in 

2009. 

Defective Equipment outages decreased in 2008, but affected more customers than 

previous years. There were only 39 outages related to equipment failures, which is the 

lowest in the past 5 years, and 5 less than 2007. Three of the failures were customer 

owned equipment, six were transformer failures, and most of the remaining failures were 

related to secondary connections and affected limited numbers of customers. These

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connections are typically 20 or more years old and on the secondary side of 

transformers. Due to the vast quantity of secondary connections (over 75,000 in service), 

the relatively low failure rate (less than 0.03% fail in any given year), and the limited 

impact to customers, it is not practical to take action that specifically addresses these 

types of failures. Our infrared inspection of the main feeders done every 2 years 

identifies most of the potential equipment problems before they cause outages. Our 

policy of re-building aging infrastructure before it becomes unreliable prevents many 

problems associated with old equipment. 

Lightning typically causes only momentary outages, although occasionally we have 

equipment damage. In 2008 there were 8 outages attributed to lightning, which is typical. 

Lightning arrestors are installed with all overhead equipment such as transformers and 

cable terminations which provides a good level of protection. 

The number of Unknown outages was down in 2008, with only 2 instances where the 

cause could not be positively identified. Animal contacts and tree contacts are the most 

likely reasons for these outages. 

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Weather = outage caused by high winds, blowing debris, ice, flooding 

Equipment = outage caused by failure of distribution equipment 

Foreign Interference = outage caused by animals, vehicles, vandalism 

Human Element = outage caused by human error 

Lightning = outage caused by lightning strike 

Loss of Supply = Outages on Hydro One System Supplying Festival Hydro 

Scheduled = planned outage by Festival Hydro needed to upgrade system 

Tree Contact = outage caused by contact with tree or tree limb 

Unknown = no cause could be found

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POOR PERFORMING FEEDERS: 


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The outage database used since 2003 allows for detailed analysis of individual feeders. Using 

this database, the top 3 worst performing feeders have been identified using customer minutes of 

outage as the primary criteria (excluding scheduled outages, and loss of supply outages). 

The decision to rank the feeders based on customer minutes of outage is based on the 

assumption that the objective is to improve the overall system reliability by identifying those areas 

that contribute the most to the overall indices of SAIDI and SAIFI. This will have the effect of 

decreasing the duration and frequency of outages to the average customer. Due to this concept, 

the feeders with the most customers naturally become the targets for potential improvements 

while feeders with fewer customers may have poorer values for feeder specific SAIDI and SAIFI. 

For example, in 2007 the feeder with the worst SAIDI was the 68M2, yet it ranks in the middle of 

the pack when customer minutes of outage are used as the ranking method since it has relatively 

fewer customers than many of the other feeders. 

The chart below ranks the Stratford and St Marys feeders from worst to best based on the 

cumulative customer minutes of outage over the past 5 years. 

Feeder 2004 2005 2006 2007 2008 Total 

68M3 973938 188834 744652 629566 898788 3435778 42% 

9M4 37434 214336 528320 302850 20551 1103491 14% 

68M5 62201 18387 210586 292350 449835 1033359 13% 

68M4 74470 185750 140174 498472 34091 932957 11% 

68M2 69243 45685 129632 248565 62003 555128 7% 

68M8 1385 179411 18502 128970 70170 398438 5% 

9M3 5011 61908 94816 32326 3028 197089 2% 

9M2 3700 34607 21795 7195 1550 68847 1% 

9M1 858 12510 2430 0 15798 0% 

Total 1228240 928918 1900987 2142724 1967729 8168598 

1. 68M3 Feeder in Stratford 

This feeder supplies primarily residential customers in the south-central area of Stratford, 

and is almost exclusively overhead distribution in older residential areas. The proximity 

to mature trees makes this feeder susceptible to squirrel contacts, averaging about 8 

squirrel contacts per year and 6 in 2008. Tree contacts were a problem in 2005 but a 

focused effort to trim trees in this area has reduced tree contacts down to zero in 2007 

and only 3 in 2008. The worst outage was the Loss of Supply issue with Hydro One 

when the breaker tripped for no apparent reason and could not be remotely closed back 

in. The breaker (and relaying) has been repaired and tested by Hydro One following this 

outage. Adverse weather and lightning also had an impact on this feeder in 2008. 

2. 9M4 Feeder in St Marys 

This feeder supplies the west ward of St Marys, basically everything west of James St 

and south of the river. It is similar to the Stratford M5 feeder as it is a long feeder through 

older residential areas with mature trees. This makes it susceptible to tree contacts and 

squirrel contacts. The installation of insulated brackets in 2008 significantly reduced the

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number of outages on this feeder. There were only 2 tree related outages in 2008 and no 

confirmed squirrel contacts in 2008, although there were 2 outages where no cause was 

identified. 

3. 68M5 Feeder in Stratford 

This feeder supplies about 5000 customers in the west third of Stratford. It is the longest 

feeder with the most exposure, making it the most susceptible to weather and tree 

contacts. Extensive tree trimming is done on this feeder on a regular basis, and there 

was only 1 tree related outage in 2008 which impacted only 1 customer. The biggest 

problem on this feeder was a failed 27.6 kV insulator that caused the feeder to lockout 

and had 5000 customers off for almost 2 hours (the outage occurred at night and the 

failure took some time to locate). 

MOMENTARY OUTAGES: 

The SAARI index – System Average Automatic Reclose Index measures the number of outages 

less than 1 minute, as seen by the average customer. The graph following shows the causes of 

the outages for the past five years based on number of customers affected. 

There was a significant decrease in foreign interference momentary outages, primarily due to a 

reduction in the number of squirrel contacts in St Marys. The longer insulated brackets installed 

in 2008 appear to have significantly reduced the number of momentary outages due to squirrels. 

There were slight increases in momentary outages due to weather, lightning, and equipment 

failure. The biggest impact was a padmount transformer failure on the 68M5 feeder in Stratford 

that caused three momentary outages before it finally caused a permanent outage and tripped 

the feeder off. 

Many utilities do not report their momentary outages so it is difficult to determine if our numbers 

are higher or lower than similar utilities. The system in Stratford is somewhat unusual in the 

distribution of customers, such that 25% of all our customers are on the 68M5 feeder, so every 

reclose on that feeder affects over 5000 customers.

1 

2 


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 2 

Appendix A 




EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 2 

Appendix A 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

26 

27 

28 

29 

30 

31 

32 

33 

34 

35 

36 

37 

38 

39 

40 

41 

42 

43 

44 

45 

46 

47 

48 

49 

50 

RECOMMENDATIONS 

CAPITAL BUDGET ITEMS 

Excluding Loss of Supply and Scheduled Outages, most of the outages are due to defective equipment 

and foreign interference. Of the three worst performing feeders, the 9M4 in St Marys showed significant 

improvement in 2008 following the installation of insulated brackets which prevented squirrel contacts. 

The number of equipment related outages has been steadily decreasing over the past 5 years, primarily 

due to our policy of proactively replacing aging infrastructure before it becomes unreliable. Based on 

these results, the focus of the capital budget going forward will add insulated brackets to the 68M3 feeder 

in Stratford, and continue the replacement of aging infrastructure. For 2009, the areas selected are 

Zurich, Water Street and Victoria Street (9M4) in St Marys, and the Nile Street and Coburg Street (68M3) 

area of Stratford. 

The implementation of the Smart Switches in the industrial areas of Stratford starting in 2006 has proven 

effective in reducing the overall duration of outages. In 2009, two switches will be added in the Lorne and 

Erie area of Stratford to provide automatic transfer between the 68M3 and 68M2 feeders. This will 

improve the performance of the 68M3 feeder which has been the worst overall performer. In 2010, two 

switches will be added to the 68M4 feeder to provide automatic transfer for the downtown area. In 2011, 

one switch will be added near SGH to automatically transfer the hospital area if the 68M5 locks out. 

During 2009, the option of using reclosures on the 68M5 feeder will be investigated to split the feeder into 

zones and allow for fewer customer to be affected by outages. Reclosures will be installed on the 68M5 

in 2010. 

OPERATING BUDGET ITEMS 

The Operations Manager will continue to meet with the City of Stratford and Town of St Marys 

representatives on a regular basis to review tree trimming requirements and performance. For 2009, 

particular emphasis will be placed on the 68M3 feeder in Stratford. 

The biannual infrared inspection of the system was completed in January 2008 and will be conducted 

again in January 2010. Dry ice cleaning of padmount switches takes place following the infrared 

inspection. The infrared inspection and dry ice cleaning have proven to be effective at reducing the 

number of equipment outages from 80 in 2003 to 46 in 2007. 

A more formal approach to regular line patrols will be created in 2009, complete with documentation and 

schedules. The current approach has been ad-hoc with limited documentation. 

This information has been prepared by Jac Vanderbaan, P.Eng., Vice-President of Engineering & 

Operations. Any questions should be directed to the author. 


187 Erie Street 

PO Box 397 


Attention: Jac Vanderbaan, P.Eng. 

Vice-President of Engineering & Operations 

Phone: 519-271-4703x241 

Fax: 519-271-7204 

Email: jvanderbaan@festivalhydro.com


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 3 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

CAPITALIZATION POLICY: 

FHI’s Capitalization Policy is as follows: 

1. Definition of an Asset 

CICA Handbook paragraph 1000.29 defines assets as economic resources controlled by an entity 

as a result of past transactions or events from which future economic benefits may be obtained. 

Assets have three essential characteristics: 

1. They embody a future benefit that involves a capacity, singly or in combination with 

other assets, in the case of profit-oriented enterprises, to contribute directly or indirectly 

to future net cash flows and in the case of not-for-profit organizations, to provide 

services. 

2. The entity can control access to the benefit. 

3. The transaction or event giving rise to the entity’s right to, or control of, the benefit has 

already incurred. 

In addition, in identifying a benefit there must be: 

A. An ability to earn income or supply a service. 

B. A reasonable expectation that the benefit will be provided in future periods. 

C. The future period must be identifiable and greater than one year. 

The CICA Handbook specifically defines a capital asset as identifiable assets comprising 

property, plant and equipment and intangible properties that meet all of the following criteria: 

1. Are held for use in the production of supply of goods and services, for rental to others, 

for administrative purposes or for the development, construction, maintenance or repair 

to other capital assets.


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 3 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

2. Have been acquired, constructed or developed with the intention of being used on a 

continuing basis. 

3. Are not intended for sale in the ordinary course of business. 

In regard to whether to capitalize intangible property costs, the CICA Handbook states that a 

degree of certainty as to future benefits to be derived from costs attributed to developing 

intangible properties varies and in many cases, the expected future benefits may be too uncertain 

to justify asset recognition. However, when future benefits are reasonably assured, such costs 

should be capitalized (subject to materiality considerations) (CICA s 3062.07). 

2. Capitalizing Upgrades and Improvements – “Betterments” 

Betterment is defined as the cost incurred to enhance the service potential of a capital asset. 

Service potential may be enhanced: 

12 

 

when there is an increase in the previously assessed physical output or service capacity, 

13 

 

associated operating costs are lowered, 

14 

 

the life or useful life is extended, or 

15 

 

the quality of output is improved. 

16 

17 

18 

19 

20 

21 

22 

23 

The definition of betterment is more difficult to apply to tangible capital assets that are complex 

networks of systems and are very long-lived, such as water systems because identifying 

expenditures that extend their lives may not be practicable. 

For complex network systems the following distinctions can be used to identify maintenance and 

betterments: 

1. Maintenance and repairs maintain the predetermined service potential of a tangible 

capital asset for a given useful life. Such expenditures are expenses in the period in 

which they are made.


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 3 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

a. A repair or replacement is comprised of the repair of an existing component, or the 

replacement of an existing component with a similar component. 

Betterments increase service potential (and may or may not increase the useful life of a tangible 

capital asset). Such expenditures would be included in the cost of the related asset. 

3. Capitalization Threshold 

Theoretically, any item that meets the definition and recognition criteria would be recorded as a 

TCA. In practical terms departments shall treat as a capital asset any asset that in addition to the 

above conditions has a useful life in excess of one year and a per item cost greater than $1,000. 

This threshold may be changed at the discretion of the President and on an item-by-item basis if 

a department wishes to capitalize an amount lower than the amount prescribed above in order to 

ensure all material capital assets are included in the financial statements. Assets below the 

threshold are expensed in the period of purchase. 

Land will always be capitalized, regardless of cost. 

14


EB-2009-0263 

Exhibit 2 

Tab 3 

Schedule 3 



1 

Characteristics to Consider 

Repairs = Expense 

All items – life less than 1 year 

Betterments = Capital Assets 

Life of more than 1 year 

All items under $1,000 Items greater than $1,000 

Replacement of individual components of a 

TCA due to age, “wear-and-tear” and 

damage in order to maintain the TCA in an 

operating condition without significantly 

enhancing functionality, capacity, usability 

and efficiency 

Renovations – carpeting, painting, etc. 

System and equipment repairs, in cases 

where the service potential of a building 

isn’t enhanced, repairs – boilers, elevators, 

control system, etc. 

Building repairs that are required in the 

normal maintenance process 

Repairs to restore assets damaged by fire, 

flood or similar events, to a condition just 

prior to the event 

Replacement of motor and parts that 

prolong the useful life 

The estimated life of the asset is extended 

by more than 25% 

The cost results in an increase in the 

capacity of the asset 

The efficiency of the asset is increased by 

more than 10% 

Significantly changes the character of the 

asset 

Reduction in operating cost 

2


EB-2009-0263 

Exhibit 2 

Tab 4 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

WORKING CAPITAL CALCULATION: 

Overview: 

FHI’s working capital allowance is forecast to be $7,335,724 for 2010 and is based on the “15% 

of specific OM&A accounts formula approach” referred to at page 15 of the Board's Filing 

Requirements. FHI has provided its calculations by account for each of 2006 Actual, 2007 

Actual, 2008 Actual, the 2009 Bridge Year and the 2010 Test Year in Table 1 on the following 

pages. 

FHI has provided a spreadsheet setting out FHI’s Cost of Power calculations as Appendix A to 

this Schedule. The cost of the commodity has been calculated at the rate approved in the Board’s 

Decisions and Orders for numerous approved 2009 Cost of Service rate applications. 

11


EB-2009-0263 

Exhibit 2 

Tab 4 

Schedule 1 



1 

2 

Table 1 

WORKING CAPITAL ALLOWANCE FOR 2006 


Distribution Expenses 

$ Distribution Expenses 

$ 

Distribution Expenses - Operation 

528,712.05 Distribution Expenses - Operation 

522,506.42 

Distribution Expenses - Maintenance 

674,908.00 Distribution Expenses - Maintenance 

835,083.00 

Billing and Collecting 

962,636.34 Billing and Collecting 

921,772.98 

Community Relations 

113,312.62 Community Relations 

157,301.47 

Administrative and General Expenses 

1,348,435.70 Administrative and General Expenses 1,249,981.83 

Taxes Other than Income Taxes 

129,853.40 Taxes Other than Income Taxes 

124,805.40 

3 

4 

Total Eligible Distribution Expenses 

Power Supply Expenses 

Total Working Capital Expenses 

Working Capital Allowance rate of 15% 

3,757,858.11 Total Eligible Distribution Expenses 3,811,451.10 

44,210,195.12 Power Supply Expenses 

44,549,337.39 

47,968,053.23 Total Working Capital Expenses 48,360,788.49 

7,195,207.98 Working Capital Allowance rate of 15% 7,254,118.27 

WORKING CAPITAL ALLOWANCE FOR 2008 WORKING CAPITAL ALLOWANCE FOR 2009 


$ Distribution Expenses 

$ 


623,913.05 Distribution Expenses - Operation 

640,790.99 


745,455.00 Distribution Expenses - Maintenance 

766,334.78 


928,130.60 Billing and Collecting 

1,022,792.01 


12,067.21 Community Relations 

22,373.98 

Administrative and General Expenses 1,383,769.27 Administrative and General Expenses 

1,410,622.13 


59,500.00 Taxes Other than Income Taxes 

89,490.00 

5 

6 





3,752,835.13 Total Eligible Distribution Expenses 3,952,403.89 

43,327,319.42 Power Supply Expenses 

46,148,115.85 

47,080,154.55 Total Working Capital Expenses 50,100,519.73 

7,062,023.18 Working Capital Allowance rate of 15% 7,515,077.96 



$ 


658,189.90 


787,806.83 


1,020,272.34 


42,930.10 


1,459,147.39 


50,317.00 

7 





4,018,663.55 

44,886,161.21 

48,904,824.76 

7,335,723.71


EB-2009-0263 

Exhibit 2 

Tab 4 

Schedule 2 



1 

2009 COST OF POWER FORECAST CALCULATION: 

2 

Electricity - Commodity 

2009 

Forecasted 


Class per Load Forecast 

Metered 

kWhs 

2009 Loss 

Factor 2009 

Residential 136,118,685 1.0281 139,943,621 $0.06072 $8,497,377 

Residential Hensall 3,991,187 1.0281 4,103,339 $0.06072 $249,155 

GS50kW Secondary metered 140,869,393 1.0281 144,827,823 $0.06072 $8,793,945 

GS>50kW Primary metered 171,660,921 1.0178 174,716,486 $0.06072 $10,608,785 

Large Use 66,477,958 1.0045 66,777,109 $0.06072 $4,054,706 

Street Lighting 3,873,055 1.0281 3,981,888 $0.06072 $241,780 

Sentinel Lighting 226,715 1.0281 233,085 $0.06072 $14,153 

Unmetered Scattered Load 655,210 1.0281 673,622 $0.06072 $40,902 

TOTAL 589,836,391 603,073,806 $36,618,642 

589,836,391 

Transmission - Network 

Volume 


Metric 

2009 

Residential kWh 139,943,621 $0.0055 $769,690 

Residential Hensall kWh 4,103,339 $0.0055 $22,568 

GS50kW non-interval kW 145,232 $2.0144 $292,556 

GS>50kW Interval metered kW 641,455 $2.1394 $1,372,329 

Large Use kW 130,519 $2.3689 $309,186 

Street Lighting kW 11,166 $1.5192 $16,963 

Sentinel Lighting kW 656 $1.5269 $1,001 

Unmetered Scattered Load kWh 673,622 $0.0049 $3,301 

TOTAL $3,119,897 

kWh 212,537,416 

929,028 kW 929,028


EB-2009-0263 

Exhibit 2 

Tab 4 

Schedule 2 



1 

Transmission - Connection 

Volume 


Metric 

2009 





Large Use kW 130,519 $1.8849 $246,015 


Sentinel Lighting kW 656 $1.1867 $778 


TOTAL $2,400,715 

kWh 212,537,416 

kW 929,028 

Wholesale Market Service 


2009 

Residential 139,943,621 $0.0052 $727,707 

Residential Hensall 4,103,339 $0.0052 $21,337 

GS50kW 319,544,309 $0.0052 $1,661,630 

Large Use 66,777,109 $0.0052 $347,241 

Street Lighting 3,981,888 $0.0052 $20,706 

Sentinel Lighting 233,085 $0.0052 $1,212 

Unmetered Scattered Load 673,622 $0.0052 $3,503 

TOTAL 603,073,806 $3,135,984 

Rural Rate Assistance 


Residential 139,943,621 

2009 

$0.0013 $181,927 


GS50kW 319,544,309 $0.0013 $415,408 

Large Use 66,777,109 $0.0013 $86,810 


Sentinel Lighting 233,085 $0.0013 $303 

Unmetered Scattered Load 673,622 $0.0013 $876 

TOTAL 603,073,806 $783,996 

2009 

2 

4705-Power Purchased $36,618,642 

4708-Charges-WMS $3,135,984 

4714-Charges-NW $3,119,897 

4716-Charges-CN $2,400,715 

4730-Rural Rate Assistance $783,996 

4750-Low Voltage $88,883 

TOTAL 46,148,116


EB-2009-0263 

Exhibit 2 

Tab 4 

Schedule 2 



1 

2010 COST OF POWER FORECAST CALCULATION: 

2010 

Electricity - Commodity Forecasted 


Metered 2010 Loss 


Residential 

kWhs 

129,739,825 

Factor 

1.0307 133,720,611 

2010 

$0.06072 $8,119,515 

Residential Hensall 3,803,820 1.0307 3,920,532 $0.06072 $238,055 

GS50kW Secondary metered 141,238,817 1.0307 145,572,425 $0.06072 $8,839,158 

GS>50kW Primary metered 169,753,138 1.0204 173,212,030 $0.06072 $10,517,434 

Large Use 65,544,852 1.0075 66,036,439 $0.06072 $4,009,733 

Street Lighting 3,904,130 1.0307 4,023,920 $0.06072 $244,332 

Sentinel Lighting 234,690 1.0307 241,891 $0.06072 $14,688 

Unmetered Scattered Load 629,732 1.0307 649,054 $0.06072 $39,411 

TOTAL 576,872,024 591,302,964 $35,903,916 

576,872,024 

Transmission - Network 

Volume 


Metric 

2010 





Large Use kW 128,687 $1.9948 $256,704 




TOTAL $2,647,842 

kWh 202,216,260 

918,565 kW 918,565 

2 

Transmission - Connection 

Volume 


Metric 

2010 





Large Use kW 128,687 $1.8427 $237,131 




TOTAL $2,409,496 

kWh 202,216,260 

kW 918,565


EB-2009-0263 

Exhibit 2 

Tab 4 

Schedule 2 



Wholesale Market Service 



2010 

$0.0052 $695,347 


GS50kW 318,784,454 $0.0052 $1,657,679 

Large Use 66,036,439 $0.0052 $343,389 


Sentinel Lighting 241,891 $0.0052 $1,258 

Unmetered Scattered Load 649,054 $0.0052 $3,375 

TOTAL 591,302,964 $3,074,775 

Rural Rate Assistance 



2010 

$0.0013 $173,837 


GS50kW 318,784,454 $0.0013 $414,420 

Large Use 66,036,439 $0.0013 $85,847 


Sentinel Lighting 241,891 $0.0013 $314 

Unmetered Scattered Load 649,054 $0.0013 $844 

TOTAL 591,302,964 $768,694 

2010 2009 

1 

4705-Power Purchased $35,903,916 $36,618,642 ($714,726) 

4708-Charges-WMS $3,074,775 $3,135,984 ($61,208) 

4714-Charges-NW $2,647,842 $3,119,897 ($472,054) 

4716-Charges-CN $2,409,496 $2,400,715 $8,781 

4730-Rural Rate Assistance $768,694 $783,996 ($15,302) 

4750-Low Voltage $81,437 $88,883 ($7,447) 

TOTAL 44,886,160 $46,148,116 $0


EB-2009-0263 

Exhibit 3 

Index 




3 – Operating Revenue 

1 Overview 

1 Overview of Operating Revenue 

2 Summary of Operating Revenue Table 

3 Variance Analysis on Operating Revenue 

2 Throughput Revenue 

1 Weather Normalized Load and Customer/ 

Connection Forecast 

A Monthly Data Used for Regression Analysis 

B Heating and Cooling Degrees Table 

3 Other Distribution Revenue 

1 Summary of Other Distribution Revenue 

2 Variance Analysis on Other Distribution 

Revenue 

4 Revenue Sharing 

1 Description of Revenue Sharing


EB-2009-0263 

Exhibit 3 

Tab 1 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

OVERVIEW OF OPERATING REVENUE: 

This Exhibit provides the details of Festival Hydro’s operating revenue for 2006 Board 

Approved, 2006 Actual, 2007 Actual, 2008 Actual, the 2009 Bridge Year and the 2010 Test 

Year. This Exhibit also provides a detailed variance analysis by rate class of the operating 

revenue components. Distribution revenue does not include revenue from commodity sales. 

A summary of operating revenues is presented in Exhibit 3, Tab 1, Schedule 2. 

Throughput Revenue: 

Information related to Festival Hydro’s throughput revenue includes details such as weather 

normalized forecasting methodology, normalized volumes based on historical number of 

customers billed throughout the year and known economic conditions. Detailed variance 

analysis on the throughput revenue is set out in Exhibit 3, Tab 3, Schedules 1 and 2. 

Other Revenue: 

Other revenues include Late Payment Charges, Miscellaneous Service Revenues, Retail Services 

Revenue and other distribution related income. A summary of these operating revenues together 

with a materiality analysis of variances is presented in Exhibit 3, Tab 3, Schedules 1 and 2. 

Revenue Sharing: 

As noted in Exhibit 3, Tab 4, Schedule 1, Festival Hydro does not have a revenue sharing 

practice in place.


EB-2009-0263 

Exhibit 3 

Tab 1 

Schedule 2 



SUMMARY OF OPERATING REVENUE TABLE 

Summary of Operating Revenue Table 

Summary of Operating Revenue 

Table 

2006 Board 

Approved 

2006 Actual 

Variance 

from Board 

Approved 

2007 Actual 

Variance from 

Previous Yr. 

2008 Actual 

Variance from 

Previous Yr. 

2009 Bridge 

Variance from 

Previous Yr. 

2010 Test 

Variance from 

Previous Yr. 

Distribution Revenues 

Residential 4,904,957 4,770,857 (134,100) 5,005,479 234,622 4,986,428 (19,051) 5,010,669 24,241 5,425,568 414,900 

Residential Hensall 72,324 75,858 3,534 88,654 12,796 86,743 (1,911) 83,902 (2,841) 100,492 16,589 

General Service < 50 kW 1,667,381 1,570,915 (96,466) 1,645,904 74,989 1,607,698 (38,206) 1,597,021 (10,677) 1,674,862 77,841 

General service > 50 kW 1,968,846 1,993,753 24,907 2,046,310 52,557 2,038,783 (7,527) 1,962,089 (76,694) 2,184,217 222,128 

Large Use 325,189 223,383 (101,805) 305,507 82,123 304,752 (755) 302,438 (2,314) 320,194 17,756 

Streetlights 53,484 67,836 14,352 65,902 (1,933) 57,701 (8,202) 54,706 (2,995) 104,433 49,726 

Sentinel Lights 2,552 3,298 746 3,359 61 3,422 63 3,509 87 6,896 3,387 

Unmetered Scattered Load 19,114 46,845 27,731 36,642 (10,203) 35,016 (1,626) 35,713 697 35,468 (245) 

Total Distribution Revenue 9,013,847 8,752,745 (261,102) 9,197,758 445,013 9,120,543 (77,214) 9,050,048 (70,495) 9,852,131 802,083 

Other Revenues 

Late Payment Charges 88,469 103,535 15,066 112,817 9,282 125,527 12,711 125,527 (0) 128,414 2,887 

Specific Service Charges 235,745 152,517 (83,229) 215,605 63,088 200,926 (14,679) 202,991 2,065 207,660 4,669 

Other Distribution Revenues and Other 

Income and Expenses 283,550 513,982 230,432 607,149 93,167 464,389 (142,760) 330,595 (133,794) 323,376 (7,219) 

Total Other Distribution Revenue 607,765 770,033 162,268 935,571 165,538 790,842 (144,729) 659,113 (131,729) 659,450 337 

Total 9,621,612 9,522,778 (98,833) 10,133,328 610,550 9,911,385 (221,943) 9,709,161 (202,224) 10,511,581 802,420 

G.L. 9,522,778 (98,833) 10,133,328 610,550 9,911,385 (221,943) 9,709,161 (202,224) 10,511,581 802,420


EB-2009-0263 

Exhibit 3 

Tab 1 

Schedule 3 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

VARIANCE ANALYSIS ON OPERATING REVENUE: 

Festival Hydro’s distribution revenues have been calculated using the OEB approved Schedule 

of Rates and Charges for each of the applicable years. A summary of FHI’s normalized operating 

revenues is set out in Exhibit 3, Tab 1, Schedule 2 above. The following analysis addresses 

variances in those operating revenues. As noted above, distribution revenue does not include 

commodity-related revenue. 

2006 Board Approved: 

Festival Hydro’s 2006 Board Approved operating revenue was forecast to be $9,621,612 as 

shown in Exhibit 3, Tab 1, Schedule 2. Distribution revenue totaled $9,013,847 or 93.7% of total 

revenues. Other operating revenue (net) accounts for the remaining revenue of $607,765. 

2006 Actual: 

Festival Hydro’s operating revenue in fiscal 2006 was $9,522,778 as shown in Exhibit 3, Tab 1, 

Schedule 2. Distribution revenue totaled $8,752,745 or 91.9% of total revenues. Other operating 

revenue (net), accounts for the remaining revenue of $770,033. Large use revenue for 2006 is 

below 2006 Board Approved because the General Service > 50 kW customer in question did not 

get switched to Large Use class until May 1, 2006 when the new rates were in place. 

Comparison to 2006 Board Approved: 

As shown in Exhibit 3, Tab 1, Schedule 2, the total operating revenue was $98,833 lower than 

the 2006 Board Approved level forecasted. Distribution revenue was lower than forecasted 

consumption levels, mainly in the residential rate class and general service less than 50 kW 

categories due to favourable weather conditions throughout the year. Conservation programs 

were also in place focusing on residential and small commercial. Other distribution revenue 

more than made up for the shortfall.


EB-2009-0263 

Exhibit 3 

Tab 1 

Schedule 3 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

2007 Actual: 

Festival Hydro’s operating revenue in fiscal 2007 was $10,133,328, as shown in Exhibit 3, Tab 

1, Schedule 2. Distribution revenue totaled $9,197,758 or 90.8% of total revenues. Other 

operating revenue (net), accounts for the remaining revenue of $935,571. 

Comparison to 2006 Actual: 

As shown in Exhibit 3, Tab 1, Schedule 2, the total operating revenue was $610,550 higher than 

the 2006 actual operating revenue. Distribution revenues increased for most classes due to 

higher sales volumes and from increased distribution rates. Unmetered Scattered Load decreased 

as a result of a new approved monthly service charge rate (approximately one-half of the General 

Service > 50 kW rate that USL was previously charged). Increased Specific Service Charge 

rates approved in the 2006 EDR contributed to higher service charge revenue. The inability to 

disconnect customers over the 2006-7 winter months lead to higher late payment charges. Other 

distribution revenues included the sale of a piece of property (a lot owned next to a municipal 

station for net proceeds of approximately $77,000. 

2008 Actual: 

Festival Hydro’s operating revenue in fiscal 2008 was $9,911,385, as shown in Exhibit 3, Tab 1, 

Schedule 2. Distribution revenue totaled $9,120,543 or 92.0% of total revenues. Other operating 

revenue (net), accounts for the remaining revenue of $790,842. 


As shown in Exhibit 3, Tab 1, Schedule 2, the total operating revenue was $221,943 lower than 

the 2007 actual operating revenue. Distribution revenues were impacted by the economic 

downturn. General Service > 50 kW customers decreased in the last half of the year as a result 

of economic conditions, especially those related to the automotive sector. General services less 

than 50 kW sales were impacted partially due to a downturn in the tourist trade impacting 

restaurants, hotels and other tourist related businesses. Conservation programs are credited for


EB-2009-0263 

Exhibit 3 

Tab 1 

Schedule 3 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

reduced residential sales and sales across general service sectors as many customers in our 

service territory are keen on conservation. Streetlight revenues are down because a few of the 

large customers now purchase their electricity from retailers, so Festival Hydro no longer 

collects the per connection administration fee. Late payment charges were up as a result of more 

general service customers not meeting due dates. 

2009 Bridge Year: 

Festival Hydro’s operating revenue is forecast to be $9,709,161 in fiscal 2009, as shown in 

Exhibit 3, Tab 1, Schedule 2. Distribution revenue totals $9,050,048 or 93.2% of total revenues. 

Other operating revenue (net), accounts for the remaining revenue of $659,113. 


As shown in Exhibit 3, Tab 1, Schedule 2, the total operating revenue is expected to be $202,224 

lower than the actual year level in fiscal 2008. Sales to general service and large use customers 

are expected to be down given the continued economic difficulties that have extended into 2009. 

Residential show slight growth, largely due to May 2009 IRM rates. Late payment charges are 

expected to be flat, after a higher increase last year. Specific service charges are expected to 

have a minimal increase. Other distribution revenues are lower because of significantly less 

interest earned on our bank deposit, and no excess properties for sale. 

2010 Test Year: 

Festival Hydro’s operating revenue is forecast to be $10,511,581 in fiscal 2010, as shown in 

Exhibit 3, Tab 1, Schedule 2. Distribution revenue totals $9,852,131 or 93.7% of total revenues. 

Other operating revenue (net), accounts for the remaining revenue of $659,450. 

Comparison to 2009 Bridge Year: 

As shown in Exhibit 3, Tab 1, Schedule 2, the total operating revenue is expected to be $802,420 

higher than the bridge year level in fiscal 2009. This increase is the result of an increase in 

revenue requirement for 2010. Other distribution revenues are budgeted to increase by only


EB-2009-0263 

Exhibit 3 

Tab 1 

Schedule 3 



1 

2 

$337. (.05%). See Exhibit 6, Tab 1, Schedule 1 for an explanation of the revenue deficiency for 

2010 test year.


EB-2009-0263 

Exhibit 3 

Tab 2 

Schedule 1 



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WEATHER NORMALIZED LOAD AND CUSTOMER/CONNECTION FORECAST 

The purpose of this evidence is to present the process used by Festival Hydro to prepare the 

weather normalized load and customer/connection forecast used to design the proposed 

distribution rates. Festival Hydro reviewed the various processes used by the 2008 and 2009 cost 

of service applicants and is proposing to adopt a weather normalization forecasting method 

similar to the one approved by the Board for Toronto Hydro Electric System Ltd in its 2008, 

2009 and 2010 rate application (EB-2007-0680). A similar method was also approved by the 

Board for the following 2009 cost of service applicants. 

a) Innisfil Hydro Distribution Systems Ltd. 

b) Lakeland Power Distribution Ltd. 

c) Niagara-on-the-Lake Hydro Inc. 

d) Thunder Bay Hydro Electricity Distribution Inc. 

In summary, Festival Hydro has used the same regression analysis methodology used by the 

distributors mentioned above to determine a prediction model. With regards to the overall 

process of load forecasting, it is Festival Hydro’s view that conducting a regression analysis on 

historical purchases to produce an equation that will predict future purchases is appropriate. 

Festival Hydro knows by month the exact amount of kWhs purchased from the IESO and others 

for use by customers of Festival Hydro. With a regression analysis these purchases can be 

related to other monthly explanatory variables such as heating degree days and cooling degree 

days which occur in the same month. The results of regression analysis produce an equation that 

predicts the purchases based on the explanatory variables. This prediction model is then used as 

the basis to forecast the total level of weather normalized purchases for Festival Hydro for the 

bridge and test year which is converted to billed kWh by rate class. A detailed explanation of the 

process is provided later on in this evidence.


EB-2009-0263 

Exhibit 3 

Tab 2 

Schedule 1 



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During the review process of the 2009 cost of service applications, Intervenors expressed 

concerns with the load forecasting weather process being proposed by Festival Hydro. Intevenors 

suggested the weather normalization should be conducted on an individual rate class basis and 

the regression analysis would based on monthly billed kWh by rate class. In Festival Hydro's 

view, conducting a regression analysis which relates the monthly billed kWh of a class to other 

monthly variables is problematic. The monthly billed amount is not the amount consumed in the 

month but the amount billed. The amount billed is based on billing cycle meter reading 

schedules whose reading dates vary and typically are not at month end. The amount billed could 

include consumption from the month before or even further back. By using a regression analysis 

to relate rate class billing data to a variable such as heating degree days does not appear to be 

logical, since the resulting regression model would attempt to relate heating degree days in a 

month to the amount billed in the month, not the amount consumed. In Festival Hydro's view, 

variables such as heating degree days impact the amount consumed not the amount billed. It is 

possible to estimate the amount consumed in a month based on the amount bill but until smart 

meters are fully deployed this would only be an estimate which in Festival Hydro's view would 

reduce the accuracy of a regression model that is based on monthly billing data. In addition, 

Festival Hydro does not have as many years of monthly historical billed data by rate class as it 

does for the amount purchased. As a result, conducting the regression analysis on purchases 

provides better results since a higher level of historical data increases the accuracy of the 

regression analysis. 

Festival Hydro understands that to a certain degree the process of developing a load forecast for 

cost of service rate application is evolving for electric distributors in the province. Festival 

Hydro expects to include additional improvements to the load forecasting methodology in future 

cost of service rate applications by taking into consideration data provided by smart meters and 

how others are conducting load forecasts in future cost of service rate applications. However, 

based on the Board's approval of this methodology in a number of 2009 applications as well as 

the discussion that follows, Festival Hydro submits the load forecasting methodology is 

reasonable at this time for the purposes of the is application.


EB-2009-0263 

Exhibit 3 

Tab 2 

Schedule 1 



1 

2 

3 

4 

5 

Table 1 below provides growth statistics for kWh sold and customer/connection numbers for the 

past eight years. Even though customers/connections are increasing annually, at a very low rate, 

the actual kWh sold started to decline in 2006, then continued to decline in 2007 and 2008, and is 

projected to further decline in 2009 and 2010. Historical and forecast customer numbers, by 

class, are displayed in Exhibit 3, Tab 2, Schedule 2. 

Table 1 

Summary of Load and 

Customer/Connection Forecast 

Year kWh sold Yr over Yr Growth % change 

#Customers/ 

Connections Yr over Yr Growth % change 

2000 596,581,663 23,592 0 

2001 605,241,071 8,659,407 1.45% 23,812 220 0.93% 

2002 624,930,122 19,689,052 3.25% 24,088 276 1.16% 

2003 627,031,302 2,101,180 0.34% 24,318 230 0.95% 

2004 632,340,069 5,308,767 0.85% 24,518 200 0.82% 

2005 632,444,846 104,777 0.02% 24,721 204 0.83% 

2006 617,899,375 (14,545,471) -2.30% 24,905 184 0.74% 

2007 615,535,179 (2,364,196) -0.38% 25,130 225 0.90% 

2008 593,387,454 (22,147,725) -3.60% 25,405 275 1.09% 

2009 (B) 589,836,391 (3,551,063) -0.60% 25,638 233 0.92% 

2010 (T) 576,872,024 (12,964,367) -2.20% 25,874 236 0.92% 

6 

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13 

2000 to 2008 are weather actual data and 2009 and 2010 are weather normalized. Festival 

Hydro currently does not have a process to adjust weather actual data to a weather normal 

basis. However, based on the process outlined in this Exhibit, a process to forecast energy 

on a weather normalized basis has been developed and used in this application. 

The streetlight, sentinel lights and unmetered scattered loads are measured as connections. 

On a rate class basis, actual and forecasted billed amount and number of customers are shown in 

Table 2 and customer usage is shown in Table 3.


EB-2009-0263 

Exhibit 3 

Tab 2 

Schedule 1 



Table 2 

Billed Energy and Number of Customers by Rate Class 

Year 

Residential 

Residential 

Hensall 

General Service 

< 50 kW 


> 50 kW Large Use Street Lighting Sentinel Lights USL Total 

Billed Energy: 

2000 131,516,901 3,859,268 72,417,171 308,580,266 75,496,947 3,598,812 167,853 944,445 596,581,663 

2001 133,084,694 4,099,937 70,701,786 318,799,805 73,794,022 3,619,840 184,736 956,251 605,241,071 

2002 136,573,470 4,302,763 69,388,032 337,201,829 72,301,280 3,657,240 191,754 1,313,754 624,930,122 

2003 135,649,596 4,050,220 71,046,669 334,616,436 76,660,027 3,613,293 148,320 1,246,741 627,031,302 

2004 136,776,916 4,191,324 72,187,366 338,001,625 76,391,354 3,753,742 143,950 893,792 632,340,069 

2005 143,411,804 4,255,224 71,281,495 334,252,910 74,489,819 3,668,342 170,856 914,396 632,444,846 

2006 Board 138,087,026 4,188,086 69,942,364 324,728,477 76,464,298 3,688,157 165,272 1,264,039 618,527,719 

2006 138,207,589 3,852,878 68,326,693 327,886,393 74,918,429 3,697,097 233,476 776,820 617,899,375 

2007 139,603,876 4,054,439 69,632,805 328,163,463 69,600,305 3,522,815 225,471 732,005 615,535,179 

2008 136,970,688 4,016,517 67,284,782 312,948,164 67,424,347 3,842,227 219,010 681,719 593,387,454 

2009 (B) 136,117,457 3,993,693 65,962,671 312,529,632 66,477,958 3,873,055 226,715 655,210 589,836,391 

2010 (T) 129,737,473 3,808,598 62,021,896 310,990,652 65,544,852 3,904,130 234,690 629,732 576,872,024 

Number of Customers/Connections 

2000 15,134 405 1,992 208 2 5,614 77 161 23,592 

2001 15,320 408 1,994 209 2 5,640 78 163 23,812 

2002 15,551 409 1,996 210 2 5,677 79 166 24,088 

2003 15,752 407 2,002 210 2 5,699 78 169 24,318 

2004 15,951 407 2,005 205 2 5,700 77 171 24,518 

2005 16,151 409 1,988 206 2 5,721 80 166 24,721 

2006 Board 16,055 408 2,002 200 2 5,731 67 157 24,622 

2006 16,334 409 1,972 209 2 5,741 81 157 24,905 

2007 16,535 410 1,972 209 2 5,767 81 156 25,130 

2008 16,708 412 1,972 218 2 5,856 82 157 25,405 

2009 (B) 16,910 412 1,970 219 2 5,886 82 156 25,638 

2010 (T) 17,115 413 1,968 221 2 5,916 83 156 25,874


EB-2009-0263 

Exhibit 3 

Tab 2 

Schedule 1 



Table 3 

Annual kWh per Customer 

Year 

Residential; 

Residential 

Hensall 


< 50 kW 


> 50 kW Large Use Street Lighting Sentinel Lights USL 

Energy Unsage by Customer /Connection 

2000 8,690 9,529 36,354 1,487,134 37,748,474 641 2,194 5,866 

2001 8,687 10,061 35,457 1,529,016 36,897,011 642 2,384 5,867 

2002 8,783 10,520 34,764 1,609,555 36,150,640 644 2,443 7,938 

2003 8,612 9,951 35,488 1,593,412 38,330,014 634 1,902 7,399 

2004 8,575 10,298 36,013 1,648,788 38,195,677 659 1,869 5,227 

2005 8,879 10,404 35,865 1,626,535 37,244,910 641 2,149 5,508 

2006 Board 8,601 10,265 34,936 1,623,642 38,232,149 644 2,467 8,051 

2006 8,461 9,420 34,648 1,568,834 37,459,215 644 2,882 4,948 

2007 8,443 9,901 35,311 1,573,925 34,800,153 611 2,801 4,707 

2008 8,198 9,761 34,120 1,435,542 33,712,174 656 2,687 4,356 

2009 (B) 8,139 9,790 33,851 1,429,220 33,238,979 658 2,756 4,197 

2010 (T) 8,080 9,819 33,583 1,422,926 32,772,426 660 2,827 4,044 

Annual Growth Rate in Usage by Customer/Connection 

2001 -0.03% 5.58% -2.47% 2.82% -2.26% 0.12% 8.64% 0.01% 

2002 1.10% 4.56% -1.96% 5.27% -2.02% 0.37% 2.48% 35.31% 

2003 -1.94% -5.41% 2.08% -1.00% 6.03% -1.57% -22.16% -6.79% 

2004 -0.43% 3.48% 1.48% 3.48% -0.35% 3.86% -1.69% -29.36% 

2005 3.55% 1.03% -0.41% -1.35% -2.49% -2.63% 14.96% 5.39% 

2006 -4.71% -9.46% -3.39% -3.55% 0.58% 0.42% 34.12% -10.18% 

2007 -0.22% 5.10% 1.91% 0.32% -7.10% -5.14% -2.83% -4.86% 

2008 -2.90% -1.42% -3.37% -8.79% -3.13% 7.41% -4.06% -7.46% 

2009 (B) -0.73% 0.30% -0.79% -0.44% -1.40% 0.29% 2.57% -3.65% 

2010 (T) -0.73% 0.30% -0.79% -0.44% -1.40% 0.29% 2.57% -3.65% 

1 

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9 

LOAD FORECAST AND METHODOLOGY 

Festival Hydro’s weather normalized load forecast is developed in a three-step process. First, a 

total system weather normalized purchased energy forecast is developed based on a multifactor 

regression model that incorporates historical load, weather, and economic data. Second, the 

weather normalized purchased energy forecast is adjusted by a historical loss factor to produce a 

weather normalized billed energy forecast. Finally, the forecast of billed energy by rate class is 

developed based on a forecast of customer numbers and historical usage patterns per customer. 

For the rate classes that have weather sensitive load, that being residential customers, general 

service less than 50 kW, and part of the load for general service greater than 50 kW, their


EB-2009-0263 

Exhibit 3 

Tab 2 

Schedule 1 



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forecasted billed energy is adjusted to ensure that the total billed energy forecast by rate class is 

equivalent to the total weather normalized billed energy forecast. The forecast of customers by 

rate class is determined using time-series econometric methodologies. For those rate classes that 

use kW for the distribution volumetric billing determinant an adjustment factor is applied to class 

energy forecast based on the historical relationship between kW and kWh. The following will 

explain the forecasting process in more detail. 

Purchased KWh Load Forecast 

The forecast of total system purchased energy is developed using a multifactor regression model 

with the following independent variables: weather (heating and cooling degree days), economic 

output (Ontario GDP growth), population and calendar variables (days in month, seasonal). The 

regression model uses monthly kWh and monthly values of independent variables from January 

1998 to December 2008 to determine the monthly regression coefficients. 

Data for Festival Hydro's total system load is available as far back as January 1998. This 

provides 132 monthly data points, which is a reasonable data set for use in a multiple regression 

analysis. Being Festival Hydro is the amalgamation of six predecessor companies; the ability to 

locate reliable data from prior to amalgamation becomes very challenging. 

Based on the recent global activity surrounding climate change, historical weather data is 

showing that there is a warming of the global climate system. In this regard it is Festival Hydro's 

view that it is appropriate to review the impact of weather since 1998 on the energy usage and 

then determine the average weather conditions from 1998 to 2008 which would be applied in the 

forecasting process to determine a weather normalized forecast. 

The multifactor regression model has determined primary drivers of year-over-year changes in 

Festival Hydro's load growth as economic conditions and weather. Both of these effects are 

captured within the multifactor regression model.


EB-2009-0263 

Exhibit 3 

Tab 2 

Schedule 1 



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Economic growth – which encompasses population trends in Festival Hydro’s service area as 

well as general economic conditions, are captured in the model using an index of economic 

output, Ontario Real Gross Domestic Product ("GDP") and population statistics. 

Weather impacts on load are apparent in both the winter heating season, and in the summer 

cooling season. For that reason, both Heating Degree Days (i.e. a measure of coldness in winter) 

and Cooling Degree Days (i.e. a measure of summer heat) are modeled. 

The third main factor determining energy use in the monthly model can be classified as "calendar 

factors". For example, the number of days in a particular month will impact energy use. The 

modeling of purchased energy uses number of days in the month and a “flag” variable to capture 

the typically lower usage in the spring and fall months. 

The process of developing a model of energy usage involves estimating multifactor models using 

different input variables to determine the best fit. Using stepwise regression techniques different 

explanatory variables were tested with the ultimate model being determined both by model 

statistics and by forecast accuracy. The model chosen as the best predictor of kWh purchased by 

Festival Hydro is as follows: 

Festival Hydro Monthly Predicted kWh Purchases 

= Heating Degree Days x 11,291.68 

+ Cooling Degree Days x 53,870.55 

+ Ontario Real GDP Monthly Index x 520,758.84 

+ Population x (5,588.23) 

+ Number of Days in the Month x 615,104.35 

+ Spring Fall Flag x (195,700.75) 

+ Peak Hours x 46,480.07 

+ Constant of 184,857,725.


EB-2009-0263 

Exhibit 3 

Tab 2 

Schedule 1 



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The monthly data used in the regression model and the resulting monthly prediction for the 

actual and forecasted years are provided in Appendix A. 

The sources of data for the various data points are: 

a) Environment Canada website for monthly heating degree day and cooling degree 

information. Data for the Stratford MOE was used; 

b) The Ontario real GDP monthly index for the period January 1998 to December 2010 was 

derived from the Government of Ontario’s 2003, 2008 and 2009 Ontario Economic 

Outlooks from the Ontario Ministry of Finance.; 

c) Population data was based on Census population data for the City of Stratford and Town 

of St. Marys from the 1998, 2001 and 2006 Census data. Population statistics for the 

smaller towns in Festival‘s service territories were obtained from the municipal offices. 

As noted on the page above, the coefficient on population is negative. This is the result 

of population growth in recent years increasing at a decreasing rate; and 

d) The calendar provided information related to number of days in the month and the 

spring/fall flag. 

The annual kWh results of the above prediction formula compared to the actual annual purchases 

from 1998 to 2008 are shown in the graph below.


EB-2009-0263 

Exhibit 3 

Tab 2 

Schedule 1 



Actual versus Predicted Purcahses (Millions of kWhs) 

700 

600 

500 

400 

300 

200 

100 

0 

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 

Series1 

Series2 

Actual 

Predicted 

1


EB-2009-0263 

Exhibit 3 

Tab 2 

Schedule 1 



1 

2 

3 

The prediction formula has a statistical R 2 of 79% which generally indicates the formula has a 

relatively good fit to the actual data set. A summary of the statistical results are presented in the 

Table 4 below: 

Table 4 

Statistical Results 

Statistic 

Value 

R Square 78.8% 

Adjusted R Square 77.6% 

F Test 65.8 

T-stats by Coefficient 

Intercept 5.2 

Heating Degree Days 12.1 

Cooling Degree Days 7.3 

Ontario Real GDP Monthly % 7.9 

Number of Days in Month 3.5 

Spring Fall Flag (0.5) 

Population (5.5) 

Number of Peak Hours 5.4 

4 

5 

6 

7 

The following Table 5 outlines the data that supports the graphical chart on page 9. In addition to 

historical data, the weather normalized forecast of total system purchases for Festival Hydro is 

provided for 2009 and 2010. 

8 

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The table illustrates the predicted versus actual purchases since 1998. There are 4 years (2000, 

2001, 2006 and 2008) where the predicted values exceeded the actual values; 3 years (2002, 

2003, 2004) in which the predicted values were less than the actual values with the remaining 

years being approximately equal. This would indicate that the model does not appear to be 

biased to either under or over predict the purchases. 

14 

15


EB-2009-0263 

Exhibit 3 

Tab 2 

Schedule 1 



Table 5 

Festival Hydro’s Total System Purchases 

Year Actual Predicted % Difference 

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2 

3 

4 

5 

6 

7 

1998 567,117,349 565,333,999 0.32% 

1999 593,828,652 593,691,923 0.02% 

2000 611,283,741 617,457,354 -1.00% 

2001 616,059,685 625,665,510 -1.54% 

2002 639,349,517 637,542,922 0.28% 

2003 640,334,466 635,007,487 0.84% 

2004 649,308,540 633,453,565 2.50% 

2005 650,800,740 649,189,218 0.25% 

2006 635,441,692 642,245,829 -1.06% 

2007 634,322,920 632,774,446 0.24% 

2008 611,667,199 617,152,248 -0.89% 

2009 (B) 605,066,307 

2010 (T) 589,782,229 

The forecasted weather normalized amount for 2009 and 2010 is determined by using a forecast 

of the dependent variables in the prediction formula on a monthly basis. In order to incorporate 

weather normal conditions, the average monthly heating degree days and cooling degree days 

which have occurred from 1998 to 2008 is applied in the prediction formula. The details on the 

average monthly heating degree days and cooling degree days are shown in Appendix A. 

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The prediction formula is based on eleven years of historical monthly data. It has been found to 

be able to predict the impact on the forecast for recent events that have caused changes in energy 

sales. On the residential side, the model has taken into account the success of Conservation and 

Demand Side Management Programs, which commenced in 2005 as a result of Third Tranche 

funding and continued through with successful OPA conservation programs. Festival Hydro has 

implemented a number of CDM programs within its service area with very positive results as can 

been seen in the decline in usage per customer since 2005. It is assumed this trend in energy 

savings that have occurred from 2005 to 2008 will continue in 2009 and 2010.


EB-2009-0263 

Exhibit 3 

Tab 2 

Schedule 1 



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The model is predicting lower sales for both 2009 and 2010 for general service rate classes, 

which is reflective of the run-off of the Ontario manufacturing sector in Festival Hydro’s service 

territory in recent years and the difficulties faced in the tourist industry. 

However, Festival Hydro’s outlook is optimistic with two adjustments to be made to the forecast 

to reflect positive trends in our general service > 50 kW forecasted data. The model itself takes 

care of net increases in customers and loads, but there are two potentially larger accounts that 

Festival Hydro believed should be incorporate into the totals. In 2010 data, quantities have been 

increased to reflect the addition of two larger General Service > 50 kW operations coming to the 

City of Stratford. Recently it has been announced and preparations are underway for a major 

Ontario University to set up a satellite site in Stratford focusing on digital media studies. The 

second announcement with preparation underway is operations of a major financial institution. 

The financial institution is expected to eventually become a large use customer, sometime 

beyond the period covered by this 2010 Cost of Service Rate application. Both new industries to 

the City are expected to result in spin off operations, however, not until dates beyond 2010. 

On August 4, 2009, one of Festival Hydro’s Large Use customers filed for creditor protection 

under CCAA in Ontario. The 2010 load forecast has not been reduced because documentation 

provided to date on the restructuring of this company indicates that it is expected that operations 

in Ontario will continue as in the past within the new structure and therefore we have concluded, 

at this time, that our load forecast should not be negatively impacted going forward. Table 6 

shows the predicted purchases before and after the adjustments for the two new customers in the 

2010 test year.


EB-2009-0263 

Exhibit 3 

Tab 2 

Schedule 1 



Table 6 

Predicted Purchases Before and After Adjustments 

Year 

Predicted 

before 

Adjustment 

Adjustment 

for University 

Satellite 

Adjustment for 

Financial 

Institution 

Predicted After 

Adjustment 

2007 632,774,446 0 0 632,774,446 

2008 617,152,248 0 0 617,152,248 

2009 (B) 605,066,307 0 0 605,066,307 

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2010 (T) 589,782,229 793,969 1,190,954 591,767,152 

Billed KWh Load Forecast 

To determine the total weather normalized energy billed forecast, the total system weather 

normalized purchases forecast is adjusted by a historical loss factor. As outlined in Table 7 

below, historically the Festival Hydro loss factor, calculated on a simple basis of actual 

purchased versus actual billed, on average has been 2.58%. This is much lower than our 

requested 2010 loss factor of 3.07% in Exhibit 9 (for secondary metered < 5,000 kW) because 

the 3.07% factor takes into account that there is a reduced rate of .75% for our two large use 

customers and reduced rate of 2.04% for primary metered less than 5,000 kW customers.


EB-2009-0263 

Exhibit 3 

Tab 2 

Schedule 1 



Table 7 

Historical Loss Factor 

Year 

Actual 

Purchases 

Actual Billed 

Simple Loss 

Factor 

2000 611,283,741 596,581,663 2.46% 

2001 616,059,685 605,241,071 1.79% 

2002 639,349,517 624,930,122 2.31% 

2003 640,334,466 627,031,302 2.12% 

2004 649,308,540 632,340,069 2.68% 

2005 650,800,740 632,444,846 2.90% 

2006 635,441,692 617,899,375 2.84% 

2007 634,322,920 615,535,179 3.05% 

2008 611,667,199 593,387,454 3.08% 

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Average 2.58% 

Billed KWh Load Forecast and Customer/Connection Forecast by Rate Class 

Since the total weather normalized billed energy amount is known, this amount needs to be 

distributed by rate class for rate design purposes taking into consideration the 

customer/connection forecast and expected usage per customer by rate class. 

The next step in the forecasting process is to determine a customer/connection forecast. The 

customer/connection forecast is based on reviewing historical customer/connection data that is 

available as shown in Table 8 below. Customer counts used throughout the model are based on a 

year average basis, rather than year end balances.


EB-2009-0263 

Exhibit 3 

Tab 2 

Schedule 1 



Table 8 

Historical Customers/Connection Data by Rate Class 

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2 

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Year 

Residential 

Hensall 

General General 

Service < 50 Service > 50 

kW kW 

Street 

Lighting 

Sentinel 

Lights USL Total 

Residential 

Large Use 

2000 15,134 405 1,992 208 2 5,614 77 161 23,592 

2001 15,320 412 1,970 219 2 5,886 82 156 24,048 

2002 15,551 409 1,996 210 2 5,677 79 166 24,088 

2003 15,752 407 2,002 210 2 5,699 78 169 24,318 

2004 15,951 407 2,005 205 2 5,700 77 171 24,518 

2005 16,151 409 1,988 206 2 5,721 80 166 24,721 

2006 16,334 409 1,972 209 2 5,741 81 157 24,905 

2007 16,535 410 1,972 209 2 5,767 81 156 25,130 

2008 16,708 412 1,972 218 2 5,856 82 157 25,405 

From the historical customer/connection data, the growth rate in customer/connection can be 

evaluated and is provided in Table 9 below. The geometric mean growth rate in number of 

customers is also provided. The geometric mean approach provides the average growth rate on a 

compounding basis. 

Table 9 

Growth Rates in Customers/Connections 

Year 

Residential 

Residential 

Hensall 

General 

Service < 50 

kW 

General 

Service > 50 

kW 

Large Use 

Street 

Lighting 

Sentinel 


7 

2001 1.23% 1.84% -1.09% 5.67% 0.00% 4.84% 7.52% -3.03% 1.93% 

2002 1.51% -0.84% 1.31% -4.45% 0.00% -3.55% -4.57% 6.01% 0.17% 

2003 1.29% -0.49% 0.30% 0.24% 0.00% 0.38% -0.64% 1.81% 0.95% 

2004 1.27% 0.00% 0.12% -2.38% 0.00% 0.03% -1.28% 1.48% 0.82% 

2005 1.25% 0.49% -0.85% 0.24% 0.00% 0.36% 3.25% -2.92% 0.83% 

2006 1.13% 0.00% -0.78% 1.70% 0.00% 0.36% 1.89% -5.42% 0.74% 

2007 1.23% 0.12% 0.00% -0.24% 0.00% 0.45% -0.62% -0.96% 0.90% 

2008 1.04% 0.49% 0.00% 4.56% 0.00% 1.54% 1.24% 0.64% 1.09% 

Geo Mean 1.012% 1.002% 0.999% 1.006% 1.000% 1.005% 1.009% 0.998% 1.009% 

8 

9 

10 

11 

12 

The resulting geometric mean is applied to the 2008 customer/connection numbers to determine 

the forecast of customer/connections for 2009 and 2010. Table 9A outlines the forecast of 

customers by rate class for 2009 and 2010. The 2009 and 2010 results are reasonable and 

predictable, given the pattern of low customer growth in Festival Hydro’s territory.


EB-2009-0263 

Exhibit 3 

Tab 2 

Schedule 1 



Table 9A 

Forecasted Customers by Rate Class for 2009 & 2010 

1 

2 

3 

4 

5 

6 

Year 

Residential 

Hensall 

General 

Service < 50 

kW 

General 

Service > 50 

kW 

Street 

Lighting 

Sentinel 


Residential 

Large Use 

2009 16,910 412 1,970 219 2 5,886 82 156 25,638 

2010 17,115 413 1,968 221 2 5,916 83 156 25,874 

The next step in the process is to review the historical customer/connection usage and to reflect 

this usage per customer in the forecast. The following Table 10 provides the average annual 

usage per customer by rate class from 2001 to 2008 where data is available. 

Table 10 

Average Energy Usage per Customer by Rate Class 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

Year 

Residential 

Residential 

Hensall 


< 50 kW 



Energy Usage by Customer /Connection 

2000 8,690 9,529 36,354 1,487,134 37,748,474 641 2,194 5,866 

2001 8,687 10,061 35,457 1,529,016 36,897,011 642 2,384 5,867 

2002 8,783 10,520 34,764 1,609,555 36,150,640 644 2,443 7,938 

2003 8,612 9,951 35,488 1,593,412 38,330,014 634 1,902 7,399 

2004 8,575 10,298 36,013 1,648,788 38,195,677 659 1,869 5,227 

2005 8,879 10,404 35,865 1,626,535 37,244,910 641 2,149 5,508 

2006 Board 8,601 10,265 34,936 1,623,642 38,232,149 644 2,467 8,051 

2006 8,461 9,420 34,648 1,568,834 37,459,215 644 2,882 4,948 

2007 8,443 9,901 35,311 1,573,925 34,800,153 611 2,801 4,707 

2008 8,198 9,761 34,120 1,435,542 33,712,174 656 2,687 4,356 

Usage per customer/connection can only be determined from 2000 and onward (after 

amalgamation) since reliable historical billed energy by rate class is not readily available. As 

can been seen from the above table, usage per customer/connection essentially declines for most 

classes after 2005. 

The change in each class is due to the following: 

 

Residential and Hensall residential – Impact of successful CDM programs which 

commenced in 2005 and continue with the OPA programs.

1 

2 

3 

4 

5 

6 

7 

8 

 

 

 


EB-2009-0263 

Exhibit 3 

Tab 2 

Schedule 1 



General Service < 50 kW - Partial impact on CDM and 2008 lower due to slower tourist 

industry impacting restaurants, hotels and retail outlets. 

General Service > 50 kW and Large Use – Loss of a number of manufacturing plants 

over the past few years. Both large use customers manufacture for the North American 

auto industry. 

Street lighting, sentinel lights and unmetered scattered loads tend to have fairly constant 

usage per connection on an annual basis. 

9 

10 

11 

As stated previously, in Festival Hydro’s view, the overall decline is due to the success of CDM 

programs which commenced in 2005, a struggling tourist industry and overall shrinkage in 

Ontario’s manufacturing sector. 

12 

13 

14 

15 

From the historical usage per customer/connection data the growth rate in usage per 

customer/connection can be reviewed which is provided on the following Table 11. The 

geometric mean growth rate has also been shown. 

Table 11 

Growth Rate in Usage Per Customer/Connection 

Year Residential 

Residential 

Hensall 


< 50 kW 

Annual Growth Rate in Usage by Customer/Connection 



16 

17 

18 

19 

20 

2001 -0.03% 5.58% -2.47% 2.82% -2.26% 0.12% 8.64% 0.01% 

2002 1.10% 4.56% -1.96% 5.27% -2.02% 0.37% 2.48% 35.31% 

2003 -1.94% -5.41% 2.08% -1.00% 6.03% -1.57% -22.16% -6.79% 

2004 -0.43% 3.48% 1.48% 3.48% -0.35% 3.86% -1.69% -29.36% 

2005 3.55% 1.03% -0.41% -1.35% -2.49% -2.63% 14.96% 5.39% 

2006 -4.71% -9.46% -3.39% -3.55% 0.58% 0.42% 34.12% -10.18% 

2007 -0.22% 5.10% 1.91% 0.32% -7.10% -5.14% -2.83% -4.86% 

2008 -2.90% -1.42% -3.37% -8.79% -3.13% 7.41% -4.06% -7.46% 

Geo Mean -0.73% 0.30% -0.79% -0.44% -1.40% 0.29% 2.57% -3.65% 

For the forecast of usage per customer/connection the historical geometric mean was used for all 

rate classes. The declining results can be expected due to the factors previously noted: 

successful CDM programs, shrinking manufacturing and challenges in tourism. 

21


EB-2009-0263 

Exhibit 3 

Tab 2 

Schedule 1 



Table 12 

Forecast Annual kWh Usage per Customer/Connection 

1 

2 

3 

4 

5 

6 

Year 

Residential 

Residential 

Hensall 


< 50 kW 



Forecast Energy Usage by Customer /Connection 

2009 (B) 8,139 9,790 33,851 1,429,220 33,238,979 658 2,756 4,197 

2010 (T) 8,080 9,819 33,583 1,422,926 32,772,426 660 2,827 4,044 

With the preceding information the non-normalized weather billed energy forecast can be 

determined by applying the forecasted number of customer/connections from Table 7 by the 

forecast of annual usage per customer/connection from Table 9. The resulting non-normalized 

weather billed energy forecast is shown in Table 13 below. 

7 

Table 13 

Non-Normalized Weather Billed Energy Forecast 

Year 

Residential 

Residential 

Hensall 


< 50 kW 



Billed Energy: 

2009 (B) 137,625,755 4,037,946 66,693,594 313,367,608 66,477,958 3,873,055 226,715 655,210 592,957,841 

2010 (T) 138,283,955 4,059,490 66,107,601 313,787,614 65,544,852 3,904,130 234,690 629,732 592,552,064 

8 

9 

10 

11 

The non-normalized weather billed energy forecast has been determined but this needs to be 

adjusted in order to be aligned with the total weather normalized billed energy forecast. As 

previously determined, the total weather normalized billed energy forecast is 589,836,391 kWh 

for 2009 and 574,937,023 kWh for 2010, prior to adjustments. 

12 

13 

14 

15 

16 

17 

The difference between the non-normalized and normalized forecast before manual adjustments 

is 3,121,450 kWh in 2009 and 17,615,041 kWh in 2010. This difference is assigned to those rate 

classes that are weather sensitive. Based on the weather normalization work completed by Hydro 

One for Festival Hydro for the 2006 cost allocation study, which has been used to support this 

rate application, the weather sensitivity by rate classes is as follows. 

18


EB-2009-0263 

Exhibit 3 

Tab 2 

Schedule 1 



Table 14 

Weather Sensitivity by Rate Class 

Residential; 

Residential 

Hensall 


< 50 kW 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

100% 100% 100% 24% 0% 0% 0% 0% 

As a result, the difference between the non-normalized and normalized forecast has been 

assigned on a prorated basis to each rate class based on the above level of weather sensitivity. 

The following tables outline how the weather sensitive rate classes have been adjusted to align 

the non-normalized forecast with the normalized forecast. In addition, the impact of the manual 

adjustments for two new General Service > 50 kW customers of 1,935,000 kWh, is also 

included to show how the weather normalized billed energy forecast after adjustments have been 

determined. The manual adjustments are at the billed level which excludes losses. 

For the Purchase forecast model, eleven years of purchase data was used along with the heating 

and cooling degree days for that eleven year period. In addition, Festival Hydro has taken the 

same data and applied the results of a 20 year Heating and Cooling Degree trend line. The 

resulting adjustment using the 20 year trend line isn’t as great as the results from the 11 year 

trend line. For both the 11 and 20 year trend line, the 2010 test year quantities are down by 

larger amounts than 2009, implying a factor such as GDP is having a greater impact than 

weather. Festival Hydro has chosen the 11 year trend line because it better reflects the impact of 

recent climate change. Appendix B shows the results of the 11 year trend line compared to the 

20 year results.


EB-2009-0263 

Exhibit 3 

Tab 2 

Schedule 1 



Table 15 

Alignment of Non-Normal to Weather Normal Forecast 

(using 11 year HDD and CDD) 

1 

2 

Residential 

Hensall 


< 50 kW 




Non-normalized weather billed energy forecast 

2009 (B) 137,625,755 4,037,946 66,693,594 313,367,608 66,477,958 3,873,055 226,715 655,210 592,957,841 

2010 (T) 138,283,955 4,059,490 66,107,601 313,787,614 65,544,852 3,904,130 234,690 629,732 592,552,064 

Adjustment for weather 

2009 (B) (1,508,298) (44,254) (730,923) (837,976) 0 0 0 0 (3,121,450) 

2010 (T) (8,546,482) (250,892) (4,085,705) (4,731,962) 0 0 0 0 (17,615,041) 

Adjustment for 2 new G.S. > 50 kW accounts 

2009 (B) 0 0 0 0 0 0 0 0 0 

2010 (T) 0 0 0 1,935,000 0 0 0 0 1,935,000 

Weather normalized billed energy forecast using 11 year HDD & CDD 

2009 (B) 136,117,457 3,993,693 65,962,671 312,529,632 66,477,958 3,873,055 226,715 655,210 589,836,391 

2010 (T) 129,737,473 3,808,598 62,021,896 310,990,652 65,544,852 3,904,130 234,690 629,732 576,872,024 

Table 16 

Alignment of Non-Normal to Weather Normal Forecast 

(using 20 year HDD and CDD) 

Residential 

Hensall 


< 50 kW 




Non-normalized weather billed energy forecast 

2009 (B) 137,625,755 4,037,946 66,693,594 313,367,608 66,477,958 3,873,055 226,715 655,210 592,957,841 

2010 (T) 138,283,955 4,059,490 66,107,601 313,787,614 65,544,852 3,904,130 234,690 629,732 592,552,064 

Adjustment for weather 

2009 (B) 101,534 101,534 101,534 101,534 101,534 101,534 101,534 101,534 812,272 

2010 (T) (7,536,029) (250,892) (4,085,705) (4,731,962) 0 0 0 0 (16,604,587) 

Adjustment for 2 new G.S. > 50 kW accounts 

2009 (B) 0 0 0 0 0 0 0 0 0 

2010 (T) 0 0 0 1,935,000 0 0 0 0 1,935,000 

Weather normalized billed energy forecast at 20 year HDD and CDD 

2009 (B) 137,727,289 4,139,480 66,795,128 313,469,142 66,579,492 3,974,589 328,249 756,744 593,770,113 

2010 (T) 130,747,926 3,808,598 62,021,896 310,990,652 65,544,852 3,904,130 234,690 629,732 577,882,477 

3


EB-2009-0263 

Exhibit 3 

Tab 2 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

Billed KW Load Forecast 

There are four rate classes that charge volumetric distribution on a per kW basis. These include 

General Service > 50 kW, Large Use, Streetlights and Sentinel Lights. As a result, the energy 

forecast for these classes needs to be converted to a kW basis for rate setting purposes. The 

forecast of kW for these classes is based on a review of the historical ratio of kW to kWhs and 

applying the average ratio to the forecasted kWh to produce the required kW. 

The following table 16 outlines the annual demand units by applicable rate class for the years 

that data is available (i.e. 2000 to 2008). KW sales for fiscal years 2006 to 2008 exceeded kW 

forecasted in the 2006 OEB Approved EDR rate filing. At the end of 2008 kW sales started to 

curtail, which are reflected in the forecast for 2009 and 2010. 

12 

13 

The following is table 17 shows the historical ratio of kW/kWh as well as the average ratio from 

2000 to 2008. 

Table 17 

Historical Annual kW per Applicable Rate Class 

Year 


> 50 kW Large Use Street Lighting Sentinel Lights Total 

2000 698,216 144,515 10,344 510 853,585 

2001 851,513 144,852 10,600 533 1,007,498 

2002 855,320 140,337 10,477 536 1,006,671 

2003 828,707 147,827 10,515 450 987,499 

2004 825,415 148,561 10,524 456 984,956 

2005 816,173 144,146 10,550 475 971,344 

2006 Board 810,112 150,650 10,837 459 972,058 

2006 832,056 149,551 10,562 649 992,818 

2007 853,400 139,780 10,654 626 1,004,460 

2008 840,462 137,493 10,789 609 989,353 

14 

15 

16 

The average ratio was applied to the weather normalized billed energy forecast in Table 16 to 

provide the forecast of kW by rate class as shown below. The following outlines the forecast of 

kW for the applicable rate classes, adjusted for the two new customers.


EB-2009-0263 

Exhibit 3 

Tab 2 

Schedule 1 



Table 18 

Historical kW/KWh Ratio per Applicable Rate Class 

Year 


> 50 kW Large Use Street Lighting Sentinel Lights 

1 

2 

2000 0.226% 0.191% 0.287% 0.304% 

2001 0.267% 0.196% 0.293% 0.289% 

2002 0.254% 0.194% 0.286% 0.280% 

2003 0.248% 0.193% 0.291% 0.303% 

2004 0.244% 0.194% 0.280% 0.317% 

2005 0.244% 0.194% 0.288% 0.278% 

2006 0.254% 0.200% 0.286% 0.278% 

2007 0.260% 0.201% 0.302% 0.278% 

2008 0.269% 0.204% 0.281% 0.278% 

Avge 0.252% 0.196% 0.288% 0.289% 

Table 19 

kW Forecast by Applicable Rate Class 

Year 


> 50 kW Large Use Street Lighting Sentinel Lights Total 

2009 (B) 786,686 130,519 11,166 656 929,026 

2010 (T) 777,941 128,687 11,255 679 918,562 

Add Adjustments for 2 new customers: 

2009 (B) 0 0 0 0 0 

2010 (T) 4,871 0 0 0 4,871 

Total kW Forecast 

3 

2009 (B) 786,686 130,519 11,166 656 929,026 

2010 (T) 782,812 128,687 11,255 679 923,433


EB-2009-0263 

Exhibit 3 

Tab 2 

Schedule 1 



1 

Summary of Forecast Data 

2006 Board 

2009 Weather 2010 Weather 

Approved 2006 Actual 2007 Actual 2008 Actual Normal Normal 

Actual kWh Purchases 635,441,692 634,322,920 611,667,199 

Predicted kWh Purchases 642,245,829 632,774,446 617,152,248 605,066,307 591,767,152 

% Difference 1.1% -0.2% 0.9% 

Billed kWh 618,527,719 617,899,375 615,535,179 593,387,454 589,836,391 574,937,024 

By Class 

Residential 

Customers 16,055 16,334 16,535 16,708 16,910 17,115 

kWh 138,087,026 138,207,589 139,603,876 136,970,688 136,117,457 129,737,473 

General Service < 50 kW 

Customers 2,002 1,972 1,972 1,972 1,970 1,968 

kWh 69,942,364 68,326,693 69,632,805 67,284,782 65,962,671 62,021,896 

General Service > 50 to 4999 kW 

Customers 200 209 209 218 219 221 

kWh 324,728,477 327,886,393 328,163,463 312,948,164 312,529,632 310,990,652 

kW 810,112 832,056 853,400 840,462 786,686 782,812 

Large Use 

Customers 2 2 2 2 2 2 

kWh 76,464,298 74,918,429 69,600,305 67,424,347 66,477,958 65,544,852 

kW 150,650 149,551 139,780 137,493 130,519 128,687 

Streetlights 

Customers 5,731 5,741 5,767 5,856 5,886 5,916 

kWh 3,688,157 3,697,097 3,522,815 3,842,227 3,873,055 3,904,130 

kW 10,837 10,562 10,654 10,789 11,166 11,255 


Connections 67 81 81 82 82 83 

kWh 165,272 233,476 225,471 219,010 226,715 234,690 

kW 459 649 626 609 656 679 

Unmetered Loads 

Connections 157 157 156 157 156 156 

kWh 1,264,039 776,820 732,005 681,719 655,210 629,732 

HENSALL Residential 

Customers 408 409 410 412 412 413 

kWh 4,188,086 3,852,878 4,054,439 4,016,517 3,993,693 3,808,598 

Total 

Customer/Connections 24,622 24,905 25,130 25,405 25,638 25,874 

kWh 618,527,719 617,899,375 615,535,179 593,387,454 589,836,391 576,872,024 

kW 972,058 992,818 1,004,460 989,353 929,026 923,433


EB-2009-0263 

Exhibit 3 

Tab 2 

Schedule 1 



2000 Actual 2001 Actual 2002 Actual 2003 Actual 2004 Actual 2005 Actual 

Actual kWh Purchases 611,283,741 616,059,685 639,349,517 640,334,466 649,308,540 650,800,740 

Predicted kWh Purchases 617,457,354 625,665,510 637,542,922 635,007,487 633,453,565 649,189,218 

% Difference 1.0% 1.6% -0.3% -0.8% -2.4% -0.2% 

Billed kWh 596,581,663 605,241,071 624,930,122 627,031,302 632,340,069 632,444,846 

By Class 

Residential 

Customers 15,134 15,320 15,551 15,752 15,951 16,151 

kWh 131,516,901 133,084,694 136,573,470 135,649,596 136,776,916 143,411,804 

General Service < 50 kW 

Customers 1,992 1,994 1,996 2,002 2,005 1,988 

kWh 72,417,171 70,701,786 69,388,032 71,046,669 72,187,366 71,281,495 

General Service > 50 to 4999 kW 

Customers 208 209 210 210 205 206 

kWh 308,580,266 318,799,805 337,201,829 334,616,436 338,001,625 334,252,910 

kW 698,216 851,513 855,320 828,707 825,415 816,173 

Large Use 

Customers 2 2 2 2 2 2 

kWh 75,496,947 73,794,022 72,301,280 76,660,027 76,391,354 74,489,819 

kW 144,515 144,852 140,337 147,827 148,561 144,146 

Streetlights 

Customers 5,614 5,640 5,677 5,699 5,700 5,721 

kWh 3,598,812 3,619,840 3,657,240 3,613,293 3,753,742 3,668,342 

kW 10,344 10,600 10,477 10,515 10,524 10,550 


Connections 77 78 79 78 77 80 

kWh 167,853 184,736 191,754 148,320 143,950 170,856 

kW 510 533 536 450 456 475 

Unmetered Loads 

Connections 161 163 166 169 171 166 

kWh 944,445 956,251 1,313,754 1,246,741 893,792 914,396 

HENSALL Residential 

Customers 405 408 409 407 407 409 

kWh 3,859,268 4,099,937 4,302,763 4,050,220 4,191,324 4,255,224 

Total 

Customer/Connections 23,592 23,812 24,088 24,318 24,518 24,721 

kWh 596,581,663 605,241,071 624,930,122 627,031,302 632,340,069 632,444,846 

kW 853,585 1,007,498 1,006,671 987,499 984,956 971,344


EB-2009-0263 

Exhibit 3 

Tab 2 

Schedule 1 

Appendix A 


APPENDIX A 

MONTHLY DATA USED FOR 

REGRESSION ANALYSIS


EB-2009-0263 

Exhibit 3 

Tab 2 

Schedule 1 

Appendix A 


Appendix A 

Purchased 

Heating 

Degree Days 

Cooling Degree 

Days 

Ontario Real 

GDP Monthly % 

Number of 

Days in 

Month 

Spring Fall 

Flag Population 

Number of 

Peak Hours 

Predicted 

Purchases 

Jan-98 51,018,028 629.3 0 100.40 31 0 41,047 336 49,566,802 

Feb-98 46,268,713 522.7 0 100.80 28 0 41,067 320 45,851,318 

Mar-98 50,209,423 517.6 1 101.20 31 1 41,087 352 49,082,973 

Apr-98 44,154,709 311 0 101.60 30 1 41,107 336 45,449,240 

May-98 44,633,793 67.1 30.4 102.00 31 1 41,127 320 44,285,952 

Jun-98 46,349,722 65.8 74.4 102.40 30 0 41,147 352 47,813,512 

Jul-98 45,612,894 7.4 77 102.80 31 0 41,167 352 47,997,975 

Aug-98 48,364,165 7.1 88.1 103.20 31 0 41,187 320 47,202,100 

Sep-98 46,175,407 49.3 40 103.60 30 1 41,207 336 45,131,724 

Oct-98 46,878,180 234.6 0 104.00 31 1 41,227 336 45,783,125 

Nov-98 48,330,562 416.9 0 104.40 30 1 41,247 336 47,320,802 

Dec-98 49,121,753 560.2 0 104.80 31 0 41,267 336 49,848,476 

Jan-99 53,791,132 767.7 0 105.44 31 0 41,287 320 51,652,236 

Feb-99 47,995,956 563.7 0 106.10 28 0 41,308 320 47,727,536 

Mar-99 51,804,580 601.3 0 106.76 31 1 41,329 368 52,278,071 

Apr-99 45,475,668 315.6 0 107.42 30 1 41,350 336 47,174,059 

May-99 45,790,093 113.3 16 108.08 31 1 41,371 320 45,834,578 

Jun-99 50,412,165 39.6 87.6 108.74 30 0 41,392 352 50,161,257 

Jul-99 50,105,483 3 135.7 109.40 31 0 41,413 336 52,446,594 

Aug-99 49,455,038 25.9 38.5 110.06 31 0 41,434 336 47,695,303 

Sep-99 47,919,668 75.5 27.8 110.72 30 1 41,455 336 47,092,268 

Oct-99 49,056,899 296.8 0 111.38 31 1 41,476 320 48,176,414 

Nov-99 50,258,087 403.4 0 112.04 30 1 41,497 352 50,486,150 

Dec-99 51,763,883 596.3 0 112.70 31 0 41,518 336 52,967,456 

Jan-00 55,153,263 737.5 0 113.27 31 0 41,539 320 53,980,536 

Feb-00 51,611,044 596.1 0 113.80 29 0 41,560 336 52,067,541 

Mar-00 52,221,022 434.5 0 114.33 31 1 41,581 368 52,928,530 

Apr-00 47,091,667 353.2 0 114.86 30 1 41,602 304 48,558,885 

May-00 49,234,362 134 17.8 115.39 31 1 41,623 352 50,050,788 

Jun-00 50,471,123 39.4 48.1 115.92 30 0 41,644 352 50,361,927 

Jul-00 48,074,327 23.1 50.7 116.45 31 0 41,665 320 49,596,891 

Aug-00 52,404,956 29.7 52.3 116.98 31 0 41,686 352 51,403,248 

Sep-00 48,909,902 114.7 38.4 117.51 30 1 41,707 320 49,463,940 

Oct-00 49,750,781 223.6 1 118.04 31 1 41,728 336 50,224,540 

Nov-00 52,441,619 458.6 0 118.57 30 1 41,749 352 53,101,774 

Dec-00 53,919,676 801.2 0 119.10 31 0 41,770 304 55,718,756 

Jan-01 55,871,300 701.2 0 119.23 31 0 41,799 352 56,708,422 

Feb-01 50,757,672 622.3 0 119.40 28 0 41,819 320 52,459,738 

Mar-01 54,139,855 611.9 0 119.57 31 1 41,839 352 55,457,903 

Apr-01 47,938,861 306.3 0 119.74 30 1 41,859 320 49,870,679 

May-01 49,297,354 114 6.8 119.91 31 1 41,879 352 50,155,622 

Jun-01 51,385,300 44.8 59.5 120.08 30 0 41,899 336 51,042,141 

Jul-01 49,946,058 23.3 84.5 120.25 31 0 41,919 336 52,740,234 

Aug-01 55,601,127 2 103.5 120.42 31 0 41,939 352 54,226,231 

Sep-01 48,919,171 105.3 18.7 120.59 30 1 41,959 304 47,756,008 

Oct-01 51,171,631 252.8 0.5 120.76 31 1 41,979 352 51,267,346 

Nov-01 50,515,679 335.6 0 120.93 30 1 41,999 352 51,544,831 

Dec-01 50,515,677 541.5 0 121.10 31 0 42,019 304 52,436,355 

Jan-02 54,557,427 616.9 0 121.43 31 0 42,039 352 55,561,029 

Feb-02 50,362,485 566.8 0 121.80 28 0 42,059 320 51,741,697 

Mar-02 53,082,278 551.8 0 122.17 31 1 42,079 320 53,305,081 

Apr-02 50,642,621 333.8 8.6 122.54 30 1 42,099 352 52,267,392 

May-02 50,608,524 240.1 7.3 122.91 31 1 42,119 352 51,827,541 

Jun-02 51,866,787 39.9 70.7 123.28 30 0 42,139 320 51,145,707 

Jul-02 55,319,351 4.8 128.2 123.65 31 0 42,159 352 56,041,092 

Aug-02 56,699,817 7.6 89.4 124.02 31 0 42,179 336 53,337,242 

Sep-02 52,723,343 38.2 56.8 124.39 30 1 42,199 320 50,424,758 

Oct-02 54,395,870 314.1 9.6 124.76 31 1 42,219 352 53,191,609 

Nov-02 54,891,660 475.3 0 125.13 30 1 42,239 336 53,232,048 

Dec-02 54,199,354 661.5 0 125.50 31 0 42,259 320 55,467,726


EB-2009-0263 

Exhibit 3 

Tab 2 

Schedule 1 

Appendix A 


Jan-03 60,682,148 821.9 0 125.65 31 0 42,279 352 58,732,252 

Feb-03 55,102,398 719.4 0 125.80 28 0 42,299 320 54,206,669 

Mar-03 56,411,683 585.7 0 125.95 31 1 42,319 336 55,075,949 

Apr-03 51,768,969 378.9 2.3 126.10 30 1 42,339 336 52,213,745 

May-03 48,041,345 189.3 0 126.25 31 1 42,359 336 50,532,624 

Jun-03 47,973,756 51.5 34.9 126.40 30 0 42,379 336 50,401,427 

Jul-03 52,352,810 7.1 73.5 126.55 31 0 42,399 352 53,289,370 

Aug-03 53,057,452 8.4 88.2 126.70 31 0 42,419 320 52,575,305 

Sep-03 51,560,940 72.9 14.2 126.85 30 1 42,439 336 49,231,296 

Oct-03 54,047,370 294.8 0.3 127.00 31 1 42,459 352 52,298,009 

Nov-03 55,039,342 400.7 0 127.15 30 1 42,479 320 51,330,737 

Dec-03 54,296,253 599.1 0 127.30 31 0 42,499 336 55,120,103 

Jan-04 60,191,796 843.7 0 127.53 31 0 42,519 336 57,890,059 

Feb-04 55,093,544 654.1 0 127.80 29 0 42,539 320 53,798,156 

Mar-04 57,723,435 514.1 0 128.07 31 1 42,559 368 55,517,290 

Apr-04 51,791,725 342.8 1 128.34 30 1 42,578 336 51,566,998 

May-04 52,028,830 161.8 13.4 128.61 31 1 42,597 320 50,082,176 

Jun-04 52,155,245 61.4 29.6 128.88 30 0 42,616 352 50,931,018 

Jul-04 51,113,907 10.2 65.7 129.15 31 0 42,635 336 52,213,131 

Aug-04 54,603,230 33 41.9 129.42 31 0 42,654 336 51,222,890 

Sep-04 53,000,453 49.7 36 129.69 30 1 42,673 336 50,315,018 

Oct-04 52,092,514 238 0 129.96 31 1 42,692 320 50,392,880 

Nov-04 53,916,856 409.5 0 130.23 30 1 42,711 352 53,243,527 

Dec-04 55,597,005 668.6 0 130.50 31 0 42,730 336 56,280,423 

Jan-05 59,519,040 782.7 0 130.81 31 0 42,749 320 56,863,277 

Feb-05 53,401,240 635 0 131.10 28 0 42,768 320 53,392,795 

Mar-05 56,026,000 644.3 0 131.39 31 1 42,787 352 56,681,485 

Apr-05 50,073,520 316.2 0 131.68 30 1 42,806 336 51,677,987 

May-05 50,162,960 208.5 0.3 131.97 31 1 42,825 336 51,140,213 

Jun-05 56,597,760 11.2 126.8 132.26 30 0 42,844 352 56,086,443 

Jul-05 53,676,610 2.2 140.7 132.55 31 0 42,863 320 55,898,768 

Aug-05 57,518,680 5.9 94.1 132.84 31 0 42,882 352 54,962,013 

Sep-05 52,250,000 44 30.4 133.13 30 1 42,901 336 50,466,275 

Oct-05 52,711,210 243.4 13.7 133.42 31 1 42,920 320 51,719,592 

Nov-05 53,362,010 418.9 0 133.71 30 1 42,939 352 53,887,794 

Dec-05 55,501,710 699.1 0 134.00 31 0 42,958 320 56,412,574 

Jan-06 56,528,710 576.3 0 134.22 31 0 42,977 336 55,795,132 

Feb-06 52,548,160 628.2 0 134.50 28 0 42,997 320 53,806,888 

Mar-06 56,081,470 571.1 0 134.78 31 1 43,017 368 57,095,800 

Apr-06 48,548,560 307.9 0 135.06 30 1 43,038 304 50,542,009 

May-06 51,563,020 163.2 23.9 135.34 31 1 43,059 352 53,073,562 

Jun-06 52,813,920 42.2 42.8 135.62 30 0 43,080 352 52,342,287 

Jul-06 54,008,040 7 127 135.90 31 0 43,101 320 55,629,486 

Aug-06 55,895,490 9.8 57.3 136.18 31 0 43,122 352 53,421,775 

Sep-06 49,552,320 108.2 6.1 136.46 30 1 43,143 320 49,494,213 

Oct-06 52,532,530 312.6 0.3 136.74 31 1 43,163 336 52,910,877 

Nov-06 53,385,930 394.5 0 137.02 30 1 43,183 352 53,972,462 

Dec-06 51,983,542 533.1 0 137.30 31 0 43,203 304 54,161,339 

Jan-07 57,509,800 433.3 0 137.55 31 0 43,223 352 55,266,049 

Feb-07 54,145,600 504.7 0 137.80 28 0 43,243 320 52,756,166 

Mar-07 55,841,344 402.6 0 138.05 31 1 43,263 352 54,760,544 

Apr-07 49,890,898 277.2 0 138.30 30 1 43,284 320 51,244,154 

May-07 50,950,599 85.8 20.9 138.55 31 1 43,305 352 52,334,907 

Jun-07 52,949,918 25.2 62.8 138.80 30 0 43,326 336 52,772,805 

Jul-07 50,695,162 8.9 43.9 139.05 31 0 43,347 336 52,200,769 

Aug-07 55,177,149 9.1 66.5 139.30 31 0 43,368 352 54,159,544 

Sep-07 49,919,310 27.6 23.9 139.55 30 1 43,388 304 49,046,784 

Oct-07 52,289,030 107.7 12.2 139.80 31 1 43,409 352 52,183,294 

Nov-07 52,590,120 287.2 0 140.05 30 1 43,429 352 52,964,060 

Dec-07 52,363,990 421.2 0 140.30 31 0 43,449 304 53,085,372


EB-2009-0263 

Exhibit 3 

Tab 2 

Schedule 1 

Appendix A 


Jan-08 56,931,880 430 0 140.24 31 0 43,469 352 55,260,143 

Feb-08 53,808,360 477 0 140.20 29 0 43,489 320 52,935,041 

Mar-08 54,411,970 421 0 140.16 31 1 43,509 304 52,460,939 

Apr-08 49,720,310 160 0 140.12 30 1 43,530 352 50,997,211 

May-08 48,905,780 140 0 140.08 31 1 43,551 336 50,502,359 

Jun-08 50,409,100 25 34 140.04 30 0 43,572 336 50,478,957 

Jul-08 51,274,000 1 53 140.00 31 0 43,593 352 52,457,227 

Aug-08 49,872,730 14 18 139.96 31 0 43,614 320 49,076,232 

Sep-08 48,308,210 59 11 139.92 30 1 43,635 336 49,015,601 

Oct-08 49,255,560 227 0 139.88 31 1 43,655 352 51,548,735 

Nov-08 49,017,380 282 0 139.84 30 1 43,675 304 49,191,035 

Dec-08 49,751,919 448 0 139.80 31 0 43,695 336 53,228,769 

Jan-09 667 0 139.49 31 0 43,715 336 55,429,885 

Feb-09 590 0 139.20 28 0 43,735 304 50,960,860 

Mar-09 532 0 138.91 31 1 43,755 352 53,932,714 

Apr-09 309 1 138.62 30 1 43,776 320 49,097,723 

May-09 147 12 138.33 31 1 43,797 320 48,222,771 

Jun-09 41 61 138.04 30 0 43,818 352 50,437,436 

Jul-09 9 89 137.75 31 0 43,839 352 51,939,209 

Aug-09 14 67 137.46 31 0 43,860 320 49,052,253 

Sep-09 68 28 137.17 30 1 43,881 336 47,197,704 

Oct-09 250 3 136.88 31 1 43,901 336 48,303,094 

Nov-09 389 0 136.59 30 1 43,921 320 48,075,346 

Dec-09 594 0 136.30 31 0 43,941 352 52,417,312 

Jan-10 667 0 136.54 31 0 43,961 320 51,775,262 

Feb-10 590 0 136.80 28 0 43,981 304 48,336,335 

Mar-10 532 0 137.06 31 1 44,001 368 52,338,287 

Apr-10 309 1 137.32 30 1 44,022 320 47,046,033 

May-10 147 12 137.58 31 1 44,043 320 46,457,499 

Jun-10 41 61 137.84 30 0 44,064 352 48,958,580 

Jul-10 9 89 138.10 31 0 44,085 336 50,003,090 

Aug-10 14 67 138.36 31 0 44,106 336 48,889,913 

Sep-10 68 28 138.62 30 1 44,127 336 46,578,101 

Oct-10 250 3 138.88 31 1 44,147 320 47,226,227 

Nov-10 389 0 139.14 30 1 44,167 336 48,772,259 

Dec-10 594 0 139.40 31 0 44,187 368 53,400,642


EB-2009-0263 

Exhibit 3 

Tab 2 

Schedule 1 

Appendix B 


APPENDIX B 

MONTHLY HDD & CDD BASED ON 11 AND 20 YEAR AVERAGES


EB-2009-0263 

Exhibit 3 

Tab 2 

Schedule 1 

Appendix B 



1 

2 

11 Year Avge 20 Year Avge Difference 

Month Heating Days Cooling Days Heating Days Cooling Days Heating Days Cooling Days 

Jan-09 706 0 667 0 39 0 

Feb-09 640 0 590 0 50 0 

Mar-09 563 0 532 0 31 (0) 

Apr-09 351 1 309 1 42 0 

May-09 173 11 147 12 26 (1) 

Jun-09 43 55 41 61 3 (6) 

Jul-09 13 81 9 89 5 (8) 

Aug-09 19 84 14 67 5 17 

Sep-09 89 22 68 28 21 (6) 

Oct-09 261 3 250 3 11 (1) 

Nov-09 442 0 389 0 52 0 

Dec-09 634 0 594 0 40 0 

Jan-10 695 0 667 0 28 0 

Feb-10 629 0 590 0 39 0 

Mar-10 558 0 532 0 26 (0) 

Apr-10 338 1 309 1 29 0 

May-10 171 11 147 12 24 (1) 

Jun-10 43 53 41 61 2 (8) 

Jul-10 13 78 9 89 4 (11) 

Aug-10 19 80 14 67 5 13 

Sep-10 85 22 68 28 18 (6) 

Oct-10 261 3 250 3 11 (1) 

Nov-10 429 0 389 0 40 0 

Dec-10 620 0 594 0 27 0


EB-2009-0263 

Exhibit 3 

Tab 3 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

SUMMARY OF OTHER DISTRIBUTION REVENUE: 

Preamble: 

The Materiality threshold used to analyze Other Revenue is the default threshold of $50,000, 

since the distribution revenue requirement is less than $10 million, as directed in the OEB’s 

Chapter 2 of the Filing Requirements for Transmission and Distribution Applications May 27, 

2009. 

Festival Hydro is not proposing any new specific service charges nor or they requesting any 

changes to the existing Board approved specific service charges. 

Appendix 2-D Other Operating Revenue details below for each account the actual balances 

for fiscal 2006 to 2009, and projected balances for the bridge year 2009 and test year 2010. 

11 

12 

13 

Following Appendix 2-D is a series of tables which breaks down the details for each account. 

Festival Hydro has provided explanations below each breakdown schedule for the variances 

which exceed the materiality threshold


EB-2009-0263 

Exhibit 3 

Tab 3 

Schedule 2 



1 

2 

3 

VARIANCE ANALYSIS ON OTHER DISTRIBUTION REVENUE 

Uniform 

System of 

Account # 

4235 

4225 

4082 

4084 

4210 

4220 

Description 

OEB Appendix 2-D 

Other Operating Revenue 

Actual 

2006 

Actual 

2007 

Actual 

2008 

Bridge 

Year 

2009 

Test Year 

2010 

Specific Service 

Charges 152,517 215, 605 200,926 202,991 207,660 

Late Payment 

Charges 103,535 112,817 125,527 125,527 128,414 

Retail Services 

Revenues 27,783 26,104 26,575 26,772 27,160 

Service 

Transaction STR 

revenue 

Rent from Electric 

Property 

Other Electric 

Revenue 

2,185 2 ,295 966 987 1,009 

134,617 188,968 152,529 148,881 152,305 

6,726 4,856 5, 898 5, 880 6, 015 

4355 Gain on Disposals 79,243 52,200 89,613 18,250 13,043 

4375 

4380 

4390 

4405 

Revenue from 

Non-Utility 

Operations 

Expenses of Non- 

Utility Operations 

Miscellaneous 

Non-Operating 

Income 

Interest and 

Dividend Income 

718,237 781,562 695,798 690,042 699,213 

(612,182) (642,754) (609,439) (617,281) (631,478) 

52,304 74,588 42,485 31,864 32,109 

105,069 119,330 59,964 25, 200 24,000 

Specific Service Charges 152,517 215,605 200,926 202,991 207,660 

Late Payment Charges 103,535 112,817 125,527 125,527 128,414 

Other Distribution Revenues 

(4082,4084,4210,4220) 

171,311 222,223 185,968 182,520 186,489


EB-2009-0263 

Exhibit 3 

Tab 3 

Schedule 2 



Other Income and Expenses 

(4355,4375,4380,4390,4405) 

342,670 384,926 278,421 148,075 136,687 

1 

2 

3 

4 

5 

Total 770,033 935,571 790,842 659,113 659,450 

Specific Service Charges: Account 4235 

Late Payment Charges: Account 4225 

Other Distribution Revenues: Accounts 4082, 4084, 4090, 4205, 4210, 4215, 4220, 4240, 4245 

Other Income and Expenses: Accounts 4305, 4310, 4315, 4320, 4325, 4330, 4335, 4340, 4345, 4350, 4355, 4360, 4365, 4370, 4375, 4380, 

4385, 4390, 4395, 4398, 4405, 4415 

6 

7 

8 

9 

Specific Service charges increased by $63,088 in 2007 as a result of new OEB approved specific 

service charges in place commencing May 1, 2006. Festival Hydro adopted the standard OEB 

service charge rates. 

10 

For late payment on accounts, Festival Hydro charges the OEB approved rate of 1.5% per month. 

11


EB-2009-0263 

Exhibit 3 

Tab 3 

Schedule 2 



1 

Breakdown of each of the Other Distribution Revenue Account: 

4082– Retail Services 

Revenue 

Actual 

2006 

Actual 

2007 

Actual 

2008 

Bridge 

2009 

Test 

Year 2010 

Distributor Consumer 

Bill Ready 

11,595 16,066 14,193 14,319 14,648 

Variance Account Entry -12,469 -19,977 -14,508 -14,955 -15,525 

Service Agreement Fixed 

Charges 

Service Agreement 

Variable Charges 

2,618 3,191 3,228 3,302 3,377 

26,039 26,824 23,662 24,106 24,660 

Total 27,783 26,104 26,575 26,772 27,160 

4084 – Service 

Transaction STR 

Revenue 

Processing Retailer 

STR Revenue 

Request Retailer STR 

Revenue 

Actual 

2006 

Actual 

2007 

Actual 

2008 

Bridge 

2009 

1,373 1,134 573 586 599 

812 1,161 393 401 410 

Test 

Year 2010 

Total 2,185 2,295 966 987 1,009 

2 

3 

4 

Both the Retail Service Revenue and Service Transaction revenues are dependent on the number 

of customers signed with retailers. These fees charged are set by the OEB and have not changed 

since Festival Hydro’s last cost of service rate application in 2006. 

5


EB-2009-0263 

Exhibit 3 

Tab 3 

Schedule 2 



1 

4210 – Rent from 

Electric Property 

Actual 

2006 

Actual 

2007 

Actual 

2008 

Bridge 

2009 

Test 

Year 2010 

2 

Joint Pole Usage 72,667 120,718 80,429 82,278 83,923 

Hydro One Telecom 

Room Rental 

Service Centre space 

rental to City of Stratford 

22 350 24 600 24 600 24,950 25,450 

30,000 30,000 30,000 30,420 30,845 

Office space rentals 9,600 13,650 17,500 11,233 12,087 

Total 134,617 188,968 152,529 148,881 152,305 

3 

4 

5 

6 

7 

8 

9 

Rent from electric property increased by $54,351 in 2007 primarily due to joint pole charges. 

After new rates were established in 2006, there was a one time adjustment in Festival Hydro’s 

favour in 2007. The 2006 rates continue to be in force. Other rents are increased annually based 

on the Rent Review rates. 

4220 – Other Electric 

Revenue 

Actual 

2006 

Actual 

2007 

Actual 

2008 

Bridge 

2009 

Test 

Year 2010 

Purchase Discounts 6,546 4,229 5,640 5,700 5,815 

Profit on Sale of Small 

Equipment 

180 627 258 180 200 

Total 6,726 4,856 5,898 5,880 6,015 

10 

11


EB-2009-0263 

Exhibit 3 

Tab 3 

Schedule 2 



1 

2 

4355 – Gain on 

Disposals 

Gain on Sale of Used 

Vehicles 

Actual 

2006 

Actual 

2007 

Actual 

2008 

Bridge 

2009 

Test 

Year 2010 

10 800 50 400 13 575 17,750 26,086 

Gain on Sale of Property 68 443 0 76 038 500 0 

Gain on Sale of Used 

Propane Tank 

0 1 800 0 0 0 

3 

4 

5 

6 

7 

8 

Total 79 243 52 200 89 613 18,250 

26,086 

50% Rule – 

$13,043 

In 2006, a spare lot beside a municipal substation was sold for a net gain of $68,443. In 2008, a 

decommissioned substation lot was also sold with a net gain of $76,038. In 2007, a used double 

bucket truck was sold. 

4375 – Revenue from 

Non-Utility Operations 

Administration Fees & 

inventory stocking for 

FHSI 

Administration Fees for 

City of Stratford Water 

Billing & Collections 

Street lighting capital and 

maintenance revenues 

Actual 

2006 

Actual 

2007 

Actual 

2008 

Bridge 

2009 

Test 

Year 2010 

45,356 55,197 72,987 32,700 21,200 

411,250 394,215 397,814 410,126 420,485 

261,631 332,150 224,997 247,216 257,528 

Total 718,237 781,562 695,798 690,042 699,213 

9 

10 

11 

12 

13 

Festival Hydro provides all the administrative and management support to its sister company, 

Festival Hydro Services Inc., as further explained in Exhibit 4, Tab 2, Schedule 4. With regard 

to City of Stratford water and sewage administration fees, in 2006 there was an $18,950 

adjustment related to prior years. Removing that adjustment, normal income for the year was


EB-2009-0263 

Exhibit 3 

Tab 3 

Schedule 2 



1 

2 

3 

4 

$393,055. In October 2007, FHSI sold its water heater business with the final administration 

being transferred to the buyer in March 2009. This has caused a large decrease in management 

and administrative fees charged to FHSI in 2009 and 2010. 

4380 – Expenses of 

Non-Utility Operations 

Actual 

2006 

Actual 

2007 

Actual 

2008 

Bridge 

2009 

Test 

Year 2010 

Billing & Collection Costs 

for City Water & Sewage (322,788) (317,816) (340,955) (347,446) (357,869) 


maintenance expenses- 

City of Stratford 


maintenance expenses- 

Other towns in Service Area 

Office space rental 

expense (2006 included in 

4380;belongs to 4210) 

(257,898) (256,099) (213,146) (214,218) (217,214) 

(19,630) (68,839) (55,338) (55,617) (56,395) 

(11,866) 

5 

6 

7 

8 

9 

10 

11 

12 

13 

(612,182) (642,754) (609,439) (617,281) (631,478) 

Total 

Festival Hydro does the meter reading, billing and collection work for the City of Stratford’s 

water and sewage, as further described under Exhibit 4, Tab 2, Schedule 4. Festival Hydro also 

does street lighting maintenance and capital work for the City of Stratford, also described under 

Exhibit 4, Tab 2, Schedule 4. 

Festival Hydro also does street lighting maintenance for the Town of St. Marys and the 

Municipality of Bluewater (Dashwood, Hensall and Zurich).


EB-2009-0263 

Exhibit 3 

Tab 3 

Schedule 2 



1 

4390 – Miscellaneous 

Non-Operating 

Income 

Sale of Scrap Copper, 

Aluminum, Transformers 

Actual 

2006 

Actual 

2007 

Actual 

2008 

Bridge 

2009 

Test 

Year 2010 

51,040 67,134 42,020 31,338 31,623 

Joint Venture Income 0 6 695 0 0 0 

Sale of Scrap Poles 1,264 759 465 476 486 

Total 52,304 74,588 42,485 31,864 32,109 

2 

3 

4 

The sale of scrap is now approximately half the value it was a few years ago as the price of scrap 

metals has dropped substantially. Scrap copper sold at $2.17 per pound in May 2007 was now 

$1.62 in May 2009. 

4405 – Interest and 

Dividend Income 

Actual 

2006 

Actual 

2007 

Actual 

2008 

Bridge 

2009 

Test 

Year 2010 

Short-term 

Investment Interest 

22, 992 0 0 0 0 

Bank Deposit Interest 125,575 210,624 132, 776 19,754 18,300 

Misc. Interest Revenue 8,045 5,989 5, 324 5,446 5,700 

Net Interest on Regulatory 

Assets/ Liabilities 

(51,543) (97,313) (78,136) 0 0 

Total 105,069 119, 300 59, 964 25,200 24,000 

5


EB-2009-0263 

Exhibit 3 

Tab 3 

Schedule 2 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

In 2006, Festival Hydro held a T Bill which was used as prudential support for the IESO. This 

was allowed to return to cash near the end of 2006 (because interest earned at Prime -1.85% was 

as high as T Bill interest and provided cash to be available for immediate use). 

Bank Interest income for 2008 shows a substantial decline. The interest rate earned on our bank 

deposit went form a high of 4.077% in January 2008 to a low of 1.795% in December 2008. 

According to the Bank of Canada (end July 09) report, the Bank of Canada does not see moving 

the prime rate from the current rate of .25%until at least mid 2010. Festival Hydro’s banking 

institution has paid a rate of bank prime minus 1.85 % during the period 2006 to 2008 and 

Festival Hydro expects this will continue for the forthcoming years. 

Interest for all regulatory accounts was charged to this account from 2006 to 2008. Because of 

large regulatory liabilities for wholesale market, retail network and retail connection rates, the 

charge against income were very high. The interest for regulatory accounts is calculated on the 

principal only balances, using the prescribed quarterly rates as set out by the OEB. For 2009 and 

2010, the net interest charge on variance accounts has been placed in the interest expense 

account.


EB-2009-0263 

Exhibit 3 

Tab 4 

Schedule 1 



1 

2 

DESCRIPTION OF REVENUE SHARING: 

Festival Hydro does not have a revenue sharing practice in place.


EB-2009-0263 

Exhibit 4 

Index 




4 – Operating Costs 

1 Overview 

1 

Overview of Operating Costs 

A 2008 Federal and Ontario Tax Return 

2 Manager’s Summary of OM&A Costs 

1 Departmental and Corporate OM&A 

Activities 

2 OM&A Detailed Costs Table 

3 Variance Analysis on OM&A Costs 

4 Charges to Affiliates for Services 

Provided 

B Affiliate Service Agreements 

5 Purchase of Products and Services from 

non-affiliates 

6 Employee Compensation, Incentive Plan 

Expenses, Pension Expense and Post 

Retirement Benefits 

7 Depreciation, Amortization and Depletion 

C Depreciation Calculations by Account 

3 Income Tax, Large Corporation Tax 

1 Tax Calculations 

2 Capital Cost Allowance (CCA)


EB-2009-0263 

Exhibit 4 

Tab 1 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

OVERVIEW OF OPERATING COSTS: 

Operating Costs: 

The operating costs presented in this Exhibit represent the annual expenditures required to 

sustain Festival Hydro’s distribution operations. Festival Hydro follows the OEB’s Accounting 

Procedures Handbook (the “APH”) in distinguishing work performed between operations and 

maintenance. A summary of Festival Hydro’s operating costs for the 2006 Board Approved, 

2006 Actual, 2007 Actual, 2008 Actual, 2009 Bridge Year and the 2010 Test Year including the 

determination of the variance amount for analysis, in accordance with the Filing Requirements, 

is provided in Table 1 below. 

10 

11 

12 

Description 

2006 Board 

Approved 

2006 

Actual 

Table 1 

Summary of Operating Costs 

Variance 

from Previous 

Yr. 

2007 

Actual 

Variance from 

Previous Yr. 

2008 

Actual 

Variance from 

Previous Yr. 

2009 

Bridge 

Variance from 

Previous Yr. 

2010 Test 

Variance from 

Previous Yr. 

OM&A expenses 

Operation 404,166 528,712 124,546 522,506 (6,206) 623,913 101,407 640,791 16,878 658,190 17,399 

Maintenance 796,377 674,908 (121,469) 835,083 160,175 745,455 (89,628) 766,335 20,880 787,807 21,472 

Billing and Collections 909,919 962,636 52,717 921,773 (40,863) 928,131 6,358 1,022,792 94,661 1,020,272 (2,520) 

Community Relations 24,784 113,313 88,529 157,301 43,989 12,067 (145,234) 22,374 10,307 42,930 20,556 

Administrative and General 

Expenses 1,234,812 1,348,736 113,924 1,250,082 (98,654) 1,384,019 133,937 1,410,880 26,860 1,459,411 48,531 

Total OM&A Expenses 3,370,058 3,628,305 258,247 3,686,746 58,441 3,693,585 6,839 3,863,171 169,586 3,968,610 105,439 

Percent change (year over year) 7.66% 1.61% 0.19% 4.59% 2.73% 

Percent change (Test Year vs. Most 

Current Actuals) 7.45% 

Percent change (Test year vs. Last 

Board Approved Rebasing Year) 17.76% 

13 

14 

15 

16 

17 

18 

19 

Average for 2007, 2008, 2009 2.13% 

Compound Annual Growth Rate for 

2006 to 2009 6.47% 

The table above highlights a 17.76% change from the last board approved (2006) OM&A 

amount to the OM&A amount determined for 2010. As the 2006 Board approved amount is 

essentially equal to 2004 actual balances (with a few Board adjustments), the 17.76% increase 

has in fact occurred over a 6 years. This is an average increase of 2.96% per year which is in 

line with the increase in labour rates and rate of inflation since 2004.


EB-2009-0263 

Exhibit 4 

Tab 1 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

Detailed information with respect to OM&A costs and variances, arranged by USoA account, is 

provided at Exhibit 4, Tab 2, Schedule 2 and 3. 

The variance used to determine the OM&A accounts requiring analysis has been prescribed by 

the Filing Requirements as $50,000 year over year, for LDCs with distribution revenue 

requirements under $10 million. 

OM&A Costs: 

OM&A costs in this Exhibit represent Festival Hydro’s integrated set of asset maintenance and 

customer activity needs to meet public and employee safety objectives; to comply with the 

Distribution System Code, environmental requirements and government direction; and to 

maintain distribution business service quality and reliability at targeted performance levels. 

OM&A costs also include providing services to customers connected to Festival Hydro’s 

distribution system, and meeting the requirements of the OEB’s Standard Supply Service Code 

and Retail Settlement Code. 

The proposed OM&A cost expenditures for the 2010 Test Year are the result of a business 

planning and work prioritization process that ensures that the most appropriate, cost effective 

solutions are put in place. 

Festival Hydro is proposing recovery of 2010 Test Year OM&A costs, including amortization 

but excluding PILs and Interest, totaling $6,674,423. 

OM&A Budgeting Process Used by Festival Hydro: 

The operating budget is prepared annually by management and is reviewed and approved by the 

Board of Directors. The budget is prepared before the start of each fiscal year. Once approved, 

it does not change, but provides a plan against which actual results may be evaluated. 

For both the 2009 and 2010 budget processes, each general ledger account was reviewed and 

increased by 3.0% for the labour and benefit components and 2.3% for other components to 

allow for inflationary costs. The accounts were then increased/decreased for any other additional


EB-2009-0263 

Exhibit 4 

Tab 1 

Schedule 1 



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specific costs or savings expected to arise during the given year. Accounts such as outside 

services and bad debt expenses are analyzed and specific amounts established for each of 2009 

and 2010. 

One of the biggest factors driving the increases is the cost of labour and related benefits. Both 

the unionized and non-unionized employees received a 3% increase effective May 1, 2009. Per 

the union contract, unionized employees are to receive another 3% increase effective May 1, 

2010. Increases for non-unionized employees, which are approved annually by the Board of 

Directors, are generally in a similar range as the unionized increases. 

In addition, a five year forecast is created on an annual basis by Senior Management and 

presented to Festival Hydro’s Board of Directors. The five year forecast reflects the impact of 

union agreements and inflationary costs plus any foreseen changes in OM & A expected to take 

place over the five year period. 

The operating budget is a component of the overall budget process described in Exhibit 1, Tab 2, 

Schedule 2. 

Operating Work plans: 

Each department Manager provides input for the preparation of the departmental budget. The 

following directives are provided to each manager: 

18 

19 

20 

 

 

Outside expenses for all department budgets are built using previous year actual, current 

year forecast and current year budget as the base; 

Significant variances in spending from prior years must be explained; 

21 

22 

 

Review the current employees in the department within consideration given to upcoming 

retirements. 

23 

24


EB-2009-0263 

Exhibit 4 

Tab 1 

Schedule 1 



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15 

Income Tax and Ontario Capital Taxes: 

Festival Hydro is subject to the payment of PILs under Section 93 of the Electricity Act, 1998, as 

amended. The Applicant does not pay Section 89 proxy taxes, and is exempt from the payment 

of income and capital taxes under the Income Tax Act (Canada) and the Ontario Corporations 

Tax Act. Table 2 below provides a summary of 2006 OEB Approved, 2006, 2007 and 2008 

income taxes included in audited statements, 2009 Bridge Year estimate using current rates, and 

2010 Test Year income taxes based on revised rates. A copy of the 2008 Federal T2 and Ontario 

CT23 tax return has been provided in Exhibit 4, Tab 1, Schedule 1, Appendix A. Income Tax 

amounts included in the 2009 financial statements are based on estimates and will differ from the 

actual tax return. The difference between actual and estimate will be recorded in 2010 financial 

statements. 

Table 2 

Summary of Income Taxes 

Description 

2006 Board 

Approved 2006 Actual 

2007 

Actual 2008 Actual 2009 Bridge 2010 Test 

Income Taxes 1,252,551 1,131,505 1,303,245 1,097,568 753,906 908,589 

Large Corporation Tax 0 0 0 0 0 0 

Ontario Capital Tax 87,022 92,296 86,067 64,059 59,490 20,317 

Total Taxes 1,339,573 1,223,801 1,389,312 1,161,627 813,396 928,906


EB-2009-0263 

Exhibit 4 

Tab 1 

Schedule 1 

Appendix A 


APPENDIX A 

2008 Federal and Ontario Tax Return


EB-2009-0263 

Exhibit 4 

Tab 1 

Schedule 1 

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EB-2009-0263 

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MANAGERS SUMMARY PER 2.5.1 OF FILING REQUIREMENTS 

DEPARTMENTAL AND CORPORATE OM&A ACTIVITIES: 

OPERATIONS & MAINTENANCE 

The expenses for this department include all costs relating to the operation (5000-5095) 

and maintenance (5105-5195) of the Festival Hydro electrical system. This includes both 

direct labor costs and non-capital material spending to support both scheduled and reactive 

maintenance events. In addition, costs are allocated from support departments to cover the 

costs of Labour Burden, Engineering, Stores, Garage, and Service Center. 

Festival Hydro’s maintenance strategy is, to the extent possible, to minimize reactive and 

emergency-type work through an effective planned maintenance program (including 

predictive and preventative actions). 

Festival Hydro’s customer responsiveness and system reliability are monitored continually 

to ensure that its maintenance strategy is effective. This effort is coordinated with Festival 

Hydro’s capital project work, so that where maintenance programs have identified matters 

the correction of which require capital investments, Festival Hydro may adjust its capital 

spending priorities to address those matters. 

Predictive Maintenance: 

Predictive maintenance activities involve the testing of elements of the Festival Hydro 

distribution system. These activities include infrared thermography testing, transformer oil 

analysis, and planned visual inspections. These evaluation tools are all administered using 

a planned schedule. Any identified deficiencies found are prioritized and addressed within 

a suitable time frame. In establishing the predictive maintenance requirements, FHI 

considers the distribution system code requirements and good utility practices. 

24


EB-2009-0263 

Exhibit 4 

Tab 2 

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Preventative Maintenance: 

Preventative maintenance activities include inspection, servicing and repair of network 

components. This includes overhead and pad-mounted load break switch maintenance, and 

cleaning/inspection of underground vaults. Also included are regular inspection and repair 

of substation components, relays, and ancillary equipment. The work is performed using a 

combination of time and condition based methodologies. In establishing the preventative 

maintenance requirements, FHI considers the distribution system code requirements and 

good utility practices. 

Emergency Maintenance: 

This item includes unexpected system repairs to the electrical system that must be 

addressed immediately. The costs include those related to repairs caused by storm damage, 

emergency tree trimming and on-call premiums. Festival Hydro constantly evaluates its 

maintenance data to adjust predictive and preventative actions. The objective is to keep 

this emergency maintenance to a minimum. 

Service Work: 

The majority of costs related to this work pertain to service upgrades requested by 

customers, and requests to provide safety coverage for work (overhead line cover ups). 

This includes service disconnections and reconnections by Festival Hydro for all service 

classes; assisting pre-approved contractors; the making of final connections after Electrical 

Safety Authority (“ESA”) inspection for service upgrades; and changes of service 

locations. 

Network Control Operations: 

Network operating costs are related to the monitoring and operation of the distribution 

system through Festival Hydro’s Supervisory Control and Data Acquisition (“SCADA”) 

system in Stratford. The engineering department room in Stratford monitors the SCADA


EB-2009-0263 

Exhibit 4 

Tab 2 

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system only on weekdays, during regular business hours. An answering service company 

has been contracted to contact “on call” lineperson and supervisory staff in the event of 

service problems after normal business hours. Real-time breaker status, and voltage and 

current readings from the Hydro One transformer stations and Festival Hydro automated 

switches, are sent to the SCADA system. The engineering department continuously 

monitors the system and dispatch repair crews to manage equipment failures and provide 

work protection for the crews doing work on the system. 

Metering: 

This department is responsible for the installation, testing, and commissioning of new and 

existing simple and complex metering installations. Testing of complex metering 

installations ensures the accuracy of the installation and verifies meter multipliers for 

billing purposes. 

Revenue Protection is another key activity performed by Metering, by proactively 

investigating potential diversion and theft of power. 

Substation Services: 

Substation services activities address the maintenance of all equipment at Festival Hydro’s 

6 substations. This includes both labor costs and non-capital material spending to support 

both scheduled and emergency maintenance events. As with the maintenance activities, 

Festival Hydro’s substation maintenance strategy focuses on minimizing, to the extent 

possible, emergency-type work by improving the effectiveness of Festival Hydro’s planned 

maintenance program (including predictive and preventative actions) for its substations. 

Festival Hydro has been actively converting its 4kV system to 27kV. This has allowed 

Festival Hydro to reduce the number of municipal substations from 10 in 2006 to 6 

substations in 2008. 

25


EB-2009-0263 

Exhibit 4 

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ENGINEERING DEPARTMENT 

Engineering is responsible for delivering underground utility locating services for 

excavating contractors and for design and construction activities including new capital 

projects and customer connections. Engineering also provides distribution system asset 

information to many departments within Festival Hydro. Engineering costs are allocated to 

operations, maintenance, capital, and Third Party receivable accounts based on direct labor 

costs. A standard overhead percentage is set at the beginning of the year and adjusted 

throughout the year as necessary. 

STORES/WAREHOUSE 

Stores staff is accountable for control, and movement of materials within Festival Hydro’s 

service centre. This would include monitoring inventory levels, issuing material receipts, 

material issues, and material returns as required. The cost of the stores department is 

allocated to all departmental, capital, intercompany receivables, and Third Party receivable 

accounts as an overhead cost based on direct material costs. A standard overhead 

percentage is set at the beginning of the year. A standard overhead percentage is set at the 

beginning of the year and adjusted throughout the year as necessary. 

GARAGE/TRANSPORTATION FLEET 

The Transportation group supports the maintenance and control of approximately 25 fleet 

vehicles. Its objectives include maintenance of vehicle reliability and safety, and the 

minimization of vehicle down time. Vehicle costs are allocated to operations, 

maintenance, capital, intercompany receivables, and Third Party receivable accounts based 

on number of hours used. A standard hourly cost/hr is set for all vehicles within the fleet. 

23 

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25


EB-2009-0263 

Exhibit 4 

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SERVICE CENTER 

This department collects the cost of operating and maintaining the service center. Costs include 

items such as repairs to the service center, heat & hydro, grass cutting and snow removal, and 

property taxes. Costs are allocated out based on a square footage. 

LABOUR BURDEN 

This department collects the cost of all employee benefits and payroll taxes such as EI, CPP, 

EHT, WSIB, and group insurances. Costs are allocated to all departments, capital projects, 

intercompany receivable and Third Party receivable amounts based on direct labour. An 

overhead rate is set at the beginning of each year and adjusted throughout the year as necessary. 

SAFETY AND HEALTH 

Costs include Health & Safety program supplies, the costs of third party training facilitators, as 

well internal labour costs associated with safety training and meetings. Festival Hydro is 

committed to maximizing productivity and reducing risk of injury by initiating safety and health 

measures that focus on preventative actions. The commitment to safety and health is significant, 

and involves documenting unsafe behaviors, monitoring conformance to established standards 

and policies, determining the effectiveness of safety training and monitoring the resolution of 

safety recommendations/audits; commitment to continuous improvement in training; and 

identifying and correcting root causes for system deficiencies. Festival Hydro was recently 

awarded 5 years of no lost time up until January 2009, as well as awarded the Effort Level 

E&USA award in 2007. The costs of Safety and Health for lineman are allocated to capital and 

O & M expenses based on standard overhead set at the beginning of the year, and adjusted 

throughout the year as necessary. Health and Safety costs for employees other than lineman are 

charged directly to each general ledger account for a given department. 

24 

25


EB-2009-0263 

Exhibit 4 

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CUSTOMER SERVICE 

The Customer Service group is responsible for the customer care activities for the 

approximately 19,800 customers in Festival Hydro’s service area. These activities include 

meter reading, billing, call centre, collections, and other back office functions. Festival 

Hydro aspires to achieve customer service excellence in its processes and customer 

programs. The costs associated with the Customer Service department are collected in 

accounts 5305 to 5515. 

Meter Reading: 

Meter reading services are contracted out to a non-affiliated third party under a service 

contract agreement. The contractor reads approximately 19,600 electric service meters per 

month. The existing meter contract was negotiated in February 2009 after the completion 

of a competitive bid (RFP) process. The contracts are generally granted for a two year 

term. 

Billing: 

With all customers on monthly billing, Festival Hydro issues approximately 238,000 

invoices annually to customers. An annual billing schedule is created based on the meter 

reading schedule to ensure timely billing of services. The billing functions include the 

VEE processes; account adjustments; processing meter changes; various account related 

field service orders and mailing services and EBT and retailer settlement functions for 

approximately 4,100 retailer accounts. Festival Hydro offers customers a number of billing 

and payment options including an equal payment plan, electronic payments billing, and a 

preauthorized payment plan. 

Collections: 

Collections involve a combination of activities, including the collection of overdue active 

accounts, security deposits and final bills for service termination. Credit risk is a concern


EB-2009-0263 

Exhibit 4 

Tab 2 

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for Festival Hydro with 2010 credit loss forecast at $121,396, which is approximately 

0.26% of 2010 Test Year gross billings of approximately $45,887,000. Establishment of 

provisions for bad debt for bridge year 2009 and test year 2010 are discussed further in 

Exhibit 4, Tab 2, Schedule 4. 

In determining the bad debt expenses for the year, Festival Hydro refers to its past history 

of losses by rate class to establish amounts for the year. There are also specific 

adjustments to the current provision based on other factors such as the economic factors, 

with special considerations for specific industries facing difficulties. 

In an effort to minimize credit losses, Festival Hydro enforces prudent credit policies in 

accordance with the Distribution System Code. Customer deposits are required according 

to the Distribution system Code, and are outlined in Festival Hydro’s Conditions of 

Service. Active overdue accounts are collected by in-house staff through notices, letters 

and direct telephone contact. Final bill collections are turned over to a collection agency 5 

weeks after the final due date, with three notices being sent to the customer in between. 

Festival Hydro works with local agencies that can provide assistances in certain 

circumstances to help customers to maintain continuous service. Previous to 2006, Festival 

Hydro partnered in the Share the Warmth program. From 2006 to 2008, Festival Hydro 

undertook its own program in conjunction with selected local agencies and provided $4,000 

annually in funding to assist in electrical energy assistance. It was the service group’s 

responsibility to assess the qualifications of each applicant. Festival Hydro would then 

provide the agency with up to $200 per customers for those customers who qualified. In 

2009 and forward, Festival Hydro will be committing .12% of the distribution revenue 

requirement for these programs. 

Customer Service: 

The Customer Service department is responsible for such activities as payment processing; 

move in and out requests; and call centre activities for Festival Hydro’s service territory.


EB-2009-0263 

Exhibit 4 

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Call volumes are fairly constant year over year, but may vary due to factors such as storm 

damages/outages, distribution rate changes, and retailers going door to door in the service 

territory. Festival Hydro’s customer service department handles over 26,000 inquires per 

year. The OEB’s SQI tracking requirements as reported in Exhibit 1 Tab 2 Schedule 1 

reveals that the SQI results for customer service have been excellent and are continuously 

met. 

COMMUNITY RELATIONS 

Festival Hydro is committed to providing consumer information and responses, in a timely 

and proactive manner, on electricity distribution and related issues. Since LDCs are the 

“face-to-the-customer” for the electricity industry, Festival Hydro has an important role to 

play in educating the public about electricity safety and energy conservation, as described 

below: 

Education – Electricity Safety: 

Festival Hydro supports elementary schools in its service territory by providing Electricity 

Safety and Conservation sessions for students in grades five. These highly interactive onehour 

sessions educate children in the dangers of electricity. 

Education – Energy Conservation: 

Building a conservation culture continues to be an important objective for Festival Hydro. 

Festival Hydro is very active in the community promoting conservation initiatives, 

attending a number of community events each year, distributing compact florescent light 

bulbs, clothes hanging racks and energy conservation handbooks. Festival Hydro dispersed 

all of its third tranche funding on various CDM programs prior to December 31, 2007. It 

has since actively participated with the OPA in administering their programs directed at 

Energy Conservation, which includes Every Kilowatt Counts, Great Refrigerator Round 

Up, Summer Sweepstakes, Electricity Rebate Incentive Program (ERIP), Power Savings 

Blitz and PeakSaver Program.


EB-2009-0263 

Exhibit 4 

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ADMINISTRATIVE AND GENERAL EXPENSES 

Administrative and general expenses include expenses incurred in connection with the general 

administration of the utility's operations. Within Festival Hydro, the following functional areas 

are considered to be part of general administration and, as such, all expenses incurred within 

these functional areas are accounted for as administrative and general expenses: 

Executive Management (5605); 

General Administrative Salaries and Expenses (5615); 

Executive Salaries and Expenses: 5605 

Remuneration and other expenses of the members of the Festival Hydro Board of Directors are 

included in this account. Remuneration for Festival Hydro Board members is outlined in a City 

of Stratford Bylaw, with basic compensation paid of $3,000 per annum for the Chair of the 

Board of Directors and $2,700 per annum for each director. For any meetings other than 

regularly scheduled board meetings, a per diem is paid to the Chair and each director in 

attendance of $60 if the meeting is less than three hours and $90 if the meeting is greater than 3 

hours. 

The President is responsible for all aspects of Festival Hydro and his salary and benefits are 

charged to account 5605. Also included in this category are the Secretary Treasurer and the Vice 

President of Engineering and Operations. 

General Administrative Salaries and Expenses: 5615 

Financial/Regulatory Services: 

The Finance department is responsible for the preparation of statutory, management and Board 

of Directors financial reporting in accordance with GAAP; all daily accounting functions, 

including accounts payable, accounts receivable, and general accounting; treasury functions 

including cash management, risk management, accounting systems and internal control 

processes; preparation of consolidated budgets and forecasts; and supporting tax compliance.


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

Expenses include salaries and all related expenses associated with the Financial and Regulatory 

Analyst, Senior Accountant, Accounts Payable Clerk, and General Office Clerk. 

The Finance Department is also responsible for all regulatory reporting and compliance with 

applicable codes and legislation governing Festival Hydro. Regulatory reporting includes 

development and preparation of rate filings, performance reporting, and compliance. Expenses 

include salary and related costs associated with the Financial and Regulatory Analyst. 

Information Technology Services: 

The Information Technology department is responsible for the development, operation, 

maintenance and security of all business system applications utilized by the utility in its 

operations. These include the customer information, financial management and work 

management systems. Expenses and all related costs associated with the Manager of Information 

Systems are charged to an account then re-allocated to other departments. 

Outside Service Employed: 5630 

Outside Services Employed include, but are not limited to, consulting and professional fees of 

accountants and auditors, actuaries, legal services, environmental monitoring costs, human 

resource professionals and tax consultants. Professional and other expenses related to the 2010 

Cost of Service Rate Application are included in 5655 Regulatory Expenses. 

Employee Post-Retirement Benefits: 5645 

Employee Post-Retirement Benefits include annual expenses for post-retirement benefits 

provided to eligible Festival Hydro employees in accordance with company policy and as 

provided in the collective bargaining agreement between Festival Hydro and its union. The 

annual expense and liability are determined in accordance with Section 3461 of the CICA 

Handbook and supported by an actuarial valuation that is completed every three years. Also 

included in this account are actual premiums paid for benefits for existing retirees. 

25


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

Regulatory Expenses: 5655 

Regulatory Expenses include those expenses incurred in connection with Decisions and Orders 

on Cost Awards for hearings, proceedings, technical sessions, and other matters before the OEB 

or other regulatory bodies, including annual assessment fees paid to a regulatory body. Annual 

fees assessed by the OEB are included in this expenditure category. All incremental costs 

associated with the 2010 Cost of Service Rate Application are included in this account. Festival 

Hydro has increased this account by $40,000 for 2010 rate year and the following three years to 

cover the cost of the 2010 Cost of Service rate application and additional increased regulatory 

cost and workload related amendments to the Distribution System Code, Conditions of Service 

and other new compliance requirements. 

Miscellaneous General Expense: 5665 

Miscellaneous General Expense includes EDA membership fees. Also included in this category 

are health and safety costs (general – not charged to specific departments) and other 

miscellaneous costs. 

Electrical Safety Authority Fees: 5680 

Expenses under Electrical Safety Authority (“ESA”) fees include all annual charges from the 

ESA. 

18


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 2 



Operation 

Expense Description 

2006 Board 

Approved 

OM&A Cost Table 

Variance 

from 2006 

Board 

2006 Actual Approved 2007 Actual 

Variance 

from 2006 

Actual 

2008 Actual 

Variance 

from 2007 

Actual 

2009 Bridge 

Variance 

from 2008 

Actual 

2010 Test 

Variance 

from 2009 

Bridge 

5005-Operation Supervision and Engineering 0 0 0 0 0 0 0 0 0 0 0 

5010-Load Dispatching 12,758 38,279 25,521 38,077 (202) 35,857 (2,220) 36,706 849 37,575 869 

5012-Station Buildings and Fixtures Expense 38,619 29,398 (9,221) 22,644 (6,754) 35,436 12,792 36,326 890 37,238 913 

5014-Transformer Station Equipment - Operation Labour 0 0 0 0 0 0 0 0 0 0 0 

5015-Transformer Station Equipment - Operation Supplies and Expenses 0 0 0 0 0 0 0 0 0 0 0 

5016-Distribution Station Equipment - Operation Labour 8,414 4,353 (4,061) 2,975 (1,378) 2,120 (855) 2,182 62 2,247 64 

5017-Distribution Station Equipment - Operation Supplies and Expenses 2,151 2,084 (67) 269 (1,815) 9 (260) 9 0 9 0 

5020-Overhead Distribution Lines and Feeders - Operation Labour 4,859 23,144 18,285 8,815 (14,329) 16,418 7,603 16,891 473 17,313 422 

5025-Overhead Distribution Lines & Feeders - Operation Supplies and Expenses 44,545 39,670 (4,875) 35,063 (4,608) 35,538 475 36,355 817 37,191 836 

5030-Overhead Subtransmission Feeders - Operation 0 0 0 0 0 0 0 0 0 0 0 

5035-Overhead Distribution Transformers- Operation 14,675 14,587 (88) 14,678 91 13,869 (809) 14,243 374 14,628 384 

5040-Underground Distribution Lines and Feeders - Operation Labour 5,974 6,227 253 3,721 (2,506) 8,840 5,119 9,095 255 9,358 263 

5045-Underground Distribution Lines & Feeders - Operation Supplies & Expenses 4,149 33,630 29,481 25,403 (8,227) 1,555 (23,848) 1,590 35 1,627 37 

5050-Underground Subtransmission Feeders - Operation 0 0 0 0 0 0 0 0 0 0 0 

5055-Underground Distribution Transformers - Operation 0 0 0 0 0 13,153 13,153 13,394 241 13,760 366 

5060 - Street Lighting and Signal System Expense 0 0 0 0 0 0 0 0 0 0 0 

5065-Meter Expense 157,975 163,230 5,255 167,992 4,762 241,752 73,760 248,332 6,580 255,093 6,761 

5070-Customer Premises - Operation Labour 96,689 152,344 55,655 184,195 31,851 199,793 15,598 205,632 5,839 211,642 6,010 

5075-Customer Premises - Materials and Expenses 705 1,635 930 1,857 222 1,855 (2) 1,898 43 1,942 44 

5085-Miscellaneous Distribution Expense 4,705 13,148 8,443 8,157 (4,991) 9,178 1,021 9,401 223 9,630 229 

5090 - Underground Distribution Lines and Feeders - Rental Paid 0 0 0 0 0 0 0 0 0 0 0 

5095-Overehad Distribution Lines & Feeders - Rent Paid 7,948 6,983 (965) 8,661 1,678 8,540 (121) 8,737 197 8,938 201 

5096 - Other Rent 0 0 0 0 0 0 0 0 0 0 0 

Sub-Total 404,166 528,712 124,546 522,506 (6,206) 623,913 101,407 640,791 16,878 658,190 17,399


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 2 



Maintenance 

5105-Maintenance Supervision and Engineering 0 0 0 0 0 0 0 0 0 0 0 

5110-Maintenance of Buildings and Fixtures - Distribution Stations 5,066 2,522 (2,544) 128 (2,394) 2,195 2,067 2,246 51 2,299 52 

5112-Maintenance of Transformer Station Equipment 0 0 0 0 0 0 0 0 0 0 0 

5114-Maintenance of Distribution Station Equipment 14,146 4,048 (10,098) 2,168 (1,880) 0 (2,168) 0 0 0 0 

5120-Maintenance of Poles, Towers and Fixtures 14,302 4,021 (10,281) 22,259 18,238 19,165 (3,094) 19,671 506 20,191 520 

5125-Maintenance of Overhead Conductors and Devices 92,168 100,215 8,047 190,836 90,621 98,977 (91,859) 101,807 2,830 104,719 2,912 

5130-Maintenance of Overhead Services 382,517 144,851 (237,666) 196,297 51,446 192,314 (3,983) 198,083 5,769 204,026 5,943 

5135-Overhead Distribution Lines and Feeders - Right of Way 120,738 178,738 58,000 175,642 (3,096) 161,754 (13,888) 166,077 4,323 170,517 4,440 

5145-Maintenance of Underground Conduit 780 16,496 15,716 10,201 (6,295) 43,783 33,582 44,999 1,216 46,250 1,251 

5150-Maintenance of Underground Conductors and Devices 36,937 101,551 64,614 104,509 2,958 95,896 (8,613) 98,552 2,656 101,282 2,730 

5155-Maintenance of Underground Services 74,365 80,161 5,796 75,696 (4,465) 83,513 7,817 85,817 2,304 88,185 2,368 

5160-Maintenance of Line Transformers 41,771 38,154 (3,617) 32,429 (5,725) 23,194 (9,235) 23,848 654 24,520 672 

5165-Maintenance of Street Lighting and Signal Systems 0 0 0 0 0 0 0 0 0 0 0 

5170-Sentinel Lights - Labour 0 0 0 0 0 0 0 0 0 0 0 

5172-Sentinel Lights - Materials and Expenses 0 0 0 0 0 0 0 0 0 0 0 

5175-Maintenance of Meters 13,587 4,151 (9,436) 24,918 20,767 24,664 (254) 25,235 571 25,818 584 

5178-Customer Installations Expenses - Leased Property 0 0 0 0 0 0 0 0 0 0 0 

5195-Maintenance of Other Installations on Customer Premises 0 0 0 0 0 0 0 0 0 0 0 

Sub-Total 796,377 674,908 (121,469) 835,083 160,175 745,455 (89,628) 766,335 20,880 787,807 21,472 

Billing and Collections 

5305-Supervision 21,196 22,038 842 23,078 1,040 22,972 (106) 23,661 689 24,371 710 

5310-Meter Reading Expense 130,855 111,434 (19,421) 105,607 (5,827) 100,757 (4,850) 103,296 2,538 105,899 2,603 

5315-Customer Billing 406,127 358,406 (47,721) 355,638 (2,768) 374,573 18,936 383,914 9,341 393,491 9,577 

5320-Collecting 178,774 149,434 (29,340) 147,483 (1,951) 153,281 5,798 157,598 4,317 162,038 4,440 

5325-Collecting- Cash Over and Short 5 -117 (122) 10 127 17 6 17 0 17 0 

5330-Collection Charges (28,662) 0 28,662 0 0 0 0 0 0 0 0 

5335-Bad Debt Expense 60,816 152,889 92,073 111,956 (40,933) 74,700 (37,256) 146,037 71,337 121,396 (24,641) 

5340-Miscellaneous Customer Accounts Expenses 140,808 168,553 27,745 178,001 9,448 201,830 23,829 208,269 6,439 213,059 4,790 

Sub-Total 909,919 962,636 52,717 921,773 (40,863) 928,131 6,358 1,022,792 94,661 1,020,272 (2,520)


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 2 




5405-Supervision 5,019 862 (4,157) 790 (73) 172 (617) 176 4 180 4 

5410-Community Relations - Sundry 3,913 783 (3,130) 1,052 269 883 (169) 904 21 925 21 

5415-Energy Conservation 9,000 106,360 97,360 145,489 39,129 460 (145,028) 10,460 10,000 30,701 20,241 

5420-Community Safety Program 6,852 5,308 (1,544) 9,971 4,663 10,552 581 10,834 282 11,124 290 

5425-Miscellaneous Customer Service and Informational Expenses 0 0 0 0 0 0 0 0 0 0 0 

5505-Supervision 0 0 0 0 0 0 0 0 0 0 0 

5510-Demonstrating and Selling Expense 0 0 0 0 0 0 0 0 0 0 0 

5515-Advertising Expense 0 0 0 0 0 0 0 0 0 0 0 

5520-Miscellaneous Sales Expense 0 0 0 0 0 0 0 0 0 0 0 

Sub-Total 24,784 113,313 88,529 157,301 43,989 12,067 (145,234) 22,374 10,307 42,930 20,556 


5605-Executive Salaries and Expenses 305,461 373,486 68,025 393,385 19,899 446,029 52,644 458,625 12,596 478,580 19,956 

5610-Management Salaries and Expenses 0 0 0 0 0 0 0 0 0 0 0 

5615-General Administrative Salaries and Expenses 191,561 265,273 73,712 255,062 (10,211) 263,958 8,897 271,877 7,919 280,033 8,156 

5620-Office Supplies and Expenses 79,625 83,070 3,445 90,248 7,178 89,370 (878) 91,425 2,055 93,528 2,103 

5625-Administrative Expense Transferred-Credit 0 0 0 0 0 0 0 0 0 0 

5630-Outside Services Employed 83,429 224,966 141,537 99,928 (125,039) 172,995 73,067 166,287 (6,708) 133,312 (32,975) 

5635-Property Insurance 51,423 13,135 (38,288) 16,198 3,063 15,039 (1,159) 15,385 346 15,739 354 

5640-Injuries and Damages 55,678 46,250 (9,428) 53,195 6,945 54,827 1,632 56,088 1,262 57,378 1,290 

5645-Employee Pensions and Benefits 102,953 102,326 (627) 101,419 (907) 96,125 (5,294) 99,009 2,884 101,979 2,970 

5650-Franchise Requirements 0 0 0 0 0 0 0 0 0 0 

5655-Regulatory Expenses 77,303 55,763 (21,540) 67,427 11,663 59,003 (8,424) 60,360 1,357 101,748 41,388 

5660-General Advertising Expenses 0 0 0 0 0 0 0 0 0 0 

5665-Miscellaneous General Expenses 162,658 43,041 (119,617) 46,960 3,919 42,847 (4,113) 43,893 1,046 44,965 1,072 

5670-Rent 0 0 0 0 0 0 0 0 0 0 0 

5675-Maintenance of General Plant 121,119 132,577 11,458 117,311 (15,266) 134,374 17,063 138,255 3,881 142,249 3,994 

5680-Electrical Safety Authority Fees 3,452 8,548 5,096 8,849 301 9,202 353 9,418 216 9,635 217 

5685-Independent Electricity System Operator Fees and Penalties 0 0 0 0 0 0 0 0 0 0 0 

5695-OM&A Contra Account 0 0 0 0 0 0 0 0 0 0 0 

6205-Charitable Donations 150 300 150 100 (200) 250 150 258 8 263 6 

Sub-Total 1,234,812 1,348,736 113,924 1,250,082 (98,654) 1,384,019 133,937 1,410,880 26,860 1,459,411 48,531


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 2 



Taxes Other Than Income Taxes 

6105-Property Taxes & Capital taxes 32,056 129,853 97,797 124,805 (5,048) 59,500 (65,305) 89,490 29,990 50,317 (39,173) 

Sub-Total 32,056 129,853 97,797 124,805 (5,048) 59,500 (65,305) 89,490 29,990 50,317 (39,173) 

Total Operating, Maintenance and Administration Expenses 3,402,114 3,758,158 356,044 3,811,551 53,393 3,753,085 (58,466) 3,952,661 199,576 4,018,927 66,266 

Amortization Expenses 

Amortization Expense - Property, Plant, and Equipment 2,036,189 2,190,695 154,506 2,244,836 54,141 2,393,253 148,416 2,537,780 144,527 2,655,496 117,716 

Sub-Total 2,036,189 2,190,695 154,506 2,244,836 54,141 2,393,253 148,416 2,537,780 144,527 2,655,496 117,716 

Total Distribution Expense Before Income Taxes 5,438,303 5,948,853 510,550 6,056,387 107,534 6,146,338 89,950 6,490,441 344,104 6,674,423 183,981 

Variance Determined as 1% of Total Distribution Expense before Taxes 54,383 59,489 5,106 60,564 1,075 61,463 900 64,904 3,441 66,744 1,840


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 3 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

VARIANCE ANALYSIS ON OM&A COSTS: 

Festival Hydro has provided a detailed OM&A cost table covering the periods from 2006 Board 

Approved, 2006 Actual, 2007 Actual, 2008 Actual, 2009 Bridge Year and 2010 Test Year 

including the variances year over year in Exhibit 4, Tab 2, Schedule 3, above. Before moving to 

a variance analysis for each account that exceeds the materiality threshold, a summary of total 

OM&A expenses (excluding depreciation) is presented below along with an analysis of the total 

movement from 2006 Board Approved ($3,402,114) to 2006 Actual ($3,758,158) in the first 

column through to 2010 Test Year in the final column. In addition, a table is provided indicating 

OM&A cost per customer and OM&A cost per FTE for 2006 through 2010 as well as a table that 

highlights various regulatory costs incurred and expected in the bridge and test years. 

The following table identifies key cost drivers from 2006 to 2010 Test year: 

2006 2007 2008 2009 2010 

Opening Balances 3,402,114 3,758,158 3,811,551 3,753,085 3,952,662 

Labour 84,183 21,133 35,002 50,405 51,918 

Materials (121,780) 15,862 (26,303) 2,072 1,770 

Outside services 49,131 (75,698) 90,312 8,387 15,150 

Office supplies 14,152 5,665 22,947 6,091 5,206 

Fuel 20,070 41,871 63,122 9,373 8,011 

Other 23,057 51,411 4,044 11,921 27,784 

Adjustments or writeoffs 92,073 (40,933) (37,256) 71,337 (24,641) 

PIL Property tax 97,797 (5,048) (65,305) 29,990 (39,173) 

Energy Conservation 97,360 39,129 (145,029) 10,000 20,241 

Total 3,758,158 3,811,551 3,753,085 3,952,662 4,018,927 

The cost driver table above highlights the trends year over year in various groupings of expenses 

incurred by FHI. The increasing trend in labour year over year is reasonable given the general 

increases in union wage contracts. The amount of labour charged to OM&A is also dependent 

on the amount of labour spent on capital – this being the reason why it may be more or less year 

to year. 

The material cost driver decreased from 2004 (2006 Board approved) as compared to the 2006 

actual expenses. Maintenance activities were less in 2006 than Board approved, with total 

maintenance cost of $674,908 in 2006 compared to Board approved of $796,377, and less being


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 3 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

26 

27 

spent on materials. The material cost driver again decreased in 2008 as a result of a reduction in 

total maintenance spending from $835,083 spent on maintenance in 2007 compared to $745,455 

in 2008. 

Outside service expenses decreased in 2007 as a result mainly of the decrease in environmental 

monitoring expenses Festival Hydro incurred. In 2006 significantly more was spent on 

environmental testing as permanent testing sites were constructed. 2007 costs incurred were 

solely for monitoring. This expense increased again in 2008 as a result of increased testing 

performed in 2008. This category of expense also includes professional fees paid to legal 

counsel and auditing/tax consultants. Various one time consulting projects were undertaken in 

2006 resulting in an increased expense to this account in that year versus the average year. For 

example, Hydro One was contracted to perform weather normalized load forecasts for the 2006 

cost of service study. Also in 2006 the Ontario Utility Smart Metering (OUSM) Group was 

contracted to assist on the assessment of specifications for smart metering communications and 

performed testing on various different meter options. The cost driver increased in 2008 as a 

result of the additional environmental testing noted above and also as a result of additional fees 

being paid to KPMG to file amended tax returns for 2005 & 2006 to include a SR&ED claim in 

these filings. 

The cost driver including office supplies has increased consistently year over year. There is a 

peak in this cost driver in 2008 as a result of increased postage expenses in that year due to new 

postage rates. It is projected that this cost driver will continue to increase in 2009 and 2010, but 

at inflationary rates. 

The fuel cost driver peaked in 2008 as a result of very high oil prices in that year. 2009 and 2010 

project this cost driver to decrease due to anticipated lower and more stable fuel pricing. The 

purchase of new, more fuel efficient fleet based on Festival’s fleet replacement plan also 

contributes to this decrease. 

Other expenses include items such as service charges, safety equipment, small tools, and 

municipal taxes. This cost driver was at its lowest in 2008 as a result of the fact that 2007


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 3 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

included one-time costs that were not in 2008 for work performed in relation to the E&USA 

Silver Award for safety. In addition regulatory expenses were over-accrued in 2007 and the 

over-accrual was cleared out in 2008. In 2009 and 2010 the increase in these cost drivers are 

returning to expected levels. 

The bad debt cost driver peaked in 2006 and 2008, the years when two large industrial customers 

filed for credit protection under CIAA thereby causing the bad debt expense to increase. As 

expected, this cost driver is reduced in the years when large customer write-offs did not occur. 

The trend in the property and capital taxes are expected to continue to decline as the tax rates are 

reduced. In 2008 however, an over accrual of property tax from a prior year was adjusted, 

thereby reducing the 2008 expense balance. The result of this adjustment is that the cost driver 

appears to go up in 2009 when the expenses go back to usual rates. The driver decreases again in 

2010 when the capital tax rate decreases again and due to the fact that capital tax in Ontario is 

expected to be eliminated effective July 1, 2010. 

Account 5415 is a cost driver that has been identified individually given the swing in the balance 

of this account in 2008 and this account includes costs related to conservation programs. The 

decrease in 2008 is a function of the new December 2005 guideline which instructed LDC’s to 

place Conservation and Demand Side Management costs and recoveries in the income statement 

versus a balance sheet variance account as was done in the past. The income was collected over 

one year (March 2005 – Feb. 2006) however the expenses were incurred up until the end of 

September 2007. Therefore the 2008 cost driver was decreased significantly as conservation 

expenses booked in 2007 weren’t incurred in 2008. 

22


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 3 



1 

2 

3 

4 

5 

6 

The following table highlights the regulatory costs from 2006 to the 2010 Test year. Included 

in 2010 and for the subsequent three year period is a $40,000 increase in annual regulatory 

costs. This increase is required to cover the expenses associated with the 2010 Cost of 

Service Application and cover the costs of future work loads associated with amendments to 

the Distribution System Code, changes to Conditions of Service, Cost of Capital hearings and 

other regulatory related matters. 

Regulatory Cost Category 

G.L. Acct # 5655 

USoA 

Account 

Balance for 

5655 

Festival Hydro Inc. - Regulatory Cost Schedule 

Ongoing or 

One-Time 

Cost 

Last 

Rebasing 

Year 2006 2007 2008 

Bridge Year 

2009 

% Change in 

bridge year 

vs. last year 

of actuals 

Test Year 

Forecast 2010 

% Change in 

Test Year vs. 

Bridge Year 

OEB Annual Assessment 

See totals at 

bottom Ongoing 53,738 61,448 53,514 54,745 2.3% 56,008 22.9% 

OEB Hearing Assessments 

(applicant initiated) 

One time 

OEB Section 30 Costs (OEB 

initiated) Ongoing 544 2,459 4,010 4,101 2.3% 4,195 2.3% 

Expert Witness cost for 

regulatory matters 

One time 

Legal costs for regulatory 

matters Ongoing 14,000 100.0% 

Consultants costs for 

regulatory matters Ongoing 14,000 100.0% 

7 

8 

Operating expenses 

associated with staff resources 

allocated to regulatory matters 

(incremental) Ongoing 6,000 100.0% 

Operating expenses 

associated with other 

resources allocated to 

regulatory matters 

One time 

Other regulatory agency fees 

or assessments - Annual OEB 

Registration Ongoing 800 800 800 818 2.3% 818 0.0% 

Costs associated with annual 

IRM/OEB filings, (i.e. 

newspaper ads, courier, 

webpage updates) Ongoing 553 1,775 679 696 2.3% 727 2.3% 

Intervenor Costs Ongoing 128 945 0 0 6,000 100.0% 

Total for G.L. #5655 55,763 67,427 59,003 60,360 2.3% 101,748 68.5% 

9 

10 

11 

12 

13


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 3 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

The following table highlights the OM&A cost per customer and FTEE. During the period 

from 2006 Board Approved to 2010, Festival Hydro has seen the total number of customers 

increase by approximately 5.6%. During such time the overall cost increases have tracked the 

rate of inflation, however, the average cost per customer is only increasing at a rate of less 

than 2% per year which is below the rate of inflation. 

There is an increase in the O M& A cost per customer over time because expenses are 

increasing at a rate which is faster than the growth in the customer base. Festival Hydro is in 

a low population growth area. 

There is also an increase in O M & A per FTE over time. Festival Hydro continues to manage 

more assets and take on additional initiatives with basically the same number of staff. 

11 

OM&A Cost Per Customer and FTE 

12 

13 

2006 Board Approved 2006 Actual 2007 Actual 2008 Actual 2009 Bridge Year 2010 Test Year 

Number of Customers 24,482 24,905 25,130 25,405 25,638 25,874 

Total OM&A 3,402,114 3,758,158 3,811,551 3,753,085 3,952,661 4,018,927 

OM&A cost per Customer 138.96 150.90 151.67 147.73 154.17 155.33 

Number of FTEs 45.7 45.0 44.0 44.0 44.0 45.0 

FTEs/Customer 0.002 0.002 0.002 0.002 0.002 0.002 

OM&A cost per FTE 74,444.51 83,514.62 86,626.16 85,297.39 89,833.21 89,309.49 

14 

15


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 3 



1 

2 

3 

4 

5 

6 

7 

Variance Analysis: 

As mentioned above, the variance that triggers the required analysis is $50,000, since the 

distribution revenue requirement for the 2010 test year is less than $10 million. Festival Hydro 

has reviewed the variance of each OEB USoA account to determine where explanations are 

necessary. In addition, OM&A expenses were reviewed by category with a variance analysis 

provided for each category that increased or decreased by $50,000 or more over the year. A 

description is provided below for each variance exceeding the threshold. 

8 

VARIANCE ANALYSIS ON USoA ACCOUNTS 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

2006 ACTUAL VERSUS 2006 BOARD APPROVED: 

5070 – Customer Premises – $55,655 greater in 2006 than 2006 Board approved 

In the 2006 rate application, under-allocated costs were all charged to 5130. To better reflect the 

cost belonging to each USoA account, in 2006 this under-allocated cost was reallocated to the 

remaining O & M accounts based on the regular labour charged to each. As a result, $40,481 

was moved from 5130 to 5070. 

5130 – Maintenance of Overhead services – $237,666 lower in 2006 than 2006 Board approved 




was moved from 5130 to the remaining O & M accounts based on the original labour charged to 

each. 

21 

22


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 3 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

5135 – Overhead Distribution Right of Way – $58,000 greater in 2006 than 2006 Board 

approved 

In the 2006, the tree trimming program was expanded, especially for the six small towns 

acquired by the City of Stratford as part of the amalgamation. These increases are the result of a 

greater focus on preventative maintenance which started in 2005. In addition, $13,724 was reallocated 

from 5130 to 5135. 

5150 – Maintenance of U/G Conductors & Devices – $64,614 greater in 2006 than 2006 Board 

approved 

Festival Hydro undertook full scale dry ice switchgear cleaning in 2006. This is now part of 

the regular preventative maintenance program with the entire service area covered over a time 

period. In addition, $15,915 was re-allocated from 5130 to 5150. 

5335 – Bad Debt Expense – $92,073 greater in 2006 than 2006 Board approved 

A general service customer > 50 kW filed Chapter 11 in the U.S. and subsequently CCAA in 

Canada in October 2006. The amount owing totaled $106,732. The customer had always been 

up to date and only owed the current billed and the unbilled portion at time of the CCAA filing. 

5415 – Energy conservation – $97,360 greater in 2006 than 2006 Board approved 

This large increase is a function of the new December 2005 guideline which instructed LDC’s to 


versus a balance sheet variance account as was done in the past. The 2006 Board approved only 

included the $9,000 for LED light distribution requested as part of the 2006 Rate application. 

5605 – Executive Salaries and Expense - $68,025 greater in 2006 than 2006 Board approved 

In 2005 a salary review was conducted for senior management comparing senior positions at 

Festival Hydro to similar positions at similar sized LDCs. Comparisons were also made to 

similar jobs within the geographic area. As a result, compensation was increased to bring


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 3 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

salaries more in line with comparable positions. At the same time, two of the three senior 

management staff moved higher within their respective pay grid. Spending on safety training 

also increased, as Festival Hydro worked towards achieving the EUSA silver award. 

5615– General Admin. Salaries & Expenses - $73,712 greater in 2006 than 2006 Board approved 

In the 2006 Rate application, an entry was made to Schedule 2-4 Adjusted Trial Balance to 

remove $42,670 from non-utility revenue (4080) and general administration expenses of $42,670 

as it related to income from an affiliate and was considered non-distribution activity. The actual 

2006 numbers includes the full amount of the expenses, as well, the income was recorded in 

4080. Ignoring this entry, the general administration expenses in 2004 were $234,231. Apply 

the costs of wages for the two year period accounts for an increase of $14,264. In addition, 

higher than normal overtime was incurred as one administration position worked extra hours to 

cover for a fellow employee on sick leave. 

5630 – Outside services employed – $141,537 higher in 2006 than 2006 Board approved. 

Additional expenses were incurred in 2006 to provide for more permanent access to ground 

environmental testing sites. This one time cost in 2006 would allow for on-going environmental 

testing going forward in future years. 

Other costs include Hydro One being contracted to perform a weather normalized load forecast 

for the 2006 Cost of Service study. Also in 2006 the OUSM group was contracted to assist on 

the assessment of specifications for smart metering communications and performed testing on 

various different meter options. 

5665 – Misc General Expense – $119,617 lower in 2006 than 2006 Board approved. 

The 2006 Board approved model included a Tier 1 adjustment for Low Voltage Charges in the 

amount of $126,265. Low voltage charges in 2006 were charged to variance and deferral 

accounts and set up as a payable to Hydro One. 

25


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 3 



1 

2 

3 

4 

6105 – Property Tax and Capital tax – $97,797 higher in 2006 than 2006 Board approved. 

The 2006 Board approved model includes only the amount of $32,056 representing the Property 

PILs. Capital tax was included with the PILs in the model. The Actual 2006 includes the 

capital tax expense in this account. 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

2007 ACTUAL VERSUS 2006 ACTUAL: 

5125 – Maintenance of Overhead Conductors and Devices – $90,621 more in 2007 than in 2006. 

Part of this increase relates to an increase in the depreciation allocated to this account resulting 

from the delivery of a $270,000 double bucket truck and a $236,000 single bucket truck in 2007. 

This was an unusual circumstance to have 2 new bucket trucks arrive in the same year. The 

remaining increase is the result of higher costs in overhead line maintenance and repairs resulting 

from higher than normal storm damage in 2007. 

5130 – Maintenance of Overhead Services – $51,446 more in 2007 than in 2006. 

This variance is the result of the two items noted above as well. 

5630 – Outside services employed – $125,039 less in 2007 than in 2006. 

Various one time consulting projects were undertaken in 2006 resulting in an increased expense 

to this account in that year versus the average year. For example, Hydro One was contracted to 

perform a weather normalized load forecast for the 2006 Cost of Service Study. Also in 2006 the 

OUSM group was contracted to assist on the assessment of specifications for smart metering 

communications and performed testing on various different meter options. In 2007, 

environmental testing was limited to monitoring activities. 

22


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 3 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

2008 ACTUAL VERSUS 2007 ACTUAL: 

5065 – Meter expense – $73,760 more in 2008 than in 2007. 

This increase is the result of the fact that the metering points rebate program from Hydro One 

ended in 2007. This rebate was netted with expenses in 2007 and amounted to $66,213. 

5125 – Maintenance and Overhead Conductors and Devices – $91,859 less in 2008 than in 2007. 

This variance is the result of lower storm repair and maintenance costs in 2008 than were 

experienced in 2007. 

5415 – Energy Conservation – $145,028 less in 2008 than in 2007 

This large decrease is a function of the new December 2005 guideline which instructed LDC’s to 


versus a balance sheet variance account as was done in the past. The majority of this variance 

relates to $126,000 of conservation expense booked in 2007. Third tranche funds were all 

dispersed by the end of 2007. In 2008, the OPA funded programs commenced. 

5605 – Executive Salaries and Expenses - $52,644 higher in 2008 than in 2007. 

There was a 3% increase in salary for all members of senior management. Professional 

accounting courses were paid for a member of senior management, which totaled $13,000 for the 

year. In addition, the Festival Hydro Board of Directors was increased from 7 to 9 members. 

Additional training costs were incurred for two senior management positions who took part in 

the four day Occupation and Safety training, moving closer to meeting the Company’s objective 

of all staff being Safety Certified. 

5630 – Outside services employed - $73,067 more in 2008 than in 2007. 

The increased cost in 2008 is the result of additional fees being paid to KPMG to file amended 

tax returns for 2005 & 2006 to include a SR&ED claim in these filings. Additional 

environmental testing was conducted compared to testing completed in 2007.


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 3 



1 

6105- Property & Capital Taxes - $65,305 lower in 2008 than in 2007 

2 

3 

4 

In 2008 an over accrual of property tax from a prior year was adjusted, thereby reducing the 

2008 expense balance. Also the capital tax rate was reduced and the exemption increased in 

2008. 

5 

6 

7 

8 

9 

10 

11 

12 

2009 BRIDGE YEAR VERSUS 2008 ACTUAL: 

5335 – Bad Debt Expense – $71,337 greater in bridge year 2009 than 2008 

A large customer with three locations in Stratford (one large use and 2 G.S. > 50 kW accounts) 

filed Chapter 11 in the U.S. and subsequently CCAA in Canada in August 2009. Festival Hydro 

has at risk the unbilled portion, of which 50% has been allowed as uncollectible at this time. In 

addition, the 2009 provision has been raised above the 2008 actual, which was low compared to 

the recent trends. Losses were abnormally low in 2008, primarily due to the fact there were no 

losses associated with General Service > 50 kW. 

13 

14 

15 

16 

17 

18 

2010 TEST YEAR VERSUS 2009 BRIDGE YEAR 

5335 – Bad Debt Expense – $24,641 lower in test year 2010 than 2009 bridge year 

The bad debt expense has been determined based on the trend in bad debts over the past three 

years plus projected 2009 bridge year. The 2010 provision is down from 2009 when one large 

customer entered into creditor filing under CCAA. Below is a table which shows how the Bad 

Debt Expense was calculated for 2010.


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 3 



Bad Debt Expense for 2010 Test year 

Four Year Test Year 

2006 2007 2008 2009 Total 2010 

Acutal & BridgeBad Debt expense 152,889.00 111,956.00 74,700.00 85,000.00 424,545.00 

Add: Large customer CCAA filing ( allow 50%) 

increase to original 2009 budget 61,037.31 61,037.31 

1 

2 

Total bad debt expense 152,889.00 111,956.00 74,700.00 146,037.31 485,582.31 121,395.58 

(2010 rate application ‐ Four year average) 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

VARIANCE ANALYSIS FOR OM&A GROUPINGS 

2006 BOARD APPROVED VERSUS 2006 ACTUAL 

2006 actual is $124,546 (31%) higher than 2006 board approved for operation expenses. 




was moved from 5130 to the remaining Operations series of accounts 5005 to 5096. 

A portion of the increase in operation expenses relates to an increase in operational labour 

expense and benefits expense of 3% as agreed upon in the union contract. 

2006 actual is $121,469 lower (15%) than 2006 board approved for maintenance expenses. 

As noted above, $122,973 was moved from 5130 to the remaining Operations series of accounts 

5005 to 5096 to better reflect costs in the respective general ledger accounts. This accounted for 

most of the increase. 

2006 actual is $52,717 (6%) higher than 2006 board approved for billing and collections 

expenses. 

This increase is the result of an increase to bad debt expense in 2006 as the result of one large 

general service customer filing for CCAA creditor protection during the year. The large increase


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 3 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

in bad debt expense is netted against decreases in costs in areas such as meter reading, customer 

billing and collections. These expense reductions are the result of items such as meter readers 

delivering disconnection notices rather than sending them via Xpress post which reduced costs. 

2006 actual is $88,529 (357%) higher than 2006 board approved for community relations 

expenses. 

The increase in this expense from 2006 board approved to 2006 actual is the result of the new 

December 2005 guideline which instructed LDC’s to place Conservation and Demand Side 

Management costs and recoveries in the income statement versus a variance account as done in 

the past. The income was collected over one year (March 2005 – Feb. 2006); however the 

expenses were incurred up until the end of September 2007. This variance represents the amount 

of CDM third tranche funding spent on CDM activities and programs in 2006. 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

2006 actual is $113,924 (9%) higher than 2006 board approved for administrative and general 

expenses. 

There are three areas which contribute the increase being account 5605 Executive Salaries and 

expenses and 5615 Administrative Salaries and expenses and 5630 Outside services employed. 

In 2005 a salary review was conducted for senior management (5605) comparing senior 

positions at Festival Hydro to similar positions at similar sized LDCs. As a result, compensation 

was increased to bring salaries more in line with comparable positions. At the same time, two of 

the three senior management staff moved higher within their respective pay grid. 

In the 2006 Rate application, an entry was made to Schedule 2-4 Adjusted Trial Balance to 

remove $42,670 from non-utility revenue (4080) and general administration expenses (5615) of 

$42,670 as it related to income from an affiliate and was considered non-distribution activity. 

The actual 2006 numbers include the full amount of the expenses (and the income was recorded 

in 4080). In addition, the costs of wages for the two year period (2004 to 2006) accounts for an


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 3 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

increase of $14,264. Higher than normal overtime incurred in 2006 as one administration 

position worked extra hours to cover for a fellow employee on sick leave also accounted for the 

higher cost. 

Additional expenses were incurred in 2006 to provide for more permanent access to ground 

environmental testing sites. This one time cost in 2006 would allow for on-going environmental 

testing going forward in future years. 

These increases were offset by an $119,617 decrease in 5665 Miscellaneous General Expense. 

The 2006 Rate application included low voltage costs in this account, but in 2006 they were 

actual book to the deferral and variance accounts. 

6105 – Property Tax and Capital tax – $97,797 higher in 2006 than 2006 Board approved. 

The 2006 Board approved model includes only the amount of $32,056 representing the Property 

PILs. Capital tax was included with the PILs in the model. The Actual 2006 includes the 

capital tax expense in this account. 

14 

15 

16 

17 

18 

19 

20 

2007 ACTUAL VERSUS 2006 ACTUAL 

2007 actual is $160,175 higher than 2006 actual for maintenance expense. 

This increase is the result of an increase in depreciation allocated to maintenance accounts from 

the delivery of a $270k double bucket truck and a $236k single bucket truck in 2007. The 

increase is also the result of higher costs in overhead line maintenance and repairs resulting from 

storm damage in 2007 that wasn’t experienced in 2006. 

21 

22 

2007 actual is $98,654 lower than 2006 actual for administrative and general expense.


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 3 



1 

2 

3 

4 

5 

6 

7 

This decrease is mainly the result of various one time consulting projects that were undertaken in 

2006 resulting in an increased expense to the outside services account included within this 

category of expenses versus the average year. For example, Hydro One was contracted to 

perform a cost of service study as prescribed by the OEB, the OUSM group was contracted to 

assist on the assessment of specifications for smart metering communications and performed 

testing on various different meter options, and additional expenses were incurred in 2006 for 

ground environmental testing. 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

2008 ACTUAL VERSUS 2007 ACTUAL 

2008 actual is $101,407 higher than 2007 for operations expenses. 

This increase is mainly the result of an increase in account 5065 due to the metering points 

rebate from Hydro One which was netted against metering expense in 2007 and ended at the end 

of 2007, an amount of $66,213. Other small increases were noted in accounts 5012 – station 

buildings and fixture expense, 5055 – underground distributions transformers, and 5070 – 

customer premises – operation labour as a result of the 3% increase in wages expense between 

2007 and 2008 as per the union contract covering this time period. 

2008 actual is $89,628 lower than 2007 actual for maintenance expenses 

This decrease is the result of a decrease in account 5125, Maintenance of Overhead Conductors 

and Devices. There were higher storm repair and maintenance costs in 2007 than there were in 

2008, resulting in a decrease in this expense year over year. 

2008 actual is $145,234 lower than 2007 actual for community relations expenses. 

This large decrease is a function of the December 2005 guideline which instructed LDC’s to 


versus a variance account. The CDM programs funded through third tranche funding ended in 

September 2007 with the bulk of the spending taking place in 2006 and 2007 and no more to be 

spent in 2008.


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 3 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

2008 actual is $133,937 higher than 2007 actual for administrative and general expenses. 

There are two accounts primarily responsible for the increase in 2008: 5605 Executive salaries 

and Expenses and 56630 Outside Service Employed. 

In account 5605, there was a 3% increase in salary for all members of senior management. 

Professional accounting courses were paid for a member of senior management, which totaled 

$13,000 for the year. In addition, the Festival Hydro Board of Directors was increased from 7 to 

9 members. 

Included in outside services were costs associated with additional environmental testing, 

compared to 2007 when there were strictly monitoring testing. Extra costs were also incurred for 

refilling of tax returns for 2005 and 2006 to take advantage of the SR&ED credits. 

11 

6105- Property & Capital Taxes - $65,305 lower in 2008 than in 2007 

12 

13 

14 

In 2008 an over accrual of property tax from a prior year was adjusted, thereby reducing the 

2008 expense balance. Also the capital tax rate was reduced and the exemption increased in 

2008. 

15 

16 

17 

18 

19 

20 

2009 BRIDGE YEAR VERSUS 2008 ACTUAL 

Billing and Collections – 2009 bridge year is $94,661 higher than 2008 actual. 

The largest contributing item is Bad Debt Expense, which is $71,337 greater in bridge year 2009 

than 2008. A large customer with three locations in Stratford filed for CCAA creditor protection 

in August 2009. Festival Hydro has at risk the unbilled portion, of which 50% has been allowed 

as uncollectible at this time. 

21


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 3 



1 

2010 TEST YEAR VERSUS 2008 BRIDGE YEAR 

2 

There are no variances greater than $50,000. 

3 

4 

SPECIFIC ITEMS TO BE ADDRESSED: 

5 

6 

The following costs have been identified as areas to be specifically addressed in the 2010 Rate 

Application: 

7 

One-time Costs: 

8 

9 

10 

In administration costs, an amount of $25,000 in the 2010 test year has been included to cover 

the costs of transition to International Financial Reporting Standards over four years for a total of 

$100,000. 

11 

Regulatory Costs: 

12 

13 

14 

15 

Festival Hydro has included $40,000 in the 2010 test year to cover additional costs associated 

with the 2010 Cost of Service Rate Application over four years for a total of $160,000. 

Appendix 2-I provides the detailed regulatory cost for Festival Hydro for historic years, 2009 

bridge and 2010 test year. 

16 

Low Income Energy Assistance Program: 

17 

18 

In account 5605, Festival Hydro has included 0.12% of its distribution revenue requirement for 

2010 to fund the LEEP program. The 2009 test year also includes this amount. This represents


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 3 



1 

2 

the amount of funds which will be available to directly assist customers. The administrative costs 

associated with Festival Hydro administering this program are included in collection costs. 

3 

Special purposes charges related to the Green Energy and Green Economy Act, 2009: 

4 

5 

6 

7 

It is anticipated that additional work may be required and costs incurred as a result of the Green 

Energy and Green Economy Act. However, at this time, Festival Hydro understands that such 

work and costs will be the subject of a future proceeding and therefore has not included any such 

costs in this Application. 

8 

Charitable Donations: 

9 

10 

11 

The only donations made by Festival Hydro are a $50 donation to charity upon the death of an 

employee, retiree, their spouse or other immediate family member. The annual amount is 

approximately $300 per year.


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 4 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

26 

27 

CHARGES TO AFFILIATES FOR SERVICES PROVIDED: 

Introduction: 

A summary of charges to affiliates for services provided in 2006 Actual, 2007 Actual and 

2008 Actual together with the projections for the 2009 Bridge Year and 2010 Test Year, 

are shown in the following table on Page 20. 

Festival Hydro currently performs streetlight maintenance and replacements for the City of 

Stratford. In addition, Festival Hydro leases two service bays at the service centre to the 

City of Stratford Water department. Festival Hydro also does the water and sewage billing 

and collection services for the City of Stratford. 

FHI is also involved in billing and collection of Sentinel Light rentals to third party 

customers (64 customers, 83 sentinel light units, as a continuation of the Stratford PUC) on 

behalf of Festival Hydro Services Inc. 

City of Stratford – Water and Sewer Billing & Collection Services 

Festival Hydro Inc. performs water and sewer billing services for the City of Stratford. 

Water and sewer billing is a continuation of services previously performed by the 

Stratford PUC. Festival Hydro Inc. has a services agreement with the City of Stratford. 

In 2009, Festival Hydro Inc. is charging $2.98 per invoice generating $410,126. This 

revenue is shown in general ledger account 4375. From 2010 to 2014 the monthly cost 

per invoice will be increased by the previous year’s May 1st, Ontario Energy Board 

allowed increase of Gross Domestic Product Implicit Price Index. Revenue for the test 

year 2010 totals $420,485. The signed agreement is attached in Appendix B of this 

exhibit. 

There is a cost allocation/shared services of Customer Service Supervision, Meter reading, 

Customer Billing, Collecting and Miscellaneous Customer Accounts. These costs are 

shared via a 35% cost allocation based on the principal of the number of invoices produced.


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 4 



1 

2 

3 

4 

5 

6 

Although the actual percentage ratio is slightly higher than the charged amount, the 35% 

allocation is based on streamlining/simplifying the total costs within functional areas 

covering electric, water and sewage activities. These costs are shown in account in general 

ledger 4380.

1 

2 

3 

Water and 

Sewer Billing 

Revenue – g/l 

4375 

Expenses 

resulting from 

35% B&C 

allocation – g/l 

4380 

Allocation of 

B&C costs 

Electric bills 

produced 

Annual Water 

bills produced 

Table 3 

Water and Sewage Billings and Collection Costs 


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 4 



2006 actual 2007 actual 2008 actual 2009 bridge 2010 test year 

year 

$393,055 $394,215 $397,814 $410,126 $420,485 

$322,788 $317,816 $340,955 $347,446 $357,869 

35% (actual 35% (actual 35% (actual 35% (actual 35% (actual 

ratio – 36.6%) ratio – 36.6%) ratio – 36.6%) ratio – 36.7%) ratio – 36.5%) 

19,097 19,326 19,476 19,513 19,719 

11,103 11,051 11,238 11,325 11,350 

Water/Sewage $11,867 $12,426 $10,763 $11,087 $11,419 

share 

supervision; 

Water/Sewage $60,389 $58,963 $56,167 $54,114 $55,738 

share meter 

reading 

Water/Sewage $86,736 $79,764 $76,746 $79,049 $81,421 

share customer 

billing 

Water/Sewage $73,037 $72,816 $73,114 $75,307 $77,566 

share 

collecting 

Water/Sewage $90,759 $95,847 $124,164 $127,889 $131,725 

share customer 

accounts 

Total $322,788 $317,816 $340,955 $347,446 $357,869 

4 

5


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 4 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

26 

City of Stratford – Leasing Service Centre Bays 

The City of Stratford leases two bays for the use of their water service employees and vehicles. 

The City continued to utilize these two bays similar to their use when operating under the 

Stratford PUC. The rate being charged is $5.93 per square foot, or $2,535.00 per 

month/$30,420.00 per year. Festival Hydro Inc. has a lease agreement with the City of Stratford 

as per the attached schedule. The lease has an annual inflationary increase as per Rent Control 

Guidelines for the prior year. The market price for service bay space is competitive to other 

vacant bays being offered within our service area. Festival Hydro is currently renting a building 

to serve as our Festival Hydro service centre in the Municipality of Huron East (5,984 square 

feet) from the Municipality of Huron East at a rate of $2.17 per square foot, or $1,081 per 

month/$12,972.00 per year. 

These lease revenues mitigate higher rates to FHI customers by reducing equivalent revenue 

requirements. If the City relocated the water employees to another location, FHI would not 

pursue leasing this space to another tenant. This space would be used for FHI vehicle and 

inventory storage. 

The revenues are shown in general ledger account 4210. 

Rental 

Revenue 

2006 

actual 

2007 

actual 

2008 

actual 

2009 

bridge 

year 

2010 

test year 

$30,000 $30,000 $30,000 $30,420 $30,845 

City of Stratford – Street Light Maintenance Services 

Festival Hydro Inc. performs street lighting services for the City of Stratford. Festival Hydro 

Inc. has been performing these services as a continuation of services previously offered by the 

Stratford PUC. We charge the City for direct costs we incur for street light maintenance and


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 4 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

replacements. The direct costs include actual costs including labour, burdens, stores handling 

burden, along with vehicle costs. 

Below is a summary of our charges to the City of Stratford for street lighting services performed. 

The bridge and test years are based on an average of the prior three years. 

2006 

actual 

2007 

actual 

2008 

actual 

2009 

bridge 

year 

2010 test 

year 

Labour/Burden $82,359 $113,137 $74,022 $90,500 $93,500 

Vehicles $25,157 $31,345 $19,993 $25,900 $26,000 

Stock Burden $10,857 $14,722 $9,716 $12,067 $11,183 

Total $118,373 $159,204 $103,731 $128,467 $130,683 

In 2007 FHI had more street lighting revenue from the City of Stratford due to the labour, 

burdens and vehicle costs for the replacement of ground fault receptacles on street light poles in 

the complete downtown core. In 2007, Festival Hydro charged for the labour, burdens and 

vehicle costs to replace seven street light fixtures and poles on behalf of the City. 

Festival Hydro Services Inc. 

Festival Hydro Inc. provides general administrative, accounting, billing, collection and financial 

statements services to Festival Hydro Services Inc. Festival Hydro Inc. has been performing 

these services for Festival Hydro Services Inc. as a continuation of services previously offered 

by the Stratford PUC. We charge Festival Hydro Services Inc. a cost equivalent to the rate of 

5% of the revenues generated by Festival Hydro Services Inc. These common costs include 

general administrative and accounting services that are not separable or identifiable. In 2007, we 

had an amendment to our agreement to include an additional amount of $1.00 per bill charged 

for billing and collection costs. In addition, direct costs including labour, burdens and vehicle 

costs are charged to Festival Hydro Services Inc.


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 4 



1 

2 

3 

4 

5 

6 

7 

8 

Festival Hydro Services Inc. sold their water heaters to Consumers Water Heater Income Fund in 

October 2007, but continued billing on behalf of Consumers until March 2009. FHSI still leases 

sentinel lights (83 units in total 64 customers) and rent dark fibre cable (9 customers). 

Administrative 

and Accounting 

Services 

Material 

Handling Charge 

Billing & 

Collecting 

Subtotal of 

Revenue (4375) 

Direct 

Labour/Burden 

Costs 

2006 

actual 

2007 

actual 

2008 

actual 

2009 

bridge 

year 

2010 test 

year 

$30,561 $33,047 $35,449 $24,000 $20,000 

$14,795 $7,822 - - - 

$0.00 $14,328 $37,538 $8,700 $1,200 

$45,356 $55,197 $72,987 $32,700 $21,200 

$18,093 $35,435 $52,097 $35,000 $36,000 

Vehicle $1,374 $2,792 $6,451 $3,500 $4,000 

Total $64,823 $93,423 $134,465 $71,200 $61,200 

The 5% administration and accounting services is well below the actual relative percentage of 

sales. 

2006 actual 2007 actual 2008 actual 2009 bridge 

year 

2010 test 

year 

9 

10 

FHI Gross 

Sales 

FHSI 

Sales 

Combined 

Gross 

Sales 

Percentage 

of FHSI 

Sales to 

combined 

sales 

$53,565,560 $53,263,091 $53,128,224 $53,000,000 $53,000,000 

$266,245 $401,058 $323,597 $400,000 $400,000 

$53,831,805 $54,664,149 $53,451,821 $53,400,000 $53,400,000 

.49% .73% .61% .75% .75%


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 4 



1 

Summary of Charges to Affiliates for Services Provided: 

2 

Name of Company 

From 



Appendix 2 ‐ M 

Shared Services/Corporate Cost Allocation 

Year: 2006 

To Service Offered Pricing Methodology Price for the 

Service $ 

Cost for the 

Service $ 

% Allocation 

Water and Sewer Billing & Collection 

Services Cost Plus Method $ 393,055.00 $ 322,788.00 35% 

Festival Hydro Inc. City of Stratford Leasing ‐ Two Service Bays Competitive Price $ 30,000.00 

Festival Hydro Inc. City of Stratford Street Light Maintenance Services Direct Allocation $ 118,373.00 $ 118,373.00 

3 

4 



Administration Services for Fibre Optic ‐ 

Sentinel light ‐water heater rentals Percentage of Sales $ 64,823.00 

5% of sales 

5 


From 




Year: 2007 


Service $ 


Service $ 

% Allocation 






6 

7 



Administration Services for Fibre Optic 

‐ Sentinel light ‐water heater rentals Percentage of Sales $ 93,423.00 


plus a $1.00 

per bill 

effective 

September 1, 

2007 

8


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 4 




From 




Year: 2008 


Service $ 


Service $ 

% Allocation 






1 

2 




‐ Sentinel light rental Percentage of Sales $ 134,465.00 


plus a $1.00 

per bill. 

3 


From 




Year: 2009 


Service $ 


Service $ 

% Allocation 






4 

5 






plus a $1.00 

per bill. 

6


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 4 




From 




Year: 2010 


Service $ 


Service $ 

% Allocation 






1 

2 






plus a $1.00 

per bill.


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 4 

Appendix B 


APPENDIX B 

AFFILIATE SERVICE AGREEMENTS


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 4 

Appendix B 




EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 4 

Appendix B 




EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 4 

Appendix B 




EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 4 

Appendix B 




EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 4 

Appendix B 




EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 4 

Appendix B 




EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 4 

Appendix B 




EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 4 

Appendix B 




EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 4 

Appendix B 




EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 4 

Appendix B 




EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 4 

Appendix B 




EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 4 

Appendix B 




EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 4 

Appendix B 




EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 4 

Appendix B 




EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 5 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

26 

27 

28 

29 

30 

31 

32 

33 

34 

PURCHASE OF PRODUCTS AND SERVICES FROM NON-AFFILIATES 

Like other distributors, Festival Hydro purchases many services and products from third parties. 

The FHI purchase policy is as follows: 

The purchasing of goods and services fall into one of four categories: 

Tenders – are used for non-stock items or service contracts valued at $30,000 or more 1 . 

A Tender can only be issued by the President, Vice-President, or Secretary-Treasurer. 

Tender packages will typically be sent directly to at least three (3) vendors known to 

specialize in the item or service, however, a Request for Tender may be advertised if 

there are an insufficient number of known vendors. A period of at least two (2) weeks is 

required for the vendors to review the tender package and respond. Receipt of tenders 

must be in sealed envelopes clearly marked as to the contents. Tenders will be opened at 

the time of closing by the President, Vice-President, Secretary-Treasurer, or designate. 

Unless otherwise specified by the Board of Directors, bidders are not permitted to attend 

the tender opening. The tenders will be evaluated by one or more suitable employees, 

and a recommendation prepared for approval by the Board of Directors. For specialized 

goods or services, it is permitted to have the tenders evaluated by an external third party 

such as an engineering consultant. Following award of the tender by the Board of 

Directors, the successful bidder will be immediately notified by the appropriate manager, 

and a purchase order initiated via a material requisition. The remaining bidders will be 

notified in writing of the name of the successful bidder and the award price – if 

appropriate. 

Quotations – are used for purchases above $2500 that do not fit the tender category 2 . 

Quotations may be issued by any Manager. The Request for Quotation package will 

typically be sent to at least three (3) vendors known to specialize in the item or service; 

however, there are some items and services with fewer than three (3) vendors. A period 

of two (2) weeks for evaluation and response is recommended for items that are usually 

made to order, or for service contracts such as line construction. Shorter periods are 

acceptable for “off the shelf” items or routine services. Quotations are normally accepted 

in hardcopy, fax, or email format but their contents must be kept confidential until the 

closing date. Sealed quotations are recommended for purchases above $25,000. The 

quotations will be reviewed by the appropriate employee(s) after the closing date, and a 

1 Exceptions to the Tender category are payments relating to Income Tax, Employment Insurance, OHIP, OMERS, 

Employment Benefits, GST, IESO (monthly invoices), OEFC (debt retirement), Hydro One (Transmission Charges), 

Energy Retailers, Insurance renewals. 

2 Exceptions to the Quotation category include charges such as utility bills, postage, training, accommodations, 

company meals, customer requests for contractor of choice, contractor on site as part of a related contract or 

quotation, software maintenance contracts, transformer repairs, scrap transformers, and situations of dire emergency 

(i.e. storm trouble) when time is of essence. Festival Hydro Inc. will submit joint tenders with the City of Stratford 

for items such as office supplies, banking arrangements and auditing services when joint needs are required.


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 5 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

26 

27 

28 

29 

30 

31 

32 

recommendation made to the appropriate manager. Approval by the President is required 

for quotes valued above $50,000 for stock items, and above $10,000 for non-stock items 

or service contracts. Approval by the Vice-President or Secretary-Treasurer is required 

for quotes valued above $10,000 for stock items, and above $2,500 for non-stock items or 

service contracts. Approval by the appropriate Manager is required for quotes above 

$2,500 for stock items. Once approval has been obtained, the successful bidder will be 

immediately notified by the appropriate manager, and a purchase order initiated via a 

material requisition. The remaining bidders will be notified in writing of the name of the 

successful bidder and the award price – if appropriate. For routine purchases of items or 

services such as office supplies, computer support, low value stock items, safety 

equipment, cleaning supplies, lawn restoration, vacuum excavation, vehicle supplies and 

vehicle servicing, it is acceptable to request pricing once, then use the same low bidder(s) 

for a fixed period of time, generally not exceeding two (2) years. For routine purchases 

of higher value stock items, formal supplier alliances may be formed with the approval of 

the President. 

Standard Purchases – are purchases between $125 and $2500, and are accomplished by 

issuing a purchase order via a material requisition with approval by manager. 

Local Purchase Orders – are used for purchases under $125. These may be issued by any 

employee but require the approval of a Manager (with the exception of the Mechanic). 

Recurring Invoices – are monthly fees typically for services that have been awarded via a 

quotation or a tender. These invoices are to be approved for payment by the appropriate 

Manager. Signing Authority may be delegated if necessary to avoid delays in the purchasing 

process. This delegation should be documented in a memo or email to the affected parties. 

The three tables below illustrate Festival Hydro’s expenditures on purchased products and 

services in 2006 (Table 4), in 2007 (Table 5), and in 2008 (Table 6). The tables disclose 

expenditures for suppliers where individual invoices were greater than $50,000 or where total 

purchases were greater than $50,000 from an individual supplier in 2006, 2007 or 2008.


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 5 



1 

2 

3 

4 

Table 4 

Individual Invoices over $50,000 in 2006 

Name Activity Priced By Total 

Municipal Electrical Association Insurance 54,332 

Noramco Wire & Cable Wire & Cable RFQ 72,454 

RJ Burnside Environmental services Tender 53,052 

S&C Electric Canada Ltd. Automated switches & radios Tender 86,788 

Siemens VA Tech Tranformateurs Transformers RFQ 84,391 

Steve Smith Construction Corporation Conduit installation Contract 60,717 

Vendors with Total Invoices over $50,000 in 2006 


ABB Inc. Transformers RFQ 173,147 

CES Transformers Transformers RFQ 76,887 

Dowler‐Karn Limited Fuel RFQ 55,974 

Erie Thames Services Wholesale metering points maintenance Tender 59,117 

Grafton Utility Supply Ltd. Electrical hardware RFQ 207,344 

Mearie Management Inc. Employee benefits 313,595 

Municipal Electrical Assocation Insurance 54,332 

Noramco Wire & Cable Wire & cable RFQ 171,857 

Ontario Municipal Employees Pension Legislation 431,745 

RJ Burnside Environmental Services RFQ 130,740 

RDS Utility Services Meter reading services Tender 162,994 

S&C Electric Canada Ltd. Automated switches & radios Tender 90,542 

Siemens VA Tech Tranformateurs Transformers RFQ 105,652 

Steve Smith Construction Corporation Conduit Installation Contract 60,717 

Stress/Crete Limited Concrete poles Contract 213,231 

Utilismart Corporation Settlement services Tender 53,760 

Westburne Ruddy Electric Electrical hardware RFQ 122,796


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 5 



1 

2 

3 

4 

5 

Table 5 




Altec Industries Ltd. New vehicle purchase Tender 268,380 

Canadian Electric Services Transformers RFQ 51,543 

Flynn Canada Ltd. Roof replacement Tender 110,664 

Municipal Electric Association Insurance 55,503 




Altec Industries Ltd. New vehicle purchase Tender 267,118 

CAM Tran Co. Ltd. Transformer maintenance Tender 58,905 

Canadian Electric Services Transformers RFQ 51,543 


Dowler‐Karn Limited Fuel RFQ 70,937 


Flynn Canada Ltd. Roof replacement Tender 136,332 

Grafton Utility Supply Ltd. Electrical hardware RFQ 255,535 

Ideal Supply Company Limited Vehicle/building maintenance RFQ 153,232 


Moloney Electric Transformers RFQ 95,318 


Nedco Electrical hardware RFQ 70,586 



RJ Burnside Environmental Services Tender 62,420 



Technology Alliance Networks Telephone system RFQ 63,522 

Utilismart Corporation Settlement services Tender 52,953


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 5 



1 

2 

3 

4 

5 

Table 6 



Kenworth Kitchener Ltd. New vehicle purchase Tender 50,172 


Posi‐Plus Technologies Inc. New vehicle purchase Tender 226,556 

Pride Bodies Ltd. New vehicle purchase Tender 52,830 

S&C Electric Canada Ltd. Automated Switches & radios RFQ 75,089 

Timberland Equipment Limited New equipment purchased Tender 136,111 



Amec Earth & Environmental Environmental Services RFQ 81,143 

Bel volt Saltes Ltd. Electrical hardware RFQ 64,802 

Carte International Inc. Transformer maintenance Tender 52,965 



HD Supply Canada Inc. Electrical hardware & transformers RFQ 314,790 

Kenworth Kitchener Limited New vehicle purchase Tender 50,172 

KPMG Professional services Tender 50,594 


Moloney Electric Transformers RFQ 54,528 




Posi‐Plus Technologies Inc. New vehicle purchase Tender 227,716 

Pride Bodies Ltd. New vehicle purchase Tender 52,830 


S&C Electric Canada Ltd. Automated Switches & radios RFQ 290,049 


Suncor Energy Products Inc. Fuel RFQ 57,572 

Timberland Equipment Limited New equipment purchased Tender 136,182 

Utilismart Corporation Settlement services Tender 52,454 

Westburn Ruddy Electric Electrical Hardware RFQ 198,783


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 6 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

EMPLOYEE COMPENSATION, INCENTIVE PLAN EXPENSES, PENSION EXPENSE 

AND POST RETIREMENT BENEFITS: 

Overview: 

Festival Hydro is facing the same challenges as other LDCs throughout the electricity 

distribution sector. In the next five years, 18.6% of Festival Hydro’s employees will be eligible 

for retirement, and an additional 32.6% will be eligible within 10 years. Festival Hydro’s total 

employee average age is 46.4 years, with a skilled trade average age at 42.8 years. 

The challenge Festival Hydro faces is effectively bridging the gap in maintaining sufficient talent 

to meet the current needs of the utility while planning for the ‘new’ future. Table 6 below 

illustrates Festival Hydro’s current employee demographics by employee type. 

Table 6 

Festival Hydro Employee Demographics 

Unionized Workforce 

13 

Department 

Avg. Age 

Avg. Length 

of Service 

Lineman 44.1 18.9 

Apprentice Linemen 23.0 0.5 

Fleet Mechanics 39.0 8.0 

Meter 42.0 22.0 

Stores 49.0 18.0 

Locates/Maintenance 45.5 15.0 

Totals 42.9 17.1 

Salaried (Non-Union) Workforce 

Avg. Length 

Dept. 

Avg. Age of Service 

Executive 47.0 12.0 

Engineering 49.0 24.3 

Operations 50.0 26.0 

Customer Service/Billing 54.0 24.0 

IT 44.0 7.0 

Total 49.2 21.7


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 6 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

Hourly (Non-Union) Workforce 

Avg. Length 

Dept. 

Avg. Age of Service 

Customer Service 48.4 17.4 

Cashier/General Admin 60.0 19.0 

Billing 53.5 24.0 

Accounting 51.0 23.0 

Engineering 48.0 24.0 

Totals 50.8 20.4 

Effective workforce planning will be a significant initiative going forward. Festival Hydro 

recognizes the need to develop a strategy to replace linepersons as a result of retirements in the 

upcoming years and an aging workforce. As a result of the required four year training program, 

these apprentice positions must be introduced on a timely basis. Festival Hydro recently hired 

two apprentice linepersons in an attempt to maintain employee line personnel skill sets. As 

pointed out in the above tables, the average age of the two new line apprentices is 23 years of 

age. No additional apprentices have been included in each of the 2009 Bridge Year and 2010 

Test Year. 

Change in Workforce Year over Year: 

Table 7 in Exhibit 4, Tab 2, Schedule 6 shows Festival Hydro’s FTE headcount for 2006 Actual 

(45), 2008 Actual (44), 2009 Bridge Year (44), and 2010 Test Year (45). Festival Hydro has 

been managing more assets and taking on further initiatives with basically the same labour force 

it had in at the last Board approval in 2006. 

2007 Actual versus 2006 Actual 

The FTE employees decreased from 45 to 44 from 2006 to 2007. This decrease is the result of a 

retirement. 

19


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 6 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

2008 Actual versus 2007 Actual 

The FTE employees remained the same at 44 in 2008. 

2009 Bridge Year versus 2008 Actual 

The FTE remained the same in 2009 at 44 employees. 

2010 Test Year versus 2009 Bridge Year 

The FTE employees will increase from 44 to 45 in 2010. Festival Hydro is in the process of 

hiring an Energy Conservation Officer to aid in the implementation of various conservation 

programs. CDM will play a key part in meeting Ontario’s electricity requirements in the future 

along with the implementation of smart meters. Currently, the Billing & Collections Manager is 

responsible for coordinating Conservation and Demand Activities at Festival Hydro. The 

importance of Conservation and Demand and the increased work load involved require the 

dedication of an additional management position. This will be a shared position with the City of 

Stratford, with the City of Stratford paying 40% of the salary and benefits. 

Festival Hydro’s Compensation System 

Festival Hydro’s pay rates are competitive with other LDCs in the Southwestern Region. 

Union 

Festival Hydro’s unionized staff is represented by the IBEW Local 636. A formal set of contract 

negotiations was recently conducted and resulted in a new three year collective agreement 

effective May 1, 2008. The settlement included annual wage increases of 3% per year beginning 

in 2009 and improvements to the benefits package. 

Non Union/Management/Executive Management 

Wage increases reflect a 3% increase in the test year.


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 6 



1 

2 

3 

4 

5 

6 

7 

8 

Benefits 

A comprehensive and competitive benefits package exists which includes medical insurance, life 

insurance, vacation and a company-sponsored retirement plan. The plans are designed to address 

the health and welfare needs of the employee population with similar plans for union, non union, 

and management employees. 

Employee Compensation and Benefits: 

Festival Hydro’s employee complement, compensation and benefits are set out in Table 7, 

below. 

9


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 6 



1 

2 

3 

4 

Table 7 

Festival Hydro – Employee Complement and Compensation 

Last Historical Year Bridge Test 

Rebasing (Bridge Year‐1) Year Year 

Year 

2006 2008 2009 2010 

Number of Employee (FTEs including Part‐time) 

Executive 3 3 3 3 

Management 7 6 7 8 

Non‐Union 14 14 13 13 

Union 21 21 21 21 

Total 45 44 44 45 

Number of Part‐Time Employees 



Non‐Union 1 0 0 0 

Union 0 0 0 0 

Total 1 0 0 0 

Total Salary and Wages 

Executive 313,236 346,858 357,264 367,981 

Management 486,253 456,406 470,098 504,201 

Non‐Union 646,327 675,237 695,494 716,359 

Union 1,336,445 1,415,345 1,457,805 1,501,540 

Total 2,782,261 2,893,845 2,980,661 3,090,080 

Total Benefits 

Executive 43,580 46,864 51,449 52,992 

Management 70,020 67,449 81,973 100,865 

Non‐Union 102,529 104,006 93,237 96,034 

Union 197,346 206,037 211,265 217,603 

Total 413,475 424,355 437,924 467,494 

Total Compensation (Salary, Wages, & Benefits) 

Executive 356,817 393,722 408,712 420,973 

Management 556,273 523,854 552,071 605,065 

Non‐Union 748,856 779,243 788,731 812,393 

Union 1,533,791 1,621,382 1,669,071 1,719,143 

Total 3,195,736 3,318,200 3,418,585 3,557,575 

5


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 6 



1 

Last Historical Year Bridge Test 

Rebasing (Bridge Year‐1) Year Year 

Year 

2006 2008 2009 2010 

Compensation ‐ Average Yearly Base Wages 

Executive 104,412 115,619 119,088 122,660 

Management 69,267 76,068 67,157 63,025 

Non‐Union 46,166 48,231 53,500 55,105 

Union 62,832 68,473 69,419 71,502 

Total 282,677 308,391 309,164 312,292 

Compensation ‐ Average Yearly Overtime 

Executive 0 157 162 167 

Management 169 1,956 2,464 2,538 

Non‐Union 958 1,296 1,412 1,454 

Union 5,496 4,930 5,599 5,767 

Total 6,623 8,339 9,636 9,925 

Compensation ‐ Average Yearly Incentive pay 



Non‐Union 0 0 0 0 

Union 0 0 0 0 

Total 0 0 0 0 

Compensation ‐ Average Yearly Benefits 

Executive 14,527 15,621 17,150 17,664 

Management 9,974 11,241 11,710 12,608 

Non‐Union 7,324 7,429 7,172 7,387 

Union 9,278 9,968 10,060 10,362 

Total 41,103 44,260 46,092 48,021 

2 

3 

Total Compensation 3,195,736 3,318,200 3,418,585 3,557,575 

Total Compensation Charged to OM & A 2,726,655 1,597,175 2,427,195 2,525,878 

Total Compensation Capitalized 469,081 1,721,025 991,390 1,031,697 

4


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 6 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

OMERS Pension Expense and Post Retiree Benefits: 

OMERS Pension Expense: 

Festival Hydro’s employees are members of the Ontario Municipal Employees Retirement 

System ("OMERS"). Accordingly, Festival Hydro has provided the OMERS pension premium 

information for 2006 Actual, 2007 Actual, 2008 Actual, 2009 Bridge Year, and the 2010 Test 

Year in Table 8 below. OMERS pension premiums from January 1, 2006 to April 30, 2006 were 

deferred to account 1508 for recovery at a later date have been recorded as an adjustment. 

Table 8 

FHI 

Pension Premium Information 

2006 2007 2008 2009 2010 

Premiums Paid 208,551 197,682 214,781 221,224 227,861 

Adjustments 0 0 0 0 0 

Pension Expense 208,551 197,682 214,781 221,224 227,861 

Post-Retirement Benefits - Liability: 

Festival Hydro has provided post-retirement benefits accounting information as required and has 

included the change in Post-Retirement expense for 2006 Actual, 2007 Actual, 2008 Actual, 

2009 Bridge Year, and 2010 Test Year, in Table 9 below. A detailed actuarial report is 

completed every three years by an outside actuarial company. 

16


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 6 



1 

2 

3 

4 

5 

6 

7 

Post-Retirement Benefits - Premiums: 

Festival Hydro pays certain health, dental, and life insurance benefits on behalf of its retired 

employees. Actual premiums paid for 2006, 2007 and 2008 are included below as well as 

projections for the 2009 Bridge Year, and 2010 Test Year, are shown in Table 9 below. 

Table 9 

FHI 

Post Retirement Benefit Information 

2006 2007 2008 2009 2010 

Premiums Paid 54,766 52,900 63,374 64,922 67,550 

Change in liability account 34,517 39,587 (28,052) 3,375 4,397 

Post retirement benefit expense 89,283 92,487 35,322 68,297 71,947


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 7 



1 

2 

DEPRECIATION, AMORTIZATION AND DEPLETION: 

Amortization on capital assets is calculated as follows: 

3 

4 

5 

6 

 

Festival Hydro uses the pooling of assets for all distribution. Vehicles are amortized on an 

individual basis. Amortization is calculated on a straight line basis over a number of years as 

suggested by OEB depreciation guidelines. A full year’s amortization is taken on capital 

additions during the year of purchase. No depreciation is taken the year of disposal. 

7 

8 

 

Depreciation rates are in line with rates set out in the APH. A summary of those rates are as 

follows: 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

Buildings 

Substations 

Buildings & Fixtures 

Poles, Towers, Fixtures 

Overhead Conductors 

Underground Conduit 

Metering 

Furniture & Equipment 

Computer Hardware/Software 

Leasehold improvements 

Automotive Equipment 

Contributed Capital 

50 years 

30 years 

30 years 

25 years 

25 years 

25 years 

25 years 

10 years 

5 years 

5 years 

5 or 8 years 

25 years 

22 

23 

Details of Festival Hydro’s depreciation by account number are provided in the Fixed Asset 

Continuity Schedule in Exhibit 2, Tab 2, Schedule 1. The tables below highlight depreciation


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 7 



1 

2 

calculations by account for historical, bridge, and test years. The small differences indicated in 

these tables are the result of rounding errors in the calculations.


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 7 

Appendix C 


APPENDIX C 

DEPRECIATION CALCULATIONS BY ACCOUNT


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 7 

Appendix C 



1 

Depreciation Expense 

2006 Actual 

Opening Balance Less: Fully Depreciated Net for Depreciation Net Additions Total Depreciable Years Depreciation Expense 

Account Description (a) (b) (c) = (a) - (b) (d) (e) = (c) + (d) (f) (g) = (e)/(f) 

1805 Land - Substations 340,120 0 340,120 0 340,120 N/A 0 

1808 Buildings - Substations 1,697,947 37,250 1,660,697 0 1,660,697 50 33,214 

1810 Leasehold Improvements 0 0 0 0 0 0 

1815 Transformer Station Equipment > 50 kV 0 0 0 0 0 0 

1820 Substation Equipment 1,745,896 602,475 1,143,421 0 1,143,421 25 45,737 

1825 Storage Battery Equipment 0 0 0 0 0 0 

1830 Poles, Towers & Fixtures 7,198,573 420,425 6,778,148 668,595 7,446,742 25 297,870 

1835 OH Conductors & Devices 8,384,480 439,650 7,944,830 597,468 8,542,298 25 341,692 

1840 UG Conduit 5,388,348 435,650 4,952,698 125,318 5,078,016 25 203,121 

1845 UG Conductors & Devices 13,845,406 1,086,575 12,758,831 276,609 13,035,439 25 521,418 

1850 Line Transformers 11,673,544 1,768,625 9,904,919 600,740 10,505,659 25 420,226 

1855 Services (OH & UG) 3,893,452 265,650 3,627,802 242,015 3,869,817 25 154,793 

1860 Meters 3,228,513 687,000 2,541,513 29,069 2,570,582 25 102,823 

1861 Smart Meters 0 0 0 0 0 

1905 Land 0 0 0 0 0 

1906 Land Rights 0 0 0 0 0 

1908 Buildings & Fixtures 135,382 0 135,382 50,976 186,359 30 6,212 

1910 Leasehold Improvements 21,798 21,798 0 0 0 5 0 

1915 Office Furniture & Equipment 330,118 258,920 71,198 1,674 72,872 10 7,287 

1920 Computer - Hardware 739,479 572,700 166,779 27,255 194,034 5 38,807 



1925 Computer - Software 406,575 314,440 92,135 11,097 103,231 5 20,646 

1930 Transportation Equipment (small) 2,241,192 1,651,695 589,497 (76,918) 512,579 5 102,516 

1935 Stores Equipment 36,199 36,199 0 0 0 10 0 

1940 Tools, Shop & Garage Equipment 589,564 318,640 270,924 23,803 294,727 10 29,473 

1945 Measurement & Testing Equipment 13,413 0 13,413 0 13,413 10 1,341 


1955 Communications Equipment 106,166 54,542 51,624 0 51,624 10 5,162 

1960 Miscellaneous Equipment 0 0 0 0 0 10 0 


1970 Load Management controls 76,841 0 76,841 0 76,841 10 7,684 

1975 Load Management Controls Utility Premises 22,056 0 22,056 105,646 127,702 10 12,770 

1980 System Supervisory Equipment 204,333 0 204,333 2,091 206,424 10 20,642 



1995 Contributions & Grants (2,006,603) (325) (2,006,278) (404,686) (2,410,965) 25 (96,439) 

Total 60,312,790 8,971,909 51,340,881 2,280,751 53,621,633 2,276,995 

Per continuity 2,278,628 

Difference 1,633


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 7 

Appendix C 



1 


2007 Actual 

Opening Balance Less: Fully Depreciated Net for Depreciation Net Additions Total Depreciation Years Depreciation Expense 


1805 Land - Substations 340,120 0 340,120 (5,321) 334,798 N/A 0 

1808 Buildings - Substations 1,697,947 37,250 1,660,697 12,408 1,673,105 50 33,462 

1810 Leasehold Improvements 0 0 0 0 0 0 0 

1815 Transformer Station Equipment > 50 kV 0 0 0 0 0 0 0 


1825 Storage Battery Equipment 0 0 0 0 0 0 0 



1840 UG Conduit 5,513,666 435,650 5,078,016 152,695 5,230,711 25 209,228 



1855 Services (OH & UG) 4,135,467 292,425 3,843,042 240,533 4,083,575 25 163,343 

1860 Meters 3,257,582 687,000 2,570,582 86,369 2,656,951 25 106,278 

1861 Smart Meters 0 0 0 0 0 0 0 

1905 Land 0 0 0 0 0 0 0 

1906 Land Rights 0 0 0 0 0 0 0 

1908 Buildings & Fixtures 186,359 17,040 169,319 151,353 320,672 30 10,689 


1915 Office Furniture & Equipment 331,792 278,350 53,442 0 53,442 10 5,344 


1921 Computer - Hardware post Mar 22/04 0 0 0 0 0 0 0 



1930 Transportation Equipment 2,164,274 1,674,065 490,209 91,927 582,136 5 116,427 




1950 Power operated Equipment 0 0 0 0 0 0 0 


1960 Miscellaneous Equipment 0 0 0 0 0 10 0 

1965 Water Heater Rental Units 0 0 0 0 0 0 0 

1970 Load Management controls 76,841 7,440 69,401 40,576 109,977 10 10,998 

1975 Load Management Controls Utility Premises 127,702 0 127,702 0 127,702 10 12,770 


1985 Sentinel Lighting Rental Units 0 0 0 0 0 0 0 

1996 Hydro One S/S Contribution 0 0 0 0 0 0 0 

1995 Contributions & Grants (2,411,290) (57,475) (2,353,815) (755,127) (3,108,941) 25 (124,358) 

Total 62,593,542 9,557,794 53,035,748 2,604,851 55,640,599 2,364,079 

Per 2007 Continuity 2,365,262 

Difference 1,184


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 7 

Appendix C 



1 


2008 Actual 



1805 Land - Substations 334,798 0 334,798 4,525 339,323 N/A 0 

1808 Buildings - Substations 1,710,355 37,250 1,673,105 (13,849) 1,659,256 50 33,185 

1810 Leasehold Improvements 0 0 0 0 0 0 0 

1815 Transformer Station Equipment > 50 kV 0 0 0 0 0 0 0 


1825 Storage Battery Equipment 0 0 0 0 0 0 0 


1835 OH Conductors & Devices 9,438,738 807,425 8,631,313 1,882,567 10,513,880 25 420,555 

1840 UG Conduit 5,666,361 565,275 5,101,086 353,091 5,454,177 25 218,167 



1855 Services (OH & UG) 4,376,000 300,750 4,075,250 216,274 4,291,525 25 171,661 

1860 Meters 3,343,951 687,000 2,656,951 85,876 2,742,828 25 109,713 

1861 Smart Meters 0 0 0 0 0 0 0 

1905 Land 0 0 0 0 0 0 0 

1906 Land Rights 0 0 0 0 0 0 0 








1930 Transportation Equipment 2,256,201 1,674,065 582,136 306,069 888,205 5 177,641 




1950 Power operated Equipment 0 0 0 0 0 0 0 


1960 Miscellaneous Equipment 0 0 0 7,842 7,842 10 784 

1965 Water Heater Rental Units 0 0 0 0 0 0 0 

1970 Load Management controls 117,417 7,440 109,977 0 109,977 10 10,998 



1985 Sentinel Lighting Rental Units 0 0 0 0 0 0 0 

1996 Hydro One S/S Contribution 0 0 0 0 0 0 0 


Total 65,198,393 10,400,784 54,797,609 4,868,851 59,666,460 415 2,577,869 

2,579,897 

2,028


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 7 

Appendix C 



1 


2009 Actual 



1805 Land - Substations 339,323 0 339,323 0 339,323 N/A 







1835 OH Conductors & Devices 11,321,305 871,250 10,450,055 1,068,000 11,518,055 25 460,722 

1840 UG Conduit 6,019,452 565,275 5,454,177 203,000 5,657,177 25 226,287 



1855 Services (OH & UG) 4,592,275 314,250 4,278,025 228,000 4,506,025 25 180,241 

1860 Meters 3,429,828 687,000 2,742,828 75,000 2,817,828 25 112,713 

1861 Smart Meters 0 0 0 0 0 0 

1905 Land 0 0 0 0 0 0 

1906 Land Rights 0 0 0 0 0 0 





1921 Computer - Hardware post Mar 22/04 0 0 0 0 0 0 



1930 Transportation Equipment 2,562,270 1,802,300 759,970 355,000 1,114,970 5 222,994 




1950 Power operated Equipment 0 0 0 0 0 0 


1960 Miscellaneous Equipment 7,842 0 7,842 0 7,842 10 784 

1965 Water Heater Rental Units 0 0 0 0 0 0 




1985 Sentinel Lighting Rental Units 0 0 0 0 0 0 



Total 70,067,244 10,848,889 59,218,355 3,402,000 62,620,355 415 2,735,941 

2,735,858 

(83)


EB-2009-0263 

Exhibit 4 

Tab 2 

Schedule 7 

Appendix C 



1 

2 


2010 Actual 



1805 Land - Substations 339,323 0 339,323 0 339,323 N/A 








1840 UG Conduit 6,222,452 649,275 5,573,177 259,500 5,832,677 25 233,307 



1855 Services (OH & UG) 4,820,275 409,450 4,410,825 220,000 4,630,825 25 185,233 

1860 Meters 3,504,828 693,050 2,811,778 20,000 2,831,778 25 113,271 

1861 Smart Meters 0 0 0 0 0 0 

1905 Land 0 0 0 0 0 0 

1906 Land Rights 0 0 0 0 0 0 








1930 Transportation Equipment 2,917,270 1,943,090 974,180 300,000 1,274,180 5 254,836 




1950 Power operated Equipment 0 0 0 0 0 0 


1960 Miscellaneous Equipment 7,842 0 7,842 0 7,842 10 784 

1965 Water Heater Rental Units 0 0 0 0 0 0 




1985 Sentinel Lighting Rental Units 0 0 0 0 0 0 



Total 73,469,244 11,488,219 61,981,025 3,357,000 65,338,025 415 2,874,920 

Per 2010 Continuity 2,874,831 

Difference (89)


EB-2009-0263 

Exhibit 4 

Tab 3 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

TAX CALCULATIONS: 

Festival Hydro’s 2006 and 2007 tax calculations are included below in the tax schedules that 

were submitted to the tax authorities for those years. In addition to these tax schedules, the 

schedules detailing the calculation of tax credits claimed such as the Scientific Research and 

Experimental Development credit and the apprenticeship tax credit, as well as the calculation of 

net income for tax purposes and capital cost allocation calculations are included. Following are 

Festival Hydro’s detailed net income for tax purposes calculations for the 2009 Bridge year as 

well as the 2010 test year using the most recent tax rates including specific schedules detailing 

how capital cost allocations and cumulative eligible capital costs have been calculated. The 

2009 and 2010 calculations tax payable calculations included in the revenue requirement model, 

do not include a calculation for the Scientific Research and Experimental Development tax credit 

The projects FHI has claimed in prior years are coming to a close and it is not possible to foresee 

at this point issues or projects that may arise which may include Scientific Research and 

Experimental Development eligible activities. In addition, the tax provision calculation in the 

revenue deficiency model does not consider the apprenticeship tax credit as this amount is 

immaterial given the few apprentices we employ at this time and we have not budgeted for 

additional apprentices that would impact this tax credit calculation. 

Also included below is a table detailing the 2006 board approved capital tax amount in 

comparison to 2006, 2007, 2008 actual amounts as well as 2009 and 2010 estimated amounts. 

Note that Ontario capital tax is scheduled to be phased out effective July 1, 2010 and therefore 

the declining balance of this expense is reasonable as the rates are legislated to decrease each 

year leading up to the elimination of this tax entirely. 

The final table details the historical property tax expense in comparison to the 2009 and 2010 

estimates. 

25

1 


EB-2009-0263 

Exhibit 4 

Tab 3 

Schedule 1 



1 


EB-2009-0263 

Exhibit 4 

Tab 3 

Schedule 1 



1 


EB-2009-0263 

Exhibit 4 

Tab 3 

Schedule 1 



1 


EB-2009-0263 

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1 


EB-2009-0263 

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EB-2009-0263 

Exhibit 4 

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1 

2

1 


EB-2009-0263 

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1 


EB-2009-0263 

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EB-2009-0263 

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1 

2


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1 

2


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Exhibit 4 

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1 

2

1 


EB-2009-0263 

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1 


EB-2009-0263 

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1 


EB-2009-0263 

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1 


EB-2009-0263 

Exhibit 4 

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1 


EB-2009-0263 

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Tab 3 

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1 


EB-2009-0263 

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Tab 3 

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1 


EB-2009-0263 

Exhibit 4 

Tab 3 

Schedule 1 



1 


EB-2009-0263 

Exhibit 4 

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1 


EB-2009-0263 

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Tab 3 

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1 


EB-2009-0263 

Exhibit 4 

Tab 3 

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1 


EB-2009-0263 

Exhibit 4 

Tab 3 

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1 


EB-2009-0263 

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Tab 3 

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1 


EB-2009-0263 

Exhibit 4 

Tab 3 

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1 


EB-2009-0263 

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Tab 3 

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1 


EB-2009-0263 

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Tab 3 

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1 


EB-2009-0263 

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Tab 3 

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1 


EB-2009-0263 

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Tab 3 

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1 


EB-2009-0263 

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Tab 3 

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1 


EB-2009-0263 

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Tab 3 

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1 


EB-2009-0263 

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Tab 3 

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1 


EB-2009-0263 

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Tab 3 

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1 


EB-2009-0263 

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Tab 3 

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1 


EB-2009-0263 

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Tab 3 

Schedule 1 



1 


EB-2009-0263 

Exhibit 4 

Tab 3 

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1 


EB-2009-0263 

Exhibit 4 

Tab 3 

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1 


EB-2009-0263 

Exhibit 4 

Tab 3 

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1 


EB-2009-0263 

Exhibit 4 

Tab 3 

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1 


EB-2009-0263 

Exhibit 4 

Tab 3 

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1 


EB-2009-0263 

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Tab 3 

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1 


EB-2009-0263 

Exhibit 4 

Tab 3 

Schedule 1 



1 


EB-2009-0263 

Exhibit 4 

Tab 3 

Schedule 1 



1 


EB-2009-0263 

Exhibit 4 

Tab 3 

Schedule 1 



1 


EB-2009-0263 

Exhibit 4 

Tab 3 

Schedule 1 



1 


EB-2009-0263 

Exhibit 4 

Tab 3 

Schedule 1 



1 


EB-2009-0263 

Exhibit 4 

Tab 3 

Schedule 1 



1 


EB-2009-0263 

Exhibit 4 

Tab 3 

Schedule 1 



1 


EB-2009-0263 

Exhibit 4 

Tab 3 

Schedule 1 



1 


EB-2009-0263 

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Tab 3 

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1 


EB-2009-0263 

Exhibit 4 

Tab 3 

Schedule 1 




EB-2009-0263 

Exhibit 4 

Tab 3 

Schedule 1 



1 

2


EB-2009-0263 

Exhibit 4 

Tab 3 

Schedule 1 



1 

2


EB-2009-0263 

Exhibit 4 

Tab 3 

Schedule 1 



1 

2


EB-2009-0263 

Exhibit 4 

Tab 3 

Schedule 1 



1 

2

1 


EB-2009-0263 

Exhibit 4 

Tab 3 

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1 


EB-2009-0263 

Exhibit 4 

Tab 3 

Schedule 1 




EB-2009-0263 

Exhibit 4 

Tab 3 

Schedule 1 



1 

2

1 


EB-2009-0263 

Exhibit 4 

Tab 3 

Schedule 1 



1 


EB-2009-0263 

Exhibit 4 

Tab 3 

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1 


EB-2009-0263 

Exhibit 4 

Tab 3 

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1 


EB-2009-0263 

Exhibit 4 

Tab 3 

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1 


EB-2009-0263 

Exhibit 4 

Tab 3 

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1 


EB-2009-0263 

Exhibit 4 

Tab 3 

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1 


EB-2009-0263 

Exhibit 4 

Tab 3 

Schedule 1 



1 


EB-2009-0263 

Exhibit 4 

Tab 3 

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1 


EB-2009-0263 

Exhibit 4 

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1 


EB-2009-0263 

Exhibit 4 

Tab 3 

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1 


EB-2009-0263 

Exhibit 4 

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1 


EB-2009-0263 

Exhibit 4 

Tab 3 

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1 


EB-2009-0263 

Exhibit 4 

Tab 3 

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1 


EB-2009-0263 

Exhibit 4 

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1 


EB-2009-0263 

Exhibit 4 

Tab 3 

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1 


EB-2009-0263 

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Schedule 1 



1 


EB-2009-0263 

Exhibit 4 

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1 


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Exhibit 4 

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1 


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Exhibit 4 

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1 


EB-2009-0263 

Exhibit 4 

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1 


EB-2009-0263 

Exhibit 4 

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1 


EB-2009-0263 

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1 


EB-2009-0263 

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1 


EB-2009-0263 

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1 


EB-2009-0263 

Exhibit 4 

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1 


EB-2009-0263 

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1 


EB-2009-0263 

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1 


EB-2009-0263 

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1 


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1 


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1 


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1 


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1 


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1 


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1 


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1 


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1 


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EB-2009-0263 

Exhibit 4 

Tab 3 

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1 

2


EB-2009-0263 

Exhibit 4 

Tab 3 

Schedule 1 



1 

Table 1 

Tax Calculations 

Description 

Determination of Taxable Income 

2006 Board 

Approved 2009 Bridge 2010 Test 

Utility Income Before Taxes 1,574,992 1,609,517 2,176,849 

Book to Tax Adjustments 

Additions to Accounting Income: 

Interest and penalties on taxes 0 3,900 3,900 

Amortization of tangible assets 2,036,189 2,735,858 2,874,831 

Amortization of intangible assets 30,061 46,652 32,239 

Non-deductible meals and entertainment expense 3,120 5,600 5,600 

Tax reserves beginning of year 137,067 0 0 

Reserves from financial statements- balance at end of year 1,195,290 1,290,004 1,294,401 

Capital items expensed 87,795 0 0 

Other Additions 2,555 40,339 2,430 

Total Additions 3,492,077 4,122,353 4,213,401 

Deductions from Accounting Income: 

Gain on disposal of assets per financial statements 0 25,500 26,265 

Capital cost allowance from Schedule 8 1,510,637 2,126,370 2,226,451 

Cumulative eligible capital deduction from Schedule 10 11,773 8,807 8,191 

Tax reserves end of year 82,447 0 0 

Reserves from financial statements - balance at beginning of year 1,152,145 1,286,629 1,290,004 

Other Deductions 87,795 0 0 

Total Deductions 2,844,797 3,447,306 3,550,910 

Regulatory Taxable Income 2,222,272 2,284,564 2,839,340 

Corporate Income Tax Rate 36.12% 33.00% 32.00% 

Subtotal 802,685 

Less: R&D ITC (0.3) 

Regulatory Income Tax 802,685 753,906 908,589 

Summary of Utility Income Taxes 

Income Taxes 802,685 753,906 908,589 

Large Corporation Tax 0 0 0 

Ontario Capital Tax 87,022 0 0 

Total Taxes 889,707 753,906 908,589 

2 

3 

4 

Tax Rates 

Federal Tax 22.12% 19.00% 18.00% 

Provincial Tax 14.00% 14.00% 14.00% 

Total Tax Rate 36.12% 33.00% 32.00%


EB-2009-0263 

Exhibit 4 

Tab 3 

Schedule 3 



1 

2 

3 

4 

CAPITAL COST ALLOWANCE: 

Festival Hydro is providing Capital Cost Allowance continuity schedules for the 2009 Bridge 

Year (Table 14) and the 2010 Test Year (Table 15) as follows:

1 

2 

3 

2009 Bridge Year Capital Cost Allowance: Table 14 


EB-2009-0263 

Exhibit 4 

Tab 3 

Schedule 2 



UCC Prior Year Less: Non-Distribution Less: Disallowed UCC Bridge Year 

UCC Before 1/2 Yr 1/2 Year Rule {1/2 Additions Reduced 

UCC Ending 

Class 

Class Description 

Ending Balance Portion FMV Increment Opening Balance Additions Dispositions Adjustment 

Less Disposals} 

UCC Rate % CCA Balance 

1 Distribution System - 1988 to 22-Feb-2005 23,023,530 0 0 23,023,530 151,500 0 23,175,030 75,750 23,099,280 4% 923,971 22,251,059 

2 Distribution System - pre 1988 3,833,241 0 0 3,833,241 0 0 3,833,241 0 3,833,241 6% 229,994 3,603,247 

6 Buildings (No footings below ground) 0 0 0 0 0 0 0 0 0 10% 0 0 

8 General Office/Stores Equip 297,287 0 0 297,287 60,000 0 357,287 30,000 327,287 20% 65,457 291,830 

10 Computer Hardware/ Vehicles 729,179 0 0 729,179 355,000 0 1,084,179 177,500 906,679 30% 272,004 812,175 

10.1 Certain Automobiles 0 0 0 0 0 0 0 0 0 30% 0 0 

12 Computer Software 13,658 0 0 13,658 0 0 13,658 0 13,658 100% 13,658 0 

13 1 Lease # 1 0 0 0 0 - 0 0 0 0 20% 0 0 

13 2 Lease #2 0 0 0 0 0 0 0 0 0 0 0 

13 3 Lease # 3 0 0 0 0 0 0 0 0 0 0 0 

13 4 Lease # 4 0 0 0 0 0 0 0 0 0 0 0 

14 Franchise 0 0 0 0 0 0 0 0 0 0 0 

17 

43.1 

New Electrical Generating Equipment Acq'd after Feb 

27/00 Other Than Bldgs 0 0 0 0 0 0 0 0 0 8% 0 0 

Certain Energy-Efficient Electrical Generating 

Equipment 0 0 0 0 0 0 0 0 0 30% 0 0 

45 Computers & Systems Hardware acq'd post Mar 22/04 15,602 0 0 15,602 0 0 15,602 0 15,602 45% 7,021 8,581 

45.1 Computers & Systems Hardware acq'd post Mar 19/07 47,929 0 0 47,929 0 0 47,929 0 47,929 55% 26,361 21,568 

46 

Data Network Infrastructure Equipment (acq'd post 

Mar 22/04) 0 0 0 0 0 0 0 0 0 30% 0 0 

47 Distribution System - post 22-Feb-2005 6,938,302 1847262 5,091,040 2,765,500 0 7,856,540 1,382,750 6,473,790 8% 517,903 7,338,637 

45.2 Computer HW & SW purchased after Jan. 09 0 0 0 70,000 70,000 0 70,000 100% 70,000 0 

SUB-TOTAL - UCC 34,898,728 0 1,847,262 33,051,466 3,402,000 0 36,453,466 1,666,000 34,787,466 2,126,370 34,327,096 

CEC Goodwill 0 0 0 

CEC Land Rights 0 0 0 

CEC FMV Bump-up 125,815 0 0 125,815 

4 

SUB-TOTAL - CEC 125,815 0 0 125,815 

5 

6 

7

1 

2 

2009 Bridge Year Cumulative Eligible Capital Deduction: Table 14 

Cumulative Eligible Capital 


EB-2009-0263 

Exhibit 4 

Tab 3 

Schedule 2 



125,815 

Additions: 

Cost of Eligible Capital Property Acquired during the year 

Other Adjustments 

Subtotal 

Non-taxable portion of a non-arm's length transferor's gain realized on the 

transfer of an ECP to the Corporation after Friday December 31, 2002 

Amount transferred on amalgamation or wind-up of subsidiary 

Subtotal 

0 

0 

0 x 3/4 = 0 

0 x 1/2 = 0 

0 125,815 

0 0 

125,815 

Deductions: 

Projected proceeds of sale (less outlays and expenses not otherwise 

deductible) from the disposition of all ECP during the year 


0 

Subtotal 

0 x 3/4 = 0 125,815 

3 

4 

Cumulative Eligible Capital Balance 

CEC Deduction 

Cumulative Eligible Capital - Closing Balance 

125,815 

7% 8,807 

117,008


EB-2009-0263 

Exhibit 4 

Tab 3 

Schedule 2 



1 

2 

2010 Test Year Capital Cost Allowance: Table 15 

UCC Prior Year Less: Non-Distribution Less: Disallowed FMV UCC Bridge Year 

UCC Before 1/2 Yr 1/2 Year Rule {1/2 Additions 

UCC Ending 

Class 

Class Description 

Ending Balance 

Portion 

Increment Opening Balance Additions Dispositions Adjustment 

Less Disposals} Reduced UCC Rate % CCA Balance 

1 Distribution System - 1988 to 22-Feb-2005 22,251,059 0 0 22,251,059 100,000 0 22,351,059 50,000 22,301,059 4% 892,042 21,459,016 

2 Distribution System - pre 1988 3,603,247 0 0 3,603,247 0 0 3,603,247 0 3,603,247 6% 216,195 3,387,052 

6 Buildings (No footings below ground) 0 0 0 0 0 0 0 0 0 10% 0 0 

8 General Office/Stores Equip 291,830 0 0 291,830 35,000 0 326,830 17,500 309,330 20% 61,866 264,964 

10 Computer Hardware/ Vehicles 812,175 0 0 812,175 300,000 0 1,112,175 150,000 962,175 30% 288,653 823,523 

10.1 Certain Automobiles 0 0 0 0 0 0 0 0 0 30% 0 0 

12 Computer Software 0 0 0 0 0 0 0 0 0 100% 0 0 

13 1 Lease # 1 0 0 0 0 0 0 0 0 0 20% 0 0 

13 2 Lease #2 0 0 0 0 0 0 0 0 0 0 0 

13 3 Lease # 3 0 0 0 0 0 0 0 0 0 0 0 

13 4 Lease # 4 0 0 0 0 0 0 0 0 0 0 0 

14 Franchise 0 0 0 0 0 0 0 0 0 0 0 

17 

New Electrical Generating Equipment Acq'd after Feb 

27/00 Other Than Bldgs 0 0 0 0 0 0 0 0 0 8% 0 0 

43.1 

Certain Energy-Efficient Electrical Generating 

Equipment 0 0 0 0 0 0 0 0 0 30% 0 0 

45 Computers & Systems Hardware acq'd post Mar 22/04 8,581 0 0 8,581 0 0 8,581 0 8,581 45% 3,861 4,720 

3 

4 

5 

6 

45.1 Computers & Systems Hardware acq'd post Mar 19/07 21,568 0 0 21,568 0 0 21,568 0 21,568 55% 11,862 9,706 

46 

Data Network Infrastructure Equipment (acq'd post Mar 

22/04) 0 0 0 0 0 0 0 0 0 30% 0 0 

47 Distribution System - post 22-Feb-2005 7,338,637 0 0 7,338,637 2,872,000 0 10,210,637 1,436,000 8,774,637 8% 701,971 9,508,666 

45.2 Computer HW & SW purchased after Jan. 09 0 0 0 0 50,000 0 50,000 0 50,000 100% 50,000 0 

SUB-TOTAL - UCC 34,327,096 0 0 34,327,096 3,357,000 0 37,684,096 1,653,500 36,030,596 2,226,451 35,457,646 

**FMV increment removed from 2009 opening UCC balance, therefore do not need to remove it again for the 2010 calc. 

CEC Goodwill 117,008 0 0 117,008 

CEC Land Rights 0 0 0 0 

CEC FMV Bump-up 0 0 0 0 

SUB-TOTAL - CEC 117,008 0 0 117,008


EB-2009-0263 

Exhibit 4 

Tab 3 

Schedule 2 



1 

2 

2010 Test Year Capital Cost Allowance: Table 15 

Cumulative Eligible Capital 

Cumulative Eligible Capital Calculation 

117,008 

Additions: 

Cost of Eligible Capital Property Acquired during the year 


Subtotal 

0 

0 

0x 3/4 = 0 

Non-taxable portion of a non-arm's length transferor's gain realized on the transfer 

of an ECP to the Corporation after Friday December 31, 2002 

Amount transferred on amalgamation or wind-up of subsidiary 

Subtotal 

0x 1/2 = 0 

0 117,008 

0 0 

117,008 

Deductions: 

Projected proceeds of sale (less outlays and expenses not otherwise deductible) 

from the disposition of all ECP during the year 


0 

Subtotal 

0 x 3/4 = 0 117,008 

3 

4 

Cumulative Eligible Capital Balance 

CEC Deduction 

Cumulative Eligible Capital - Closing Balance 

117,008 

7% 8,191 

108,817


EB-2009-0263 

Exhibit 4 

Tab 3 

Schedule 2 



1 

2 

3 

4 

5 

6 

7 

Capital Tax Amounts 

Table 16 


Ontario Capital Tax Summary 

2006 Board 2006 2007 2008 

Approved Actual Actual Actual 2009 2010 

87,022 92,296 86,067 64,049 59,490 20,317 

Property Tax Amounts 

Table 17 


Property Tax Summary 

2006 Board 2006 2007 2008 

Approved Actual Actual Actual 2009 2010 

31,248 32,731 30,378 28,571 30,000 30,000


EB-2009-0263 

Exhibit 5 

Index 




5 – Cost of Capital and 

Rate of Return 

1 1 Overview 

2 Capital Structure Deemed & Actual 

3 Analysis 

A Promissory Note


EB-2009-0263 

Exhibit 5 

Tab 1 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

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23 

24 

25 

OVERVIEW: 

The purpose of this evidence is to summarize the method and cost of financing capital 

requirements for the 2010 test year. 

Capital Structure: 

Festival Hydro currently has a deemed capital structure of 56.67% debt with a return of 7.25%, 

and 43.33% equity with a return of 9% as approved in the 2009 IRM rate decision EB-2008- 

0175. 

Festival Hydro has prepared this rate application with a deemed capital structure of 56% Long 

Term Debt, 4% Short Term Debt, and 40% Equity to comply with the Report of the Board on 

Cost of Capital and 2 nd Generation Incentive Regulation for Ontario Electricity Distributors 

dated December 20, 2006 (the “Cost of Capital Report”). 

Return on Equity: 

Festival Hydro is requesting a return on equity (“ROE”) for the 2010 Test year of 8.01% in 

accordance with the Cost of Capital Parameter Updates for 2009 Cost of Service Applications 

issued by the OEB. Festival Hydro understands that the OEB will be finalizing the ROE for 

2010 rates based on January 2010 market interest rate information. 

Festival Hydro’s use of an ROE of 8.01% is without prejudice to any revised ROE that may be 

adopted by the OEB in early 2010. 

Cost of Debt: Long Term 

Festival Hydro will have two debt components starting in the 2010 test year. Festival Hydro has 

its original debt being a Promissory Note held by its shareholder the City of Stratford, to which 

has been assigned the 2009 Board approved deemed interest rate of 7.62%. 

In addition, in 2010 Festival Hydro will be borrowing $2.5 million dollars from Infrastructure 

Ontario to fund our smart meter program. The loan will be a 15 year loan with blended principal 

and interest payments. The interest rate currently quoted (as at June 16, 2009) on the


EB-2009-0263 

Exhibit 5 

Tab 1 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

Infrastructure Ontario website is 5.04%. We have used 6.00% in our model which allows for 

some interest rate volatility between now and when the loan is drawn upon in 2010. Based on 

Bank of Canada Economic reports, we expect interest rates to hold until mid 2010 then may be 

subject to change. This loan was approved by Infrastructure Ontario on October 16, 2007. 

Festival Hydro understands that the OEB will be finalizing the return on short tem and long term 

debt for 2010 rates based on January 2010 market interest rate information. Festival Hydro’s use 

of a Return on Long Term Debt of 7.62% is without prejudice to any revised ROE that may be 

adopted by the OEB in early 2010. 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

Cost of Debt: Short Term 

Festival Hydro is requesting a return on Short Term Debt for the 2010 Test year of 1.33% in 

accordance with the Cost of Capital Parameter Updates for 2009 Cost of Service Applications 

issued by the OEB on February 24, 2009. Festival Hydro understands that the OEB will be 

finalizing the return on short term debt for 2010 rates based on January 2010 market interest rate 

information. Festival Hydro’s use of a Return on Short Term Debt of 1.33% is without prejudice 

to any revised ROE that may be adopted by the OEB in early 2010. 

Rate Base and Rate of Return 

Exhibit 6, Tab 1, Schedule 2 details Festival Hydro’s rate base, deemed debt/equity ratios, 

deemed rate of return, actual debt/equity ratios and actual rates of returns for 2006 Board 

Approved, 2006 Actual, 2007 Actual, 2008 Actual, 2009 Bridge Year Forecast, and 2010 Test 

Year Forecast.


EB-2009-0263 

Exhibit 5 

Tab 1 

Schedule 2 



1 

Capital Structure – Deemed & Actual 

Capital Structure for 2006 

% of Rate 

Description $ 

Base Rate of Return 

Return 

Long Term Debt 18,042,951 50.00% 

7.25% 1,308,113.96 

Unfunded Short Term Debt 

Total Debt 18,042,951 50.00% 

1,308,113.96 

2 

3 

Share Equity 18,042,951 50.00% 

Total equity 18,042,951 50.00% 

Total Rate Base 36,085,902 100% 

9.00% 1,623,865.61 

1,623,865.61 

8.13% 2,931,979.57 



Description $ 


Long Term Debt 18,304,187 50.00% 

7.25% 


Total Debt 18,304,187 50.00% 

Return 

1,327,053.53 

1,327,053.53 

Share Equity 18,304,187 50.00% 

Total equity 18,304,187 50.00% 

9.00% 

1,647,376.79 

1,647,376.79 

4 

5 


8.13% 

2,974,430.32 



Description $ 


Return 

Long Term Debt 20,037,938 53.33% 

7.25% 1,452,750.48 


Total Debt 20,037,938 53.33% 

1,452,750.48 

6 

7 

Share Equity 17,533,195 46.67% 

Total equity 17,533,195 46.67% 


9.00% 1,577,987.59 

1,577,987.59 

8.07% 3,030,738.07


EB-2009-0263 

Exhibit 5 

Tab 1 

Schedule 2 





Description $ 


Return 

Long Term Debt 22,207,015 56.67% 

7.25% 1,610,008.57 

Unfunded Short Term Debt 0 0.00% 

0.00% 0.00 

Total Debt 22,207,015 56.67% 

1,610,008.57 

1 

2 

Share Equity 16,981,835 43.33% 

Total equity 16,981,835 43.33% 


9.00% 1,528,365.14 

1,528,365.14 

8.01% 3,138,373.71 



Description $ 


Return 

Long Term Debt 22,166,845 56.00% 

7.40% 1,639,513.71 

Unfunded Short Term Debt 1,583,346 4.00% 

1.33% 21,058.50 

Total Debt 23,750,191 60.00% 

1,660,572.21 

3 

4 

5 

Share Equity 15,833,460 40.00% 

Total equity 15,833,460 40.00% 


8.01% 1,268,260.18 

1,268,260.18 

7.40% 2,928,832.39


EB-2009-0263 

Exhibit 5 

Tab 1 

Schedule 2 



2006 Board Approved Rate base 

Elements 

Deemed Dollars 

Deemed 

Return (%) 

Long Term Debt 17,499,914 7.25% 


Total Debt 17,499,914 7.25% 

Deemed Return ($) 

1,268,743.77 

1,268,743.77 

Actual Dollars 

Deb t to 

Equity (%) 

Actual Cost 

Rate (%) 

Common Share Equity 17,499,914 9.00% 

Total equity 17,499,914 9.00% 

1,574,992.26 

1,574,992.26 

Total Rate Base 34,999,828 8.13% 

2,843,736.03 

2006 Actual Rate Base 

Elements 


Deemed 

Return (%) Deemed Return ($) Actual Dollars 

Deb t to 

Equity (%) 

Actual Cost 

Rate (%) 

Long Term Debt 18,042,951 7.25% 1,308,113.96 15,600,000.00 49.04% 7.25% 

Cosumer Deposits 644,876.00 2.03% Prime - 1.85% 

Total Debt 18,042,951 7.25% 1,308,113.96 16,244,876.00 51.06% 

Share Equity 18,042,951 9.00% 1,623,865.61 15,568,388.00 48.94% 

Total equity 18,042,951 9.00% 1,623,865.61 15,568,388.00 

Total Rate Base 36,085,902 8.13% 2,931,979.57 31,813,264.00 100.00% 

Actual return 

1,385,507.00 

Actual rate of return on equity 8.90% 


Elements 


Deemed 


Deb t to 

Equity (%) 

Actual Cost 

Rate (%) 

Long Term Debt 18,304,187 7.25% 1,327,053.53 15,600,000.00 48.65% 7.25% 


Total Debt 18,304,187 7.25% 1,327,053.53 16,496,096.00 51.45% 

Share Equity 18,304,187 9.00% 1,647,376.79 15,568,388.00 48.55% 

Total equity 18,304,187 9.00% 1,647,376.79 15,568,388.00 


Actual return 

1,536,157.00 



Elements 


Deemed 


Deb t to 

Equity (%) 

Actual Cost 

Rate (%) 

Long Term Debt 20,037,938 7.25% 1,452,750.48 15,600,000.00 48.65% 7.25% 


Total Debt 20,037,938 7.25% 1,452,750.48 16,497,020.00 51.45% 

Share Equity 17,533,195 9.00% 1,577,987.59 15,568,388.00 48.55% 

Total equity 17,533,195 9.00% 1,577,987.59 15,568,388.00 

1 

2 

3 


Actual return 

1,722,574.32 

Actual rate of return on equity 11.06%


EB-2009-0263 

Exhibit 5 

Tab 1 

Schedule 2 



2009 Bridge Year 

Elements 


Deemed 


Deb t to 

Equity (%) 

Actual Cost 

Rate (%) 

Long Term Debt 22,207,015 7.25% 1,610,008.57 15,600,000.00 48.56% 7.25% 


Total Debt 22,207,015 7.25% 1,610,008.57 16,556,223.00 51.54% 

Share Equity 16,981,835 9.00% 1,528,365.14 15,568,388.00 48.46% 

Total equity 16,981,835 9.00% 1,528,365.14 15,568,388.00 


Actual return 

1,376,906.14 



Elements 


Deemed 


Deb t to 

Equity (%) 

Actual Cost 

Rate (%) 

Long Term Debt 22,166,845 7.40% 1,639,513.71 15,600,000.00 45.05% 7.40% 

Infrastructure ontario 0 2,500,000.00 7.22% 6.00% 

Cosumer Deposits 1,583,346 1.33% 21,058.50 956,223.00 2.76% Prime - 1.85% 

Total Debt 23,750,191 8.73% 1,660,572.21 19,056,223.00 55.04% 

Share Equity 15,833,460 8.01% 1,268,260.18 15,568,388.00 44.96% 

Total equity 15,833,460 8.01% 1,268,260.18 15,568,388.00 

1 

2 

3 


Actual return 

1,268,260.18 

Actual rate of return on equity 8.15%


EB-2009-0263 

Exhibit 5 

Tab 1 

Schedule 3 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

ANALYSIS 

Actual Rate of Return 

Festival Hydro’s ROE in 2006 (8.9%), 2007 (9.87%) and 2008 (11.32%) were close to or above 

the allowed deemed ROE. The main items affecting returns during this time were stable 

revenues, higher than expected other revenues and keeping OM&A costs in line. The fact our 

actual debt is lower than our deemed debt also impacts our returns. 

The ROE using current rates is projected at 2009 (9.06%) and 2010 (8.16%). 


Festival Hydro’s current Debt to Equity ratio, with the addition of the Infrastructure Ontario 

loan, will approach the deemed rate of 60% Debt and 40% Equity, as set for this Application. 

Festival Hydro will continue to undertake options to bring the actual debt to equity ratio in line 

with the new deemed rates. All future debt funding will be third party funding. 

There have been no changes to the actual equity share structure since the 2006 EDR Rate 

application. Equity consists of 6,100 Class A Preferred Shares with a book value of $6,100,000 

and 6,995 common shares with a book value of $9,468,388. The City of Stratford owns 100% of 

shares in each class. 

There have been no changes to the actual debt structure since the 2006 EDR Rate application. 

Festival Hydro has its Promissory Note held by its shareholder, the City of Stratford, for 

$15,600,000 with an interest rate of 7.25%. In addition, Festival Hydro will be borrowing $2.5 

million in 2010 to fund the smart meter program. Refer to appendix A for a copy of the 

promissory notes held by the City of Stratford.


EB-2009-0263 

Exhibit 5 

Tab 1 

Schedule 3 

Appendix A 


APPENDIX A 

PROMISSORY NOTE

1 


EB-2009-0263 

Exhibit 5 

Tab 1 

Schedule 3 

Appendix A 



1 


EB-2009-0263 

Exhibit 5 

Tab 1 

Schedule 3 

Appendix A 



1 


EB-2009-0263 

Exhibit 5 

Tab 1 

Schedule 3 

Appendix A 



Festival Hydro-Electric System Corp. 

EB-2009-0263 

Exhibit 6 

Index 




6 – Calculation of 

Revenue Deficiency or 

Surplus 

1 1 Revenue Deficiency - Overview 

2 Drivers of Revenue Deficiency


EB-2009-0263 

Exhibit 6 

Tab 1 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

REVENUE DEFICIENCY - OVERVIEW: 

Festival Hydro has provided detailed calculations supporting its 2010 revenue deficiency. 

Festival Hydro’s net revenue deficiency is $666,038 and when grossed up for PILs Festival 

Hydro’s revenue deficiency is $979,467. Table 1 on the following page provides the revenue 

deficiency calculations for the 2010 Test Year at Existing 2009 OEB-approved rates and the 

2010 Test Year Revenue Requirement.


EB-2009-0263 

Exhibit 6 

Tab 1 

Schedule 1 



Calculation of Revenue Deficiency or Surplus 

2010 Test Existing 

Rates 

2010 Test 

Proposed Rates 

Revenue 

Suff/ Def From Below. $979,467 

Distribution Revenue $8,872,663 $8,872,663 

Other Operating Revenue (Net) $659,450 $659,450 

Total Revenue $9,532,113 $10,511,581 

Distribution Costs 

Operation, Maintenance, and Administration $3,968,347 $3,968,347 

Depreciation & Amortization $2,655,496 $2,655,496 

Taxes $50,317 $50,317 

Interest- Deemed Interest $1,660,572 $1,660,572 

Total Costs and Expenses $8,334,732 $8,334,732 

Utility Income Before Income Taxes $1,197,382 $2,176,849 

Net Adjustments per 2010 Pils $662,491 $662,491 

Taxable Income $1,859,872 $2,839,340 

Tax Rate 32.0% 32.0% 

Income Tax $595,159 $908,589 

Utility Income $602,222 $1,268,260 

Rate Base $39,583,651 $39,583,651 

Equity 40.00% 40.00% 

Equity Component Rate Base $15,833,460 $15,833,460 

Income / Equity Rate Base % 3.80% 8.01% 

Target Return -Equity on Rate Base 8.01% 8.01% 

1 

Return- Equity on Rate Base $1,268,260 $1,268,260 

Revenue Deficiency $666,038 

Revenue Deficiency (Gross-up) $979,467


EB-2009-0263 

Exhibit 6 

Tab 1 

Schedule 2 



1 

2 

DRIVERS OF REVENUE DEFICIENCY 

The following table highlights the drivers of the 2010 revenue deficiency. 

Drivers of 2010 Revenue Deficiency 

Descriptin of Driver $ % 

Increase in rate base $ 339,161 35% 

Decrease in regulated rate of return $ (213,028) ‐22% 

Increase in OM&A expenses $ 1,215,540 124% 

Decrease in taxable income $ (101,313) ‐10% 

Decrease in tax rate $ (203,545) ‐21% 

Increase in paid up capital used in OCT calc. $ 2,311 0% 

Increase in paid up capital exemption used in OCT calc. $ (3,750) 0% 

Decrease in OCT tax rate $ (65,266) ‐7% 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

Expected revenue deficiency $ 970,110 99% 

Actual Revenue deficiency $ 979,467 100% 

Difference $ 9,357 1% 

The deficiency is largely the result of increased OM&A expenses. Table 1 of Exhibit 4, Tab 1, 

Schedule 1, summarizes the increase and notes that it totals 17.76% when comparing the 2010 

projected OM&A expenses to the 2006 Board Approved OM&A expenses. As the 2006 Board 

approved amount is essentially equal to 2004 actual balances (with a few Board adjustments), the 

17.76% increase has in fact occurred over a 6 years. This is an average increase of 2.96% per 

year which is in line with the increase in labour rates and rate of inflation since 2004. 

The other large revenue deficiency driver noted above relates to the increase in the rate base 

from the 2006 Board Approved amount of $34M to the projected 2010 rate base amount of 

$39M. This increase is mainly the result of increasing capital additions as supported by the 

Asset Management Plan included in Exhibit 2, Tab 3, Schedule 2, Appendix A. 

These increases are netted against decreases in the deficiency due to a decreased allowed 

regulated rate of return as well as decreased expected tax expenses due mainly to decreasing 

federal and capital tax rates.


EB-2009-0263 

Exhibit 7 

Index 




7 – Cost 

Allocation 

1 1 Cost Allocation Overview 

2 Summary of Results and Proposed 

Adjustments 

3 Revenue to Cost Ratios


EB-2009-0263 

Exhibit 7 

Tab 1 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

COST ALLOCATION OVERVIEW: 

Introduction: 

On September 15, 2006, the OEB issued its directions on Cost Allocation Methodology for 

Electricity Distributors (the “Directions”). On November 15, 2006, the Board issued the Cost 

Allocation Information Filing Guidelines for Electricity Distributors (“the Guidelines”), the Cost 

Allocation Model (the “Model”) and User Instructions (the “Instructions”) for the Model. 

Festival Hydro prepared a cost allocation information filing consistent with Festival Hydro’s 

understanding of the Directions, the Guidelines, the Model and the Instructions. Festival Hydro 

submitted this filing to the OEB on February 28, 2007. 

One of the main objectives of the filing was to provide information on any apparent crosssubsidization 

among a distributor’s rate classifications. It was felt that this would give an 

indication of cross-subsidization from one class to another and this information would be useful 

as a tool in future rate applications.


EB-2009-0263 

Exhibit 7 

Tab 1 

Schedule 2 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

SUMMARY OF RESULTS AND PROPOSED ADJUSTMENTS: 

INITIAL COST ALLOCATION STUDY RESULTS: 

The data used in the Cost Allocation Model was consistent with Festival Hydro’s cost data that 

supported its 2006 OEB-approved distribution rates. Consistent with the Guidelines, Festival 

Hydro’s assets were broken out into primary and secondary distribution functions. The breakout 

of assets, capital contributions, depreciation, accumulated depreciation, customer data and load 

data by primary, line transformer and secondary categories were developed from the best data 

available to Festival Hydro, its engineering records, and its customer and financial information 

systems. 

As noted above, the results of a cost allocation study are typically presented in the form of 

revenue to cost ratios. The ratio is shown by rate classification and is the percentage of 

distribution revenue collected by rate classification compared to the costs allocated to the 

classification. The percentage identifies the rate classifications that are being subsidized and 

those that are over-contributing. A percentage of less than 100% means the rate classification is 

under-contributing and is being subsidized by other classes of customers. A percentage of 

greater than 100% indicates the rate classification is over-contributing and is subsidizing other 

classes of customers. 

The following Table 1 outlines the revenue to cost ratios from the Cost Allocation Informational 

Filing submitted by Festival Hydro on February 28, 2007. The calculations are based on Festival 

Hydro’s OEB-approved 2006 electricity distribution rates. 

21


EB-2009-0263 

Exhibit 7 

Tab 1 

Schedule 2 



1 

2 

3 

4 

5 

6 

7 

8 

Table 1 

Revenue to Cost Ratios as Filed in Festival Hydro’s 

Initial 2006 Cost Allocation Informational Filing 

Rate Classification 

Revenue 

(A) 

Allocated Cost 

(B) 

Revenue to Cost 

Ratio (A)/(B) 

Residential $5,267,673 $4,961,397 106.17% 

Residential Hensall $81,865 $134,241 60.98% 

GS < 50 kW $1,754,659 $1,729,881 101.43% 

GS > 50 kW to 4,999 kW $2,337,166 $2,601,328 89.85% 

Large Use $404,662 $256,476 157.78% 

Street Lighting $56,692 $198,312 28.59% 

Sentinel Lights $2,846 $11,689 24.35% 

Unmetered Scattered Load $20,754 $32,993 62.90% 

Total $9,926,317 $9,926,317 100.00% 

REVISED INTIAL MODEL FOR TRANSFOMER ALLOWANCE: 

The original 2006 model has been updated to remove the cost associated with the transformer 

ownership allowance of $446,944 from the revenue requirement to create a second model for 

adjusted transformer allowance. The results are very similar to the first model. 

Table 2 

Revenue to Cost Ratios as Filed in Festival Hydro’s 

Updated 2006 Cost Allocation Informational Filing with TA Removed 


Revenue 

(A) 

Allocated Cost 

(B) 

Revenue to Cost 

Ratio (A)/(B) 

Residential $5,034,449 $4,789,799 105.11% 


GS < 50 KW $1,675,384 $1,656,608 101.13% 

GS > 50 kW to 4,999 kW $2,228,954 $2,414,956 92.30% 

Large Use $385,581 $258,829 148.97% 




Total $9,479,373 $9,479,373 100.00% 

9


EB-2009-0263 

Exhibit 7 

Tab 1 

Schedule 2 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

2010 COST ALLOCATION STUDY RESULTS: 

In preparing for this rate application, the original cost of service model has been updated to 

reflect 2010 test year data included forecasted assets balances, loss factors, deemed capital 

structure and 2010 income and expenses. Rather than complete a full weather normalization 

study, the load profiles from the 2006 study have been updated and scaled to match the 2010 

load forecast. This filing follows the cost allocation policies reflected in the Board’s report of 

November 28, 2007 Application of Cost Allocation for Electricity Distributors (EB-2007-0667). 

A copy of the updated cost allocation is provided in Appendix A. The model has been updated 

to remove the costs associated with the transformer ownership allowance from the revenue 

requirement. The revenue to cost ratios for updated study is provided in Table 3 below: 

Table 3 

Revenue to Cost Ratios from Festival Hydro's 

2010 Cost Allocation Information Filing 

Rate Classification Revenue Allocated Cost Revenue to Cost Ratio 

(A) (B) (A)/(B) 

Residential $5,870,413 $5,413,673 108.44% 


GS50kW to 4,999 kW $2,289,157 $2,863,904 79.93% 

Large Use $341,907 $299,651 114.10% 




Total $10,511,582 $10,511,581 100.00% 

13


EB-2009-0263 

Exhibit 7 

Tab 1 

Schedule 2 



1 

2 

3 

4 

5 

6 

7 

8 

9 

Proposed Adjustment to Cost Allocation: 

On November 28, 2007, the OEB issued its “Report on Application of Cost Allocation for 

Electricity Distributors” (the “Cost Allocation Report”). In the Cost Allocation Report, the OEB 

established what it considered to be the appropriate ranges of revenue to cost ratios which are 

summarized in Appendix 2-P below. The appendix provides Festival Hydro’s original 2006, 

revised 2006 for transformer allowance removal, and 2010 proposed for test year ratios. The 

proposed revenue to cost ratios reflects adjustments to revenue to eventually move away from 

cross subsidization. 

Appendix 2-P Revenue to Cost Ratios (%) 

10 

11 

From Original 2006 

Cost Allocation 

Original 2006 Model 

revised to remove 

Transformer 

Ownership From 2010 Cost Proposed for Test 

Board 

Target 

Board 

Target 

Class 

Model 

Allownace Allocation Model Year Low High 

Residential 106.17% 105.11% 108.44% 107.70% 85% 115% 

Residential - Hensall 60.98% 60.51% 71.52% 91.21% 85% 115% 

GS < 50 kW 101.43% 101.13% 116.03% 112.28% 80% 120% 

GS >50 89.85% 92.30% 79.93% 81.85% 80% 180% 

Large Use 157.78% 148.97% 114.10% 108.13% 85% 115% 

Sentinel Lights 24.35% 24.62% 31.40% 50.70% 70% 120% 

Street Lighting 28.59% 28.94% 32.88% 51.52% 70% 120% 

USL 62.90% 62.73% 143.83% 120.30% 80% 120% 

12 

13 

14 

15 

16 

17 

18 

While most ratios for 2010 are similar to the ratios from 2006, there have been some changes 

which are primarily a result in the differences in forecasted loads used in the 2006 model 

compared to the updated load projections used in the 2010 model. The contribution from 

unmetered scattered load appears to have doubled; however, this was due to a data error for USL 

revenue in 2006. The 2010 forecast reflects the proper revenues generated by USL. Table 5 at 

the end of this chapter provides the revenue to costs ratio summaries for the 2006 original filing, 

2006 with transformer allowances removed and the updated 2010 cost allocation model.


EB-2009-0263 

Exhibit 7 

Tab 1 

Schedule 2 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

Festival Hydro is proposing in this application to re-align its revenue to cost ratios by adjusting 

the allocations of revenue among rate classes in order to reduce some of the cross-subsidization 

that is occurring. The following re-alignments are proposed: 

Residential has a slight decrease (.7%) to balance the overall net change. Residential is 

well within the range with a final ratio of 107.70. 

General Service 50 kW has been raised by 1.91% from the current ratio of 79.93, a 

move slightly beyond the minimum target ratio of 80. 

Large Use has been decreased by 5.2% as an offset to the increases. 

Sentinel lights has been increased by 122%, which is an increase equal to 50% between 

the current ratio and the minimum target. 

Street Lighting has been increased by 113%, which is 50.7% between the current ratio 

and the minimum target ratio. 

Unmetered Scattered Load has been decreased by 16.3% to bring the ratio down from 

143.84 to the Board target high of 120.30. 

Residential Hensall has been increased by 27.5% between the current ratio and the 

minimum target ratio. This increase is beyond the 50% difference between the existing 

ratio and the minimum target because of Festival Hydro’s desire to move these rates 

closer to the normal Festival Hydro residential rates and to eventually harmonize these 

rates. 

In 2000, Festival Hydro purchased the electrical assets of the former Hensall Public Utilities 

Commission. Because of the large differences in residential rates, the rates were not harmonized 

at that time. As part of the 2006 rate application process and previous RAM models, Festival


EB-2009-0263 

Exhibit 7 

Tab 1 

Schedule 2 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

Hydro took steps to harmonize these rates through direct mitigation. There has been no further 

direct mitigation since 2006. 

All Festival Hydro residential customers receive the same level of service, regardless of whether 

they live in Hensall or anywhere else in Festival Hydro’s territory (i.e. in Stratford, St. Marys, 

Seaforth, Dashwood, Brussels, Zurich and Hensall). As such, we want to move towards full rate 

harmonization so that Hensall residential customers pay the same amount for the same service. 

Through the Cost allocation process, we have increased the cost to revenue ratio to 91.21%, 

which is still lower than 107.70% for regular residential customers. By increasing the cost to 

revenue ratio to 91.21%, it creates a final bill impact (along with all other changes) of 7.45% 

($5.78 per month) for a customer using 800 kWh and a 9.79% ($6.72 per month) for a customer 

using 500 kWh. For the average Hensall residential customer the impact on the total bill is less 

than 10%. 

Cost Allocation - Test Year Revenue Impacts 

Test Year 

Class 

Current Revenue 

(i.e. 2006 model 

revenue to cost 

ratios with TA 

removed 

Test Year Revenue 

using 2010 model 


ratios 

Revenue 

assuming 

Proposed 


ratios 

Residential 5,034,449.38 5,870,412.79 5,830,423.31 

Residential - Hensall 78,271.59 99,742.26 127,203.47 

GS < 50 kW 1,675,383.69 1,798,111.34 1,739,984.60 

GS >50 2,228,954.17 2,289,157.16 2,344,010.83 

Large Use 385,581.05 341,906.71 324,011.09 

Sentinel Lights 2,724.82 4,409.24 7,120.04 

Street Lighting 54,161.32 66,582.91 104,317.84 

USL 19,847.20 41,259.32 34,510.51 

TOTAL 9,479,373.23 10,511,581.71 10,511,581.71


EB-2009-0263 

Exhibit 7 

Tab 1 

Schedule 2 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

The Test Year Impact table above provides the amount of revenue generated by each class, 

providing our current revenue, test year at current revenue to costs ratios and Test year revenue 

at the proposed revenue to cost ratios. The following table illustrates the revenue contributions 

which will be in place after the adjustments compared to the revenue splits at existing rates. 

Residential Hensall, Sentinel lighting and Street Lighting show the largest changes, as all are 

currently under-contributing towards costs. 

Table 4 

Revenue Split by Rate Class to Achieve Proposed Revenue to Cost Ratios 


Revenue Contribution from 

Proposed Revenue Cost Ratio 

Revenue Contributions at Existing 

Rates 

Residential 55.02% 55.43% 

Residential Hensall 1.20% 0.92% 

GS < 50kW 16.68% 17.27% 

GS > 50kW to 4,999 kW 22.51% 21.95% 

Large Use 3.20% 3.38% 

Street Lighting 1.00% 0.62% 

Sentinel Lights 0.07% 0.04% 

Unmetered Scattered Load 0.33% 0.40% 

Total 100.00% 100.00% 

Cost Allocation Summary: 

The discussion and tables above support Festival Hydro’s proposed reallocation of distribution 

revenues across customer classes, in order to begin moving toward revenue to cost ratios which 

approximate 100% and reduce cross-subsidization. Festival Hydro submits that the proposed 

reallocation of distribution revenue is fair and reasonable for the following reasons: 

15 

16 

 

Customer class revenues will more closely reflect the actual costs of providing 

distribution service to that class; 

17 

18 

 

When necessary partial reallocation provides time for further refinement of the cost 

allocation model and movement between classes


EB-2009-0263 

Exhibit 7 

Tab 1 

Schedule 3 



Table 5 

Revenue to Cost Ratios 

2010 COST ALLOCATION INFORMATION FILING 


EB-2005-0364 EB-2007-0002 

Friday August 28, 2009 

Sheet O1 Revenue to Cost Summary Worksheet - Second Run 2010 - Run 2 Model 

Class Revenue, Cost Analysis, and Return on Rate Base 

Rate Base 

Assets 

1 2 3 6 7 8 9 10 

Total Residential GS 50-Regular Large Use >5MW Street Light Sentinel 

Hensall 

Residential 

Unmettered 

Scattered Load 

crev Distribution Revenue (sale) $9,852,130 $5,460,632 $1,701,462 $2,162,368 $333,164 $60,786 $3,989 $90,764 $38,965 

mi Miscellaneous Revenue (mi) $659,451 $409,781 $96,649 $126,789 $8,743 $5,797 $421 $8,978 $2,294 

Total Revenue $10,511,582 $5,870,413 $1,798,111 $2,289,157 $341,907 $66,583 $4,409 $99,742 $41,259 

Expenses 

di Distribution Costs (di) $951,502 $495,784 $142,540 $239,759 $27,890 $27,481 $1,875 $12,789 $3,383 

cu Customer Related Costs (cu) $1,514,767 $1,020,635 $233,900 $195,664 $21,902 $12,261 $1,105 $24,814 $4,486 

ad General and Administration (ad) $1,552,395 $942,165 $236,270 $285,915 $32,417 $25,413 $1,893 $23,424 $4,898 

dep Depreciation and Amortization (dep) $2,655,496 $1,220,246 $386,380 $865,275 $83,959 $56,897 $3,801 $32,350 $6,590 

INPUT PILs (INPUT) $908,589 $410,760 $130,361 $302,425 $31,605 $19,045 $1,271 $10,912 $2,209 

INT Interest $1,660,572 $750,721 $238,253 $552,724 $57,762 $34,807 $2,323 $19,944 $4,038 

Total Expenses $9,243,321 $4,840,311 $1,367,703 $2,441,762 $255,535 $175,905 $12,268 $124,233 $25,603 

Direct Allocation $0 $0 $0 $0 $0 $0 $0 $0 $0 

NI Allocated Net Income (NI) $1,268,260 $573,363 $181,965 $422,142 $44,116 $26,584 $1,774 $15,232 $3,084 

Revenue Requirement (includes NI) $10,511,581 $5,413,673 $1,549,669 $2,863,904 $299,651 $202,490 $14,042 $139,465 $28,687 

Revenue Requirement Input equals Output 

Rate Base Calculation 

Net Assets 

dp Distribution Plant - Gross $72,353,294 $33,121,256 $10,502,557 $23,709,883 $2,321,867 $1,538,397 $102,828 $877,439 $179,067 

gp General Plant - Gross $6,927,776 $3,187,988 $1,000,673 $2,247,620 $228,064 $151,218 $10,120 $84,441 $17,651 

accum dep Accumulated Depreciation ($42,899,817) ($19,567,506) ($6,248,189) ($14,154,113) ($1,352,250) ($895,494) ($59,803) ($518,439) ($104,024) 

co Capital Contribution ($4,133,326) ($2,145,553) ($626,153) ($1,087,671) ($79,947) ($116,312) ($7,898) ($55,756) ($14,036) 

Total Net Plant $32,247,928 $14,596,185 $4,628,888 $10,715,720 $1,117,735 $677,809 $45,247 $387,685 $78,659 

Directly Allocated Net Fixed Assets $0 $0 $0 $0 $0 $0 $0 $0 $0 

COP Cost of Power (COP) $44,886,161 $10,094,816 $4,825,897 $24,198,047 $5,100,016 $303,779 $18,261 $296,345 $48,999 

OM&A Expenses $4,018,664 $2,458,583 $612,710 $721,338 $82,209 $65,156 $4,873 $61,028 $12,767 

Directly Allocated Expenses $0 $0 $0 $0 $0 $0 $0 $0 $0 

Subtotal $48,904,825 $12,553,400 $5,438,607 $24,919,386 $5,182,225 $368,935 $23,134 $357,373 $61,766 

Working Capital $7,335,724 $1,883,010 $815,791 $3,737,908 $777,334 $55,340 $3,470 $53,606 $9,265 

Total Rate Base $39,583,651 $16,479,195 $5,444,679 $14,453,628 $1,895,069 $733,150 $48,717 $441,291 $87,924 

Rate Base Input equals Output 

Equity Component of Rate Base $15,833,461 $6,591,678 $2,177,872 $5,781,451 $758,028 $293,260 $19,487 $176,516 $35,170 

Net Income on Allocated Assets $1,268,261 $1,030,102 $430,408 ($152,605) $86,372 ($109,323) ($7,859) ($24,491) $15,656 

Net Income on Direct Allocation Assets $0 $0 $0 $0 $0 $0 $0 $0 $0 

Net Income $1,268,261 $1,030,102 $430,408 ($152,605) $86,372 ($109,323) ($7,859) ($24,491) $15,656 

RATIOS ANALYSIS 

REVENUE TO EXPENSES % 100.00% 108.44% 116.03% 79.93% 114.10% 32.88% 31.40% 71.52% 143.83% 

EXISTING REVENUE MINUS ALLOCATED COSTS $1 $456,739 $248,443 ($574,747) $42,256 ($135,907) ($9,633) ($39,723) $12,572 

RETURN ON EQUITY COMPONENT OF RATE BASE 8.01% 15.63% 19.76% -2.64% 11.39% -37.28% -40.33% -13.87% 44.52% 

OEB Range 

Low 85% 80% 80% 85% 70% 70% 85% 80% 

High 115% 120% 180% 115% 120% 120% 115% 120% 

Proposed Revenue to Cost Ratios 108.44% 112.10% 80.0% 149.3% 57.5% 43.1% 77.7% 130.4% 

Cost $10,511,581 $5,413,673 $1,549,669 $2,863,904 $299,651 $202,490 $14,042 $139,465 $28,687 

Revenues $10,614,215 $5,870,413 $1,737,194 $2,291,123 $447,379 $116,350 $6,051 $108,309 $37,396 

Percentage $1 55.31% 16.37% 21.59% 4.21% 1.10% 0.06% 1.02% 0.35%



EB-2005-0364 EB-2007-0002 


Sheet O1 Revenue to Cost Summary Worksheet - Second Run Run 2 with USL as a separate class 



EB-2009-0263 

Exhibit 7 

Tab 1 

Schedule 3 



Rate Base 

Assets 

1 2 3 6 7 8 9 10 


Hensall 

Residential 

Unmettered 




Total Revenue $9,926,317 $5,267,673 $1,754,659 $2,337,166 $404,662 $56,692 $2,846 $81,865 $20,754 

Expenses 

di Distribution Costs (di) $1,378,530 $720,121 $237,071 $328,187 $23,411 $41,866 $2,424 $19,257 $6,194 

cu Customer Related Costs (cu) $1,178,876 $798,181 $205,645 $141,416 $2,816 $5,861 $544 $20,801 $3,611 


dep Depreciation and Amortization (dep) $2,036,190 $919,119 $358,845 $615,687 $65,669 $42,867 $2,457 $25,298 $6,248 

INPUT PILs (INPUT) $1,339,573 $592,895 $233,988 $414,833 $48,236 $27,615 $1,581 $16,378 $4,047 

INT Interest $1,268,744 $561,546 $221,616 $392,899 $45,686 $26,155 $1,498 $15,512 $3,833 


Direct Allocation $9,000 $8,820 $0 $0 $0 $0 $0 $180 $0 





Net Assets 


gp General Plant - Gross $4,573,711 $2,041,915 $802,636 $1,398,649 $158,694 $95,911 $5,494 $56,360 $14,051 

accum dep Accumulated Depreciation ($28,828,157) ($12,809,611) ($5,054,819) ($8,962,093) ($941,852) ($587,341) ($33,624) ($352,987) ($85,829) 

co Capital Contribution ($1,384,370) ($722,940) ($265,188) ($317,708) ($12,267) ($38,712) ($2,229) ($19,687) ($5,640) 




OM&A Expenses $3,697,819 $2,181,928 $640,324 $690,173 $40,172 $69,206 $4,294 $57,616 $14,107 

Directly Allocated Expenses $9,000 $8,820 $0 $0 $0 $0 $0 $180 $0 

Subtotal $46,354,930 $11,711,988 $5,462,920 $23,080,529 $5,312,463 $323,508 $15,690 $346,569 $101,264 




Net Income on Allocated Assets $1,574,991 $1,003,365 $299,888 $223,575 $204,899 ($109,151) ($6,984) ($33,119) ($7,481) 


Net Income $1,574,991 $1,003,365 $299,888 $223,575 $204,899 ($109,151) ($6,984) ($33,119) ($7,481) 




EXISTING REVENUE MINUS ALLOCATED COSTS ($1) $306,274 $24,779 ($264,162) $148,186 ($141,620) ($8,844) ($52,376) ($12,239) 

RETURN ON EQUITY COMPONENT OF RATE BASE 8.99% 14.14% 10.47% 3.68% 22.67% -34.76% -39.31% -16.75% -14.95%


EB-2009-0263 

Exhibit 7 

Tab 1 

Schedule 3 





EB-2005-0364 EB-2007-0002 


Sheet O1 Revenue to Cost Summary Worksheet - Second Run 2006 Run 2 tranformer allowance removed 


Rate Base 

Assets 

1 2 3 6 7 8 9 10 


Hensall 

Residential 

Unmettered 




Total Revenue $9,479,373 $5,034,449 $1,675,384 $2,228,954 $385,581 $54,161 $2,725 $78,272 $19,847 

Expenses 

di Distribution Costs (di) $931,586 $516,720 $162,408 $177,198 $23,411 $31,645 $1,837 $13,649 $4,717 

cu Customer Related Costs (cu) $1,178,876 $798,181 $205,645 $141,416 $2,816 $5,861 $544 $20,801 $3,611 


dep Depreciation and Amortization (dep) $2,036,190 $919,463 $358,860 $615,305 $65,694 $42,857 $2,456 $25,306 $6,249 

INPUT PILs (INPUT) $1,339,573 $593,094 $233,996 $414,611 $48,251 $27,609 $1,581 $16,383 $4,048 

INT Interest $1,268,744 $561,735 $221,624 $392,689 $45,700 $26,149 $1,498 $15,516 $3,834 


Direct Allocation $9,000 $8,820 $0 $0 $0 $0 $0 $180 $0 





Net Assets 


gp General Plant - Gross $4,573,711 $2,042,563 $802,664 $1,397,929 $158,742 $95,891 $5,494 $56,375 $14,053 

accum dep Accumulated Depreciation ($28,828,157) ($12,810,143) ($5,054,843) ($8,961,502) ($941,891) ($587,324) ($33,624) ($352,999) ($85,831) 

co Capital Contribution ($1,384,370) ($722,940) ($265,188) ($317,708) ($12,267) ($38,712) ($2,229) ($19,687) ($5,640) 




OM&A Expenses $3,250,875 $2,009,362 $567,009 $504,877 $42,454 $58,051 $3,674 $52,702 $12,747 

Directly Allocated Expenses $9,000 $8,820 $0 $0 $0 $0 $0 $180 $0 

Subtotal $45,907,986 $11,539,422 $5,389,606 $22,895,233 $5,314,744 $312,353 $15,070 $341,655 $99,904 




Net Income on Allocated Assets $1,574,991 $941,976 $293,894 $301,474 $183,482 ($100,504) ($6,484) ($31,816) ($7,030) 


Net Income $1,574,991 $941,976 $293,894 $301,474 $183,482 ($100,504) ($6,484) ($31,816) ($7,030) 




EXISTING REVENUE MINUS ALLOCATED COSTS ($1) $244,650 $18,775 ($186,002) $126,752 ($132,966) ($8,344) ($51,077) ($11,790) 

RETURN ON EQUITY COMPONENT OF RATE BASE 9.01% 13.29% 10.28% 4.97% 20.30% -32.10% -36.60% -16.11% -14.07%


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

RATE DESIGN OVERVIEW: 

This Exhibit documents the calculation of Festival Hydro’s proposed distribution rates by rate 

class for the 2010 test year, based on rate design as proposed in this Exhibit. 

Festival Hydro has determined its total 2010 service revenue requirement to be $10,511,581. 

The total revenue offsets in the amount of $659,450 reduce Festival Hydro’s total service 

revenue requirement to a base revenue requirement to $9,852,130 which is used to determine 

the proposed distribution rates. The base revenue requirement is derived from Festival 

Hydro’s 2010 capital and operating forecasts, weather normalized usage, forecasted customer 

counts, and Festival Hydro’s regulated return on rate base. The revenue requirements are 

summarized below in Table 1: 

Table 1 

Calculation of Base Revenue Requirement 

OM&A Expenses & Taxes 4,018,664 

Amortization Expenses 2,655,496 

Total Distribution Expenses 6,674,159 

Regulated Return On Capital 2,928,832 

PILs 908,589 

Service Revenue Requirement 10,511,581 

Rate Determination Constants/Options For Test Year 

Service Revenue Requirement $ 10,511,581 

Less: Revenue Offsets $ 

659,450 

Total Base Revenue Requirement $ 

9,852,131 

15 

16 

Addback LV Charges $ 

81,437 

Addback Transformer Allowances $ 

383,134 

Gross Revenues For Rates $ 10,316,701 

17


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

The outstanding base revenue requirement is allocated to the various rate classes using the 

following proposed apportionment of revenue as outlined in Exhibit 8 – Cost Allocation. 

Proposed Apportionment of Revenue to Rate Class: 

As explained in of Exhibit 8 of the 2010 Rate application, the original 2006 Cost of Service 

Model has been updated to reflect 2010 test year data included forecasted assets balances, loss 

factors, deemed capital structure and 2010 income and expenses, with transformer allowances 

removed from the revenue requirement. Rather than complete a full weather normalization 

study, the load profiles from the 2006 study have been updated and scaled to match the 2010 

load forecast. The table below provides the proposed apportionment of Revenue to Rate 

Classes. Those classes which were below the OEB minimum target were increased by 50% of 

the difference between the existing apportionment and the OEB minimum target. (i.e. General 

Service > 50 kW, street lighting and sentinel lights). The offset was applied first to those 

classes which were above the targets (USL) and the residual to Large Use, General Service < 

50 kW and Residential. Residential Hensall was increased from 71.52% cost to revenue ratio 

to 91.21%, to allow for further rate harmonization with the objective at some time mainlining 

one residential rate. The increases for street lighting and sentinel lights are quite large, but 

are not so significant as to warrant any mitigation measures. Table 2 provides the % 

apportionment by rate class.


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 1 



1 

2 

3 

4 

Table 2 

Proposed Apportionment of Revenue to Rate Classes 

Customer Class 

Existing 

Rates 

Rate 


5 

6 

7 

Residential 55.43% 55.02% 

Residential - Hensall 0.92% 1.20% 

GS < 50 kW 17.27% 16.68% 

GS >50 21.95% 22.51% 

Large Use 3.38% 3.20% 

Sentinel Lights 0.04% 0.07% 

Street Lighting 0.62% 1.00% 

USL 0.40% 0.33% 

TOTAL 100.00% 100.00% 

The following Table 3 outlines the impact of the apportionment on Festival Hydro’s revenue 

requirements. 

8


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 1 



1 

2 

3 

Table 3 

Allocation of Outstanding Base Revenue Requirement 

4 

5 

6 

7 

8 

9 

10 

11 


Existing 

Rates 

Rate 


Existing 

Rates 

Rate 


Residential 55.43% 55.02% 5,460,632 5,420,642 

Residential - Hensall 0.92% 1.20% 90,764 118,226 

GS < 50 kW 17.27% 16.68% 1,701,462 1,643,335 

GS >50 21.95% 22.51% 2,162,368 2,217,222 

Large Use 3.38% 3.20% 333,164 315,268 

Sentinel Lights 0.04% 0.07% 3,989 6,699 

Street Lighting 0.62% 1.00% 60,786 98,521 

USL 0.40% 0.33% 38,965 32,216 

TOTAL 100.00% 100.00% 9,852,131 9,852,131 

Determination of Monthly Fixed/Volumetric Charges: 

Festival Hydro’s current OEB-approved (2009 IRM) volumetric and monthly fixed charges 

are summarized in Table 4 as follows. 

Table 4 

Current Monthly Fixed and Volumetric Charges (excludes smart meters) 

Customer Class Connection Customer kW kWh 

Residential 14.09 0.0158 

Residential - Hensall 9.03 0.0099 

GS < 50 kW 28.11 0.0142 

GS >50 209.76 2.2603 

Large Use 10,447.04 1.0931 

Sentinel Lights 0.79 4.1925 

Street Lighting 0.45 2.0977 

USL 14.06 0.0142 

Transformer Allowance (0.6000)


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 1 



1 

2 

3 

4 

Using the existing approved fixed charges applied to the forecasted number of customers for 

2010 and the approved volumetric charge applied to the forecasted volumetric billing 

determinants, the following Table 5 details the calculation of the current split between fixed 

and variable distribution revenue. 

Table 5 

Determination of Current Fixed/Variable Proportions 

Fixed 

Distribution 

Revenue 

Variable 


Revenue 

Dist. Rev. 

Including 


Dist. Rev. 

Excluding 


Dist Rev At 

Existing Rates 

% 

Class 

Annual kWh 

Annual kW 

For Dx 

Annualized 

Customers 

Annualized 

Connections 


Allowance 

Current Fixed 

Charge Portion 

Current Variable 

Charge Portion 

Residential 129,737,473 205,383 2,893,848 2,023,905 4,917,753 4,917,753 55.43% 58.84% 41.16% 

Residential - Hensall 3,808,598 4,961 44,797 36,943 81,741 81,741 0.92% 54.80% 45.20% 

GS < 50 kW 62,021,896 23,622 664,002 868,307 1,532,308 1,532,308 17.27% 43.33% 56.67% 

GS >50 310,990,652 782,812 2,646 555,082 1,698,232 2,253,314 305,922 1,947,393 21.95% 24.63% 75.37% 

Large Use 65,544,852 128,687 24 250,729 126,525 377,254 77,212 300,042 3.38% 66.46% 33.54% 

Sentinel Lights 234,690 679 996 787 2,805 3,592 3,592 0.04% 21.91% 78.09% 

Street Lighting 3,904,130 11,255 70,990 31,946 22,797 54,743 54,743 0.62% 58.36% 41.64% 

USL 629,732 1,869 26,275 8,816 35,091 35,091 0.40% 74.88% 25.12% 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

576,872,024 923,433 236,636 73,855 4,467,467 4,788,330 9,255,797 383,134 8,872,663 100% 48.27% 51.73% 

Festival Hydro proposes that it is appropriate for 2010 to maintain the same fixed/variable 

proportions assumed in the current rates for all customer classifications. 

In its November 28, 2007 Report on Application of Cost Allocation for Electricity 

Distributors, referred to in Exhibit 8 above, the OEB addressed a number of “Other Rate 

Matters”, including the treatment of the fixed rate component (the Monthly Service Charge, or 

“MSC”) of the bill. At page 12 of the Report, the OEB determined that the floor amount for 

the MSC should be the avoided costs, as that term is defined in the September 29, 2006 report 

of the OEB entitled “Cost Allocation: Board Directions on Cost Allocation Methodology for 

Electricity Distributors”. Festival Hydro’s MSCs for all rate classes exceed that floor amount. 

With respect to the upper bound for the MSC, the OEB considered it to be inappropriate to 

make changes to the MSC ceiling at this time, given the number of issues that remain to be 

examined within the scope of the OEB’s Rate Review proceeding (EB-2009-0031). The OEB 

indicated that for the time being, it does not expect distributors to make changes to the MSC 

that result in a charge that is greater than the ceiling as defined in the Methodology for the


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

MSC; and that distributors that are currently above that value are not required to make 

changes to their current MSC to bring it to or below that level at this time. 

Until the OEB’s Rate Review proceeding (EB-2009-0031) is completed and consistent other 

2009 rate application approvals, Festival Hydro submits that an MSC ceiling has not been 

established and that it is appropriate for the purposes of setting rates in this Application to 

maintain the current fixed and variable proportions. Below is a copy of the Monthly Fixed 

Charge minimum and maximum worksheet which shows Festival Hydro’s 2010 Cost of 

Service Study results compared to the OEB recommended minimums and maximums. 



EB-2005-0364 EB-2007-0002 

Friday August 28, 2009 

Sheet O2 Monthly Fixed Charge Min. & Max. Worksheet - Second Run 2010 - Run 2 Model 

Output sheet showing minimum and maximum level for 

Monthly Fixed Charge 

1 2 3 6 7 8 9 10 

Summary Residential GS 50-Regular Large Use >5MW Street Light Sentinel 

Hensall 

Residential 

Unmettered 


Customer Unit Cost per month - Avoided Cost $4.83 $9.81 $84.40 $221.36 $0.80 $0.99 $5.11 $1.54 

Customer Unit Cost per month - Directly Related $7.22 $14.78 $126.42 $320.01 $1.35 $1.63 $7.53 $2.74 

Customer Unit Cost per month - Minimum System 

with PLCC Adjustment 

$16.80 $28.03 $151.80 $1,390.03 $9.31 $9.24 $17.14 $6.96 

9 

10 

Fixed Charge per approved 2006 EDR $15.09 $29.11 $210.76 $10,448.04 $0.45 $0.79 $10.03 $14.06 

11 

12 

13 

14 

Proposed Fixed Monthly Charges: 

The following Table 6 provides Festival Hydro’s calculations of its proposed monthly fixed 

distribution charges for the 2010 Test Year assuming the fixed/variable split supporting the 

current approved rates. 

15 

16


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 


Table 6 

Proposed Fixed Distribution Charge 

Total Base Rev. 

Requirement 

(exclude LV) 

Current Fixed 

Charge 

Proportion 


Customers/ 

Connections 

Proposed Fixed 


Charge 

Residential 5,420,642 58.84% 17,115 $ 

15.53 

Residential - Hensall 118,226 54.80% 413 $ 

13.06 

GS < 50 kW 1,643,335 43.33% 1,968 $ 

30.15 

GS >50 2,523,144 24.63% 221 $ 206.40 

Large Use 392,480 66.46% 2 $ 8,730.51 

Sentinel Lights 6,699 21.91% 83 $ 

1.47 

Street Lighting 98,521 58.36% 5,916 $ 

0.81 

USL 32,216 74.88% 156 $ 

12.91 

TOTAL 10,235,264 25,874 

Proposed Volumetric Charges: 

The variable distribution charge is calculated by dividing the variable distribution portion of 

the base revenue requirement by the appropriate 2010 Test Year usage, kWh or kW, as the 

class charge determinant. 

The following Table 7 provides Festival Hydro’s calculations of its proposed variable 

distribution charges for the 2010 Test Year assuming the same fixed/variable split used in 

designing the current approved rates. 

12 

13


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 


Table 7 

Proposed Volumetric Distribution Charge 

Total Base Rev. 

Requirement 

Variable 

Revenue 

Proportion 


kWh/kW 

Proposed 

Volumetric Dist 

Charge 

Residential 5,420,642 41.16% 129,737,473 $ 0.01720 kWh 

Residential - Hensall 118,226 45.20% 3,808,598 $ 0.01400 kWh 

GS < 50 kW 1,643,335 56.67% 62,021,896 $ 0.01500 kWh 

GS >50 2,523,144 75.37% 782,812 $ 2.52550 kW 

Large Use 392,480 33.54% 128,687 $ 1.42170 kW 

Sentinel Lights 6,699 78.09% 679 $ 7.70540 kW 

Street Lighting 98,521 41.64% 11,255 $ 3.64530 kW 

USL 32,216 25.12% 629,732 $ 0.01290 kWh 

TOTAL 10,235,264 

Proposed Distribution Rates: 

The following Table 8 sets out Festival Hydro’s proposed 2010 electricity distribution rates 

based on the foregoing calculations, including adjustments for the recovery of transformer 

allowance. It does not include the smart meter rate adder of $1.00/month, the regulatory asset 

rate rider or the low voltage cost recovery adder. 

Basis 

10


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

Table 8 

Proposed 2010 Electricity Distribution Rates 

2010 TEST YEAR - BASE REVENUE DISTRIBUTION RATES 

Customer Class Connection Customer kW kWh 

Residential 15.53 0.0172 

Residential - Hensall 13.06 0.0140 

GS < 50 kW 30.15 0.0150 

GS> 50 kW 206.40 2.5255 

Large Use 8,730.51 1.4217 

Sentinel Lights 1.47 7.7054 

Street Lighting 0.81 3.6453 

USL 12.91 0.0129 

Adjustment to Transformer Allowance: 

Currently, Festival Hydro provides a Transformer Allowance to those customers that own 

their transformation facilities. Festival Hydro proposes to maintain the current approved 

transformer ownership allowance of $0.60 per kW. The Transformer Allowance is intended to 

reflect the costs to a distributor of providing step down transformation facilities to the 

customer’s utilization voltage level. Since the distributor provides electricity at utilization 

voltage, the cost of this transformation is captured in and recovered through the distribution 

rates. Therefore, when a customer provides its own step down transformation from primary to 

secondary, it should receive a credit of these costs already included in the distribution rates. 

The General Service > 50 kW and Large Use rates have been adjusted for transformer 

allowances based on the proportion of projected 2010 kW sold which are subject to the 

transformer allowance. 

18


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

Low Voltage Cost Recovery Adder: 

Festival Hydro is a partially embedded distributor. On June 8, 2009, Festival Hydro received 

from Hydro One their new distribution rates effective May 1, 2009. The new rates are 

substantially lower than the rates charged previous to May 1, 2009. As a result, the low 

voltage rate riders charged to our customers have been adjusted downward accordingly. To 

determine the new rates to be charged, Festival Hydro applied the new Hydro One rates to 

historical usages to derive estimated total annual low voltage charges from Hydro One. The 

calculations are in Table 9 below. 

Table 9 

Calculation of Low Voltage Charges from Hydro One for Test Year 2010 

LV charges for 2010 Test Year based on new LV rates June 1, 2009: 

KW subject to LV Charges 

Total kW of embedded distribution 233,782.00 

Seaforth (1) 97,565.00 

Brussels (2) 16,191.00 

Grand Bend (3) 19,101.00 

Remaining locations (4) 100,925.00 June 1, 2009 LV charges 

Total kW for embedded locations 233,782.00 L.V. Rates for the year 

11 

12 

13 

14 

15 

16 

kW with Common ST Lines Charge (1,2,3) 116,666.00 0.35 40,833.10 

kW with Inc Capital (1,2,3) 116,666.00 0.021 2,449.99 

kW with LVDS (2) 16,191.00 0.78 12,628.98 

kW with HVDS High (3) 19,101.00 0.89 16,999.89 

Monthly Service charge (1,2,3,4) 6.00 118.4 8,524.80 

Test Year 2010 LV charges, with new rates effective June 1, 2009 81,436.76 

The annual low voltage charges of $81,436 have been allocated to each class based on 

historical amounts collected from each rate class. Festival Hydro accumulated the amounts 

collected from each class for the period May 1, 2006 to December 31, 2008 and used the 

percentage contributed to apportion the projected charges to each class, as outlined in Table 

10.


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 1 



1 

Table 10 

Low Voltage Costs Allocated by Customer Class 

Low Voltage Charges Collected from customers 2006 to 


2008 at approved rates 

Allocation 

2006 2007 2008 

Total Percentages Allocated $ 

Residential 15,182.00 27,638.00 27,358.00 70,178.00 20.42% 16,627.35 

Residential - Hensall 411.00 801.00 794.00 2,006.00 0.58% 475.28 

GS < 50 kW 7,666.00 13,920.00 13,431.00 35,017.00 10.19% 8,296.61 

GS> 50 40,233.00 77,953.00 76,934.00 195,120.00 56.77% 46,229.99 

GS> 50 interval (in above) - - - 0.00 0.00% 0.00 

Large Use 8,119.00 15,519.00 15,345.00 38,983.00 11.34% 9,236.28 

Sentinel Lights 446.00 769.00 735.00 1,950.00 0.57% 462.02 

Street Lighting 19.00 37.00 34.00 90.00 0.03% 21.32 

USL 88.00 149.00 134.00 371.00 0.11% 87.90 

2 

3 

TOTALS 72,164.00 136,786.00 134,765.00 343,715.00 100.00% 81,436.76 

4 

5 

6 

7 

8 

9 

As stated in Chapter 3 of the Filing Requirements for Transmission and Distribution 

Applications dated July 22, 2009, for all 2010 rate applications and going forward, the Board 

has determined that the rate to recover the low voltage costs will be explicitly shown on the 

Distributor’s Tariff of Rates and Charges, identified as the Low Voltage Cost Recovery 

Adder. Festival Hydro requests the approval of the proposed Low Voltage Cost Recovery 

Adders as shown in Table 11. 

10


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 1 



1 

2 

Table 11 

RATES - Low Voltage Cost Recovery Adder 


LV Adj. 

Allocated 

Calculated kWh 

Calculated 

kW 

Volumetric 

Rate Type 

LV/ Adj. 

Rates/kWh 

Residential 16,627.35 129,737,473 kWh 0.0001 

Residential - Hensall 475.28 3,808,598 kWh 0.0001 

GS < 50 kW 8,296.61 62,021,896 kWh 0.0001 

LV Adj. 

Rates/ 

kW 

GS> 50 kW 46,229.99 310,990,652 782,812 kW 0.0591 

Large Use 9,236.28 65,544,852 128,687 kW 0.0718 

Sentinel Lights 462.02 234,690 679 kW 0.6805 

Street Lighting 21.32 3,904,130 11,255 kW 0.0019 

USL 87.90 629,732 kWh 0.0001 

TOTALS 81,436.76 576,872,024 923,433 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

DETERMINATION OF LOSS ADJUSTMENT FACTORS: 

Total Loss Factor: 

Festival Hydro is a partially embedded distributor. It has metering points in the City of 

Stratford and Town of St. Marys which are directly connected to the IESO controlled grid. 

Festival Hydro is embedded with Hydro One as the host distributor for the smaller towns in 

Festival’s service territory (Dashwood, Seaforth, Brussels, Zurich, and Hensall). 

Festival Hydro has calculated the total loss factor to be applied to customers’ consumption 

based on the average wholesale and retail kWh for the past five years - 2004 to 2008. The 

calculations are summarized in Appendix 2-Q below. 

13


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 1 



1 

2 

3 

Appendix 2-Q 

Loss Factors 

Appendix 2 - Q Loss Factors 

Modified Schedule 10-5: Determinationof Loss Factors 

2004 2005 2006 2007 2008 5 Year Average 

A1 "Wholesale" kWh delivered to distributor (higher value) 649,308,540 650,800,740 635,441,692 634,322,920 611,667,199 636,308,218 

A2 "Wholesale" kWh delivered to distributor (lower value) 644,449,392 646,228,119 630,640,682 629,594,889 607,112,091 631,605,035 

B "Wholesale" kWh delivered to LDC for Large Use customer(s) 77,155,267 75,234,718 75,667,613 70,296,308 68,098,590 73,290,499 

C Net "Wholesale" kWh delivered to LDC(A2)-(B) 567,294,124 570,993,402 554,973,069 559,298,581 539,013,501 558,314,535 

D "Retail" kWh deliered by the Distributor 632,340,069 632,444,846 617,899,375 615,535,179 593,387,454 618,321,385 

E Portion of "Retail" kWh for Large Use Customer(s) 76,391,354 74,489,819 74,918,429 69,600,305 67,424,347 72,564,851 

F Net "Retail" kWh (delivered to LDC (D)-(E) 555,948,715 557,955,027 542,980,946 545,934,874 525,963,107 545,756,534 

G Loss Factor in distributors system [(C)/(F)] 102.04% 102.34% 102.21% 102.45% 102.48% 102.30% 

Losses Upstream of Distributor's System 

H Supply Facility Loss Factor (A1/A2) 100.75% 100.71% 100.76% 100.75% 100.75% 100.75% 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

Supply Facility Loss Adjustment Factor (5 year avg.) 100.75% 

I Total Loss Factor (G)x(H) 1.0307 

Supply Facility Loss Factor: 

The supply facility loss factor (the “SFLF”) calculation shown in Appendix 2- Q represents 

the losses on supply to Festival Hydro. The SFLF is calculated on the measured quantities 

between the transformer stations and the wholesale meter points. Since Festival Hydro is 

partially embedded, its SFLF is the weighted average of 1.0045 charged for the IESO 

connected points and 1.0340 for the embedded metering points. 

Based on historical data from the past 5 years, Festival Hydro is requesting an increase in its 

SFLF to 1.0075 for the current SFLF of 1.0045. 

Distribution Loss Factor: 

As a result of ongoing 4 kV infrastructure conversions to 27 kV, Festival Hydro is requesting 

a slight reduction in its distribution loss factor for both secondary metered less than 5,000 kW 

and primary metered less than 5,000 kW, from 1.0235 to 1.0230 and 1.0133 to 1.0128, 

respectively. 

19


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 1 



1 

2 

3 

4 

5 

6 

Total Loss Factor by Class: 

Table 12 sets out the class-specific Loss Factors used by Festival Hydro in the calculation of 

commodity and other non-distribution charges. 

Table 12 

Total Loss Factor by Class 

Total Utility Loss Adjustment Factor 2010 Proposed LAF 2006 Approved LAF 

Supply Facility Loss Factor 1.0075 1.0045 

7 

8 

Distribution Loss Factor 

Distribution Loss Factor - Secondary Metered < 5,000kW 1.0230 1.0235 

Distribution Loss Factor - Secondary Metered > 5,000kW 1.0100 1.0100 

Distribution Loss Factor - Primary Metered < 5,000kW 1.0128 1.0133 

Distribution Loss Factor - Primary Metered > 5,000kW 1.0000 1.0000 

Total Loss Factor 

Total Loss Factor - Secondary Metered < 5,000kW 1.0307 1.0281 

Total Loss Factor - Secondary Metered > 5,000kW 1.0176 1.0145 

Total Loss Factor - Primary Metered < 5,000kW 1.0204 1.0178 

Total Loss Factor - Primary Metered > 5,000kW 1.0075 1.0045 

9 

10 

11 

12 

13 

14 

15 

16 

17 

Due to changes in both the SFLF and distribution loss factors, Festival Hydro’s is requesting 

the following changes to the Total Loss Adjustment factors, as shown in Table 12: 

for secondary metered less than 5,000 kW, to be increased slightly to 1.0307 from the 

current rate of 1.0281. (This applies to most of our customers). 

for secondary metered greater than 5,000 kW, to be increased slightly to 1.0176 from 

the current rate of 1.0145 (Festival Hydro currently has no customers in this class). 

for primary metered less than 5,000 kW, to be increased to 1.0204 from the current rate 

of 1.0178. (There are approximately 22 customers in this class).


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

for primary metered greater than 5,000 kW, continue to charge the SFLF which 

Festival Hydro proposed to be 1.0075 from the previous SFLF of 1.0045. (Festival 

Hydro has two customers in this class). 

Materiality Analysis on Distribution Losses: 

Pursuant to the Filing Requirements, as the Total Loss Adjustment factor is less than 5%, 

Festival Hydro is not required to provide a explanation of, or justification for, its loss 

adjustment factor. Since Festival Hydro currently has been building up a debit balance in its 

Cost of Power variance accounts (ignoring sub account Global Adjustment), this would 

suggest our loss factor currently charged may be slightly undervalued and should be increased.


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 2 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

RATE MITIGATION: 

Festival Hydro has submitted our rate application which includes only one rate class with a 

total bill impact in excess of 10%. Sentinel lighting has a total bill impact of approximately 

13.4%. For the entire class, this represents a $264.51 increase in the total monthly bill for all 

sentinel lights. Considering there are approximately 64 customers (with a total 83 

connections), this works out to an average of approximately $4.13 per customer increase on a 

monthly basis. Festival Hydro believes this should not create an undue hardship for these 

customers and request that the proposed rate increase of 13.4% be accepted by the Board. 

Further rate harmonization for the Hensall residential rate class has been accomplished 

through Cost Allocation. With the proposed 2010 rates, Hensall Residential will be at revenue 

to cost ratio of 91.21%, which is still lower than 107.70% for regular residential customers. By 

increasing the cost to revenue ratio to 91.21%, it creates a final bill impact (along with all 

other changes) of 7.46% ($6.72 per month) for a customer using 800 kWh and a 9.79% ($5.78 

per month) for a customer using 500 kWh. For the average Hensall residential customer the 

impact on the total bill is less than 10%.


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 3 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

OTHER ELECTRICITY CHARGES: 

Festival Hydro proposes to keep the rates for Wholesale Market Service, Rural Rate Protection 

Charge, and Standard Supply Service – Administrative Charge as approved by the OEB in 

EB-2007-0855 (2009 rates). 

Retail Transmission Service Rates (RTSRs): 

On July 22, 2009, the Ontario Energy Board issued G-2008-0001 Guideline Electricity 

Distribution Transmission Service Rates, which provides electricity distributors with 

instructions on the evidence needed, and the processes to be used, to adjust retail transmission 

service rates to reflect changes in the Ontario Uniform Transmission Rates (UTRs). The new 

UTRs effective July 1, 2009, are as follows: 

Network Service Rate – increased from 2.57 kW to $2.66 per K w per month, a 3.5% 

increase. 

13 

 

Line Connection Service Rate – unchanged at .70 per kW 

14 

15 

16 

 

Transformation Connection service rate – decreased from $1.62 per kW to 1.57 per 

kW, a 2.2 % decrease. If you add the connection rates together, they have a net 

decrease of 2.16%. 

17 

18 

19 

20 

21 

22 

23 

24 

25 

The adjustment to the RTSRs for Festival Hydro’s 2010 rate year is based on the specific rate 

changes noted above, as well as the recent trends in the deferral accounts. In completing our 

analysis, Festival Hydro’s reviewed the collected from each rate class to the amounts paid to 

the IESO/Hydro One over the past two and one half years. The reason for looking in 

particular at the first six months of 2009 is because there was an increase in RTSR rates takes 

place May 1, 2008 and May 1, 2009, so these most recent trends are valuable in our analysis. 

Table 13 provides the data analysis completed for the past two and one half year. In 

determining our new RTSR rates, Festival Hydro ignored the 2007 data because there have


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 3 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

been two RTSR rate changes since and the data from 2007 does not reflect our current trend in 

amounts collected versus amounts charged. The 2008 and 2009 data Festival Hydro believes 

better reflects the trends to be taken into consideration when setting the new rates. Based on 

our experience for the past one and one half years, we applied the new rate changes (Network 

3.5% increase, combined Connection 2.16% decrease) to determine our projected annual 

charges from the IESO/Hydro One. Based on the amounts collected from each rate class over 

the past one and a half years, the new charge was allocated proportionally. With the total 

charge for each class determined, the rate per kWh/kW was calculated based on the 2010 

forecasted load data. 

2007 Data by Class - kWh/kW sold and 

charges collected 

Table 13 

Proposal for Revised Network and Connection Charges 

Total Network Charged 

kW for Network kW for Connection kWh >< 

to customers 

Connection 

Service Rate 

Total Connection 

Charged to 

customers 

Residential 142,071,278 0.0057 $809,806 0.0050 $710,356 

Residential - Hensall 4,114,075 0.0057 $23,450 0.0050 $20,570 

G.S. < 50 kW 71,557,976 0.0052 $372,101 0.0045 $322,011 

G.S. 50 kW to 4999 kW 151,327 151,327 2.1218 $321,086 1.7882 $270,603 

G.S. 50 kW to 4999 kW (interval Metered) 679,634 706,245 2.2535 $1,538,458 1.9603 $1,390,462 

Larger Use 141,214 141,214 2.4952 $352,358 2.2417 $316,560 

Unmetered Scattered Load 768,594 0.0052 $3,997 0.0045 $3,459 

Sentinel Lighting 626 626 1.6083 $1,007 1.4113 $883 

Street Lighting 10,646 10,646 1.6002 $17,036 1.3824 $14,717 

13 

14 

TOTALS 983,448 1,010,059 218,511,924 $3,439,300 $3,049,623 

Less: Billed by the IESO and Hydro One $3,178,481 $2,737,460 

Overcharge to customers $260,819 $312,163 

8.21% 11.40% 


charges collected 



to customers 

Connection 

Service Rate 


Charged to 

customers 

Residential 140,510,280 0.0057/.0049 $740,252 0.005/.0040 $626,831 

Residential - Hensall 4,128,179 0.0057/.0049 $21,877 0.005/.0040 $18,574 

G.S. < 50 kW 0 0 69,020,413 0.0052/.0044 $328,802 0.0045/.0036 $276,723 

G.S. 50 kW to 4999 kW 167,021 167,011 2.1218/1.8099 $322,229 1.7882/1.4252 $261,243 

G.S. 50 kW to 4999 kW (interval Metered) 656,029 679,338 2.2535/1.9222 $1,337,542 1.9603/1.5624 $1,160,730 

Larger Use 139,635 139,635 2.4952/2.1284 $318,227 2.2417/1.7866 $275,562 

Unmetered Scattered Load 685,262 0.0052/.0044 $3,241 0.0045/.0036 $2,721 

Sentinel Lighting 606 606 1.6083/1.3719 $885 1.4113/1.1248 $749 

Street Lighting 10,180 10,180 1.6002/1.365 $14,595 1.3824/1.1018 $12,050 

15 

16 

TOTALS 973,472 996,771 214,344,133 $3,087,650 $2,635,182 



20.26% 6.78%


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 3 




charges collected to Jun 30/09 



to customers 

Connection 

Service Rate 


Charged to 

customers 

Residential 74,978,129 0.0049/.0055 $372,672 0.0040/.0042 $301,671 

Residential - Hensall 2,196,134 0.0049/.0055 $10,869 0.0040/.0042 $8,820 

G.S. < 50 kW 34,922,056 .0044/.0049 $155,651 0.0036/.0038 $126,512 

G.S. 50 kW to 4999 kW 78,767 78,767 1.8099/2.0144 $143,846 1.4252/1.5036 $112,752 

G.S. 50 kW to 4999 kW (interval Metered) 323,111 333,777 1.9222/2.1394 $621,639 1.5624/1.6483 $521,712 

Larger Use 56,238 56,238 2.1284/2.3689 $119,696 1.7866/1.8849 $100,474 

Unmetered Scattered Load 349,620 .0044/.0049 $1,603 .0036/.0038 $1,303 

Sentinel Lighting 305 305 1.3719/1.5269 $415 1.1248/1.1867 $342 

Street Lighting 6,338 6,338 1.365/1.5192 $8,930 1.1018/1.1624 $7,093 

1 

2 

TOTALS 464,759 475,424 112,445,939 $1,435,322 $1,180,679 


Overcharge to customers $160,412 -$40,562 

12.58% -3.32% 


2008 to July 2009 - Totals for 18 months kW for Network kW for Connection kWh >< 

to customers 

Connection 

Service Rate 


Charged to 

customers 

Residential 215,488,409 0.0049/.0055 1,112,924 0.0040/.0042 928,502 

Residential - Hensall 6,324,313 0.0049/.0055 32,746 0.0040/.0042 27,394 

G.S. < 50 kW 103,942,469 .0044/.0049 484,453 0.0036/.0038 403,235 

G.S. 50 kW to 4999 kW 245,788 245,778 1.8099/2.0144 466,075 1.4252/1.5036 373,994 

G.S. 50 kW to 4999 kW (interval Metered) 979,141 1,013,115 1.9222/2.1394 1,959,180 1.5624/1.6483 1,682,441 

Larger Use 195,873 195,873 2.1284/2.3689 437,924 1.7866/1.8849 376,036 

Unmetered Scattered Load 0 0 1,034,882 .0044/.0049 4,844 .0036/.0038 4,024 

Sentinel Lighting 911 911 1.3719/1.5269 1,300 1.1248/1.1867 1,091 

Street Lighting 16,518 16,518 1.365/1.5192 23,525 1.1018/1.1624 19,143 

3 

4 

TOTALS 1,438,231 1,472,195 326,790,072 $4,522,972 $3,815,861 

Less: Billed by the IESO and Hydro One 3,842,469 3,689,128 


17.71% 3.44% 

Rate reduction required to retail transmission Rates: Network Connection 

Total charged by IESO/Hydro One over past one year, 6 months $3,842,469 $3,689,128 

Network - 3.5 % increase due to most recent rate order/Connection combinded decrease of 2.16% $134,486 -$79,685 

Amount needed to be recovered through customer rates on a go forward basis $3,976,955 $3,609,443 

Annualized $2,651,303 $2,406,295 

5 

6 

Check for reasonableness: June 2009 year to date billed by the IESO/Hydro One times 2 $2,549,821 $2,442,483 

Add: Network - 3.5 % increase due to most recent rate order/Connection combinded decrease of 2.16% $89,244 -$52,758 

Net expected charges for 2010 $2,639,064 $2,389,726 

2010 Test year kWh/kW kW for Network kW for Connection kWh 

Calculated 

Proposed 

Network Rate 


to customers 

Calculated 

Proposed 

Connection Rate 


Charged to 

customers 

Residential 133,720,413 0.0049 $652,381 0.0044 $585,517 

Residential - Hensall 3,925,522 0.0049 $19,195 0.0044 $17,275 

G.S. < 50 kW 63,925,968 0.0044 $283,980 0.0040 $254,281 

G.S. 50 kW to 4999 kW 167,021 167,011 1.6358 $273,207 1.4121 $235,842 

G.S. 50 kW to 4999 kW (interval Metered) 615,791 615,801 1.8650 $1,148,444 1.7229 $1,060,953 

Larger Use 128,687 128,687 1.9948 $256,705 1.8427 $237,130 

Unmetered Scattered Load 629,732 0.0045 $2,840 0.0040 $2,537 

Sentinel Lighting 679 679 1.1226 $762 1.0136 $688 

Street Lighting 11,255 11,255 1.2252 $13,790 1.0725 $12,071 

7 

8 

TOTALS 923,433 923,433 202,201,636 $2,651,303 $2,406,295 

Amount allocated to each rate group 2,651,303 2,406,295


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 3 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

Even though the UTR network service rate is going up by 3.5%, Festival Hydro is in fact 

requesting a reduction in their network RTSR rate because of the trend in the variance 

account. Festival Hydro has over-collected annually from its customers ever since market 

opening in 2002. A reduction in the network rate charged was implemented as part of our 

2008 rate application, but the reduction wasn’t sufficient as we have continued to overcharge 

customers. As a result, Festival hydro is requesting a reduction in the retail network rates, in a 

range of 9.3% to 26.5% so as to cease the overcharging to customers. Tables 14 and 15 below 

shows the proposed changes in rate per customer class and percentage impact. 

The combined UTR Connection charges are decreasing by 2.16%. With each class continuing 

their proportionate share of the costs, some classes have an increase to their rates while others 

will have a decrease. All classes which are kWh based plus the interval metered general 

service > 50KW class will see an increase in the range of 2.9% to 4.8% increase. The 

remaining kW charged rates will be decreased in the range of 2.2% to 14.67 %. The use of the 

2010 forecasted loads in setting these rates have directly impacted the increase/decrease in 

rates for each class. Tables 14 and 15 below shows the proposed changes in rate per customer 

class and percentage impact. 

Festival Hydro request that the RTSR rates as presented in Table 14 and 15 be approved 

by the Board. 

Proposed 2010 Network Rate Sheet 

Table 14 

Proposed 2010 Network Rates 

Existing Network 

Rate( kWh billed) 

Existing Network Proposed Network 

Rate( kW billed) Rate( kWh billed) 

Proposed 

Network Rate 

( kW billed) 

Reduction in rate 

Percentage 

Reduction 

Residential 0.0055 0.0049 0.0006 11.3% 

Residential - Hensall 0.0055 0.0049 0.0006 11.1% 

G.S. < 50 kW 0.0049 0.0044 0.0005 9.3% 

G.S. 50 kW to 4999 kW 2.0144 1.6358 0.3786 18.8% 

G.S. 50 kW to 4999 kW (interval Metered) 2.1394 1.8650 0.2744 12.8% 

Larger Use 2.3689 1.9948 0.3741 15.8% 

Unmetered Scattered Load 0.0049 0.0045 0.0004 8.0% 

Sentinel Lighting 1.5269 1.1226 0.4043 26.5% 

Street Lighting 1.5192 1.2252 0.2940 19.4%


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 3 



1 

2 

3 

Proposed 2010 Connection Rate Sheet 

Table 15 

Proposed 2010 Connection Rates 

Existing Connection 

Rate( kWh billed) 

Existing 


( kW billed) 

Proposed 


( kWh billed) 

Proposed 

Connection 

Rate ( kW 

billed) 

Reduction (increase) 

in rate 

Percentage 

Reduction 

(Increase) 

4 

5 

6 

7 

8 

9 

Residential 0.0042 0.0044 (0.0002) -4.3% 

Residential - Hensall 0.0042 0.0044 (0.0002) -4.8% 

G.S. < 50 kW 0.0038 0.0040 (0.0002) -4.7% 

G.S. 50 kW to 4999 kW 1.5036 1.4121 0.0915 6.1% 

G.S. 50 kW to 4999 kW (interval Metered) 1.6483 1.7229 (0.0746) -4.5% 

Larger Use 1.8849 1.8427 0.0422 2.2% 

Unmetered Scattered Load 0.0038 0.0040 (0.0002) -6.0% 

Sentinel Lighting 1.1867 1.0136 0.1731 14.6% 

Street Lighting 1.1624 1.0725 0.0899 7.7% 

Specific Service Charges and Retail Service Charges: Festival Hydro requests no changes 

to its existing Specific Service Charges and Retail Service Charges. The 2010 proposed rates 

are the same as the 2009 actual rates in force.


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 4 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

EXISTING RATE CLASSES: 

Residential: 

A customer is classified as residential when all the following conditions are met: 

(a) The property is zoned strictly residential by the local municipality 

(b) The account is created and maintained in the customer’s name 

(c) The Building is used for dwelling purposes. This classification refers to the supply of 

electrical energy to residential customers in detached or semi-detached units, as 

defined in the local zoning by-law. 

Exceptions may be made for properties zoned for farming use under the following 

conditions: (a) the principal use of the service is for the residence and (2) the service size 

is 200 amperes or less, and the service is 120/240 volt single phase. 

General Service Less than 50 kW: 

This classification refers to a non- residential account whose peak demand is less than 50 kW 

based on the process for and frequency of reclassification as outlined in Amendments to the 

Distribution System Code, Board File No: EB-2007-0722. For a new customer with no prior 

history, the peak demand in estimated by Festival Hydro. Customers who are classed as 

General Service but considers themselves residential must provide Festival Hydro with a copy 

of their tax assessment, which clearly demonstrates the zoning is for residential use only. 

General Service 50 to 4999 kW: 

This classification refers to a non residential account whose monthly peak demand is equal to 

or greater than 50 kW based on the process for and frequency of reclassification as outlined in 

Amendments to the Distribution System Code, Board File No: EB-2007-0722. For a new 

customer with no prior history, the peak demand in estimated by Festival Hydro. 

24


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 4 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

Large Use 

This classification refers to an account whose monthly average peak demand is equal to or 

greater than 5,000 kW based on the process for and frequency of reclassification as outlined in 

Amendments to the Distribution System Code, Board File No: EB-2007-0722. 

Unmetered Scattered Load: 

This classification refers to an account whose average monthly maximum demand is less than 

50 kW and the consumption is unmetered. Such connections include cable TV power packs, 

bus shelters, telephone booths, and traffic lights, pedestrian cross walk signal/beacons railway 

crossing. The level of consumption will be agreed to by the distributor and the customers, 

based on detailed manufacturer information with regard to electrical consumption of the 

unmetered load, or periodic monitoring of the actual consumption. 

Sentinel Lighting: 

This classification refers to an account that has an unmetered lighting load supplied to a 

sentinel light. 

Street Lighting: 

This classification applies to accounts for roadway lighting with a Municipality, Regional 

Municipality, and Ministry of Transportation and provides roadway lighting controlled by 

photocells. The consumption of these customers will be based on the calculated connected 

load times the required lighting times established in the approved OEB street light laid shape 

template. If connected to the street lighting system, decorative lighting and tree lighting 

services will be treated as a street lighting class of service. Decorative or tree lighting 

connected to Festival Hydro’s distribution system will be treated as General Service less than 

50 kW class customers.


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 5 



EXISTING RATE SCHEDULE: 

MONTHLY RATES AND CHARGES 

Residential 



Regulatory Asset Recovery $/kWh 0.0000 

Retail Transmission Rate – Network Service Rate $/kWh 0.0055 

Retail Transmission Rate – Line and Transformation Connection Service Rate $/kWh 0.0042 



Standard Supply Service – Administrative Charge (if applicable) $ 0.25 










General Service Less than 50 kW 









General Service 50 kW to 4,999 kW 



Regulatory Asset Recovery $/kW 0.0000 

Retail Transmission Rate – Network Service Rate $/kW 2.0144 

Retail Transmission Rate – Line and Transformation Connection Service Rate $/kW 1.5036 

Retail Transmission Rate – Network Service Rate – Interval Metered $/kW 2.1394 

Retail Transmission Rate – Line and Transformation Connection Service Rate – Interval Metered $/kW 1.6483 




Large Use 








Standard Supply Service – Administrative Charge (if applicable) $ 0.25


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 5 









































Collection of account charge – no connection $ 30.00 

Disconnect/Reconnect at meter - during Regular Hours $ 65.00 

Disconnect/Reconnect at meter - after regular hours $ 185.00 

Disconnect/Reconnect at pole – during regular hours $ 185.00 

Disconnect/Reconnect at pole – after regular hours $ 415.00 

Install/Remove load control device – during regular hours $ 65.00 

Install/Remove load control device – after regular hours $ 185.00 

Service call – customer owned equipment $ 30.00 

Service call – after regular hours $ 165.00 

Temporary service install & remove – overhead – no transformer $ 500.00 

Temporary service install & remove – underground – no transformer $ 300.00 

Temporary service install & remove – overhead – with transformer $ 1,000.00 

Specific charge for access to the power poles – per pole/year $ 22.35


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 5 



Allowances 


Primary Metering Allowance for transformer losses – applied to measured demand and energy % (1.00) 





Monthly Fixed Charge, per retailer $ 20.00 




Service Transaction Request (STR) 


Processing fee, peer request, applied to the requesting party $ 0.50 





no charge 


Loss Factor 

Total Loss Factor – Secondary Metered Customer < 5,000 kW 1.0281 

Total Loss Factor – Secondary Metered Customer > 5,000 kW 1.0145 

Total Loss Factor – Primary Metered Customer < 5,000 kW 1.0178 

Total Loss Factor – Primary Metered Customer > 5,000 kW 1.0045


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 6 



SCHEDULE OF PROPOSED RATES AND CHARGES: 

Residential 






















General Service Less Than 50 kW 




Smart Meter Adder $/mo 1.00 







General Service 50 to 4,999 kW 














EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 6 



Large Use 





































Retail Transmission Rate - Lien and Transformation Connection Service Rate $/kW 1.1624 















Collection of account charge - no disconnection $ 30.00 

Disconnect/Reconnect Charge - At Meter During Regular Hours $ 65.00 

Disconnect/Reconnect Charge - At Meter After Hours $ 185.00 

Disconnect/Reconnect at pole - during regular hours $ 185.00 

Disconnect/Reconnect at pole - after regular hours $ 415.00


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 6 



Install/Remove load control device - during regular hours $ 65.00 

Install/Remove load control device - after regular hours $ 185.00 

Service call - customer owned equipment $ 30.00 

Service call - after regular hours $ 165.00 

Temporary service install & remove - overhead - no transformer $ 500.00 

Temporary service install & remove - underground - no transformer $ 300.00 

Temporary service install & remove - overhead - with transformer $ 1000.00 

Specific Charge for Access to the Power Poles - per pole/year $ 22.35 

Allowances 


Primary Metering Allowance for transformer losses - applied to measured demand and energy % (1.00) 




LOSS FACTORS 


Monthly Fixed Charge, pre retailer $ 20.00 




Service Transaction Requests (STR) 


Processing fee, per request, applied to the requesting party $ 0.50 





no charge 


Total Loss Factor - Secondary Metered Customer 5,000 kW 1.0176 

Total Loss Factor - Primary Metered Customer 5,000kW 1.0075


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 7 



1 

RECONCILIATION OF RATE CLASS REVENUE: 


Fixed 


Revenue 

Variable 


Revenue 


Allowance 

Credit 

Total Distribution 

Revenue 

Expected 

Residential $ 3,189,600 $ 2,231,485 

$ 5,421,085 $ 5,420,642 

Residential - Hensall $ 64,790 $ 53,320 

$ 118,110 $ 118,226 

GS < 50 kW $ 712,190 $ 930,328 

$ 1,642,518 $ 1,643,335 

GS> 50 kW demand metered $ 546,191 $ 1,976,991 ($305,922) $ 2,217,260 $ 2,217,222 

Large Use $ 209,532 $ 182,954 ($77,212) $ 315,274 $ 315,268 

Sentinel Lights $ 1,468 $ 5,232 

$ 6,699 $ 6,699 

Street Lighting $ 57,495 $ 41,029 

$ 98,524 $ 98,521 

USL $ 24,123 $ 8,124 

$ 32,246 $ 32,216 

Back-up/Standby Power 

2009 Test Year Distribution Revenue Reconciliation 

Total $ 4,805,388 $ 5,429,462 ($383,134) $ 9,851,717 $ 9,852,131 

Difference Due to Rate Rounding 

2 

3 

4 

5 

6 

$ 

414 

The 2010 proposed rates applied to the test year 2010 customer numbers, kWh and kW sold will 

product the total distribution revenue necessary to meet Festival Hydro’s Base Revenue 

Requirements.


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 8 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

RATE AND BILL IMPACTS: 

Appendix A to this Schedule presents the results of the assessment of customer total bill impacts 

by customer rate class. 

Impacts are derived using the applicable May 1, 2009 rates and the proposed 2010 distribution 

rates, the proposed new Regulatory Asset rate rider, revised RTTS rates, and revised low voltage 

recovery adder and the proposed revised loss factors. Electricity rates for Residential and 

General Service < 50 kW are the rates effective May 1, 2009 for Rate Protection Plan customers. 

Electricity rates for other classes are the forecasted rates used for the approved 2009 cost of 

service rate applications for 2010 of $.607 /kWh. The rates also reflect an increase to Hensall 

residential rates, with revenue offset to regular residential rates, for the purpose of rate 

harmonization. 

The total bill impacts are calculated for each rate class at various levels of consumption. The 

rate impacts are assessed on the basis of moving to the proposed distribution rates. The 

following is a high level analysis of the resulting rate changes, as provided in appendix A: 

Residential Regular - A typical 800 kWh customer will experience a $1.80 or 1.83% increase 

on their total bill. 

Residential Hensall – Due to rate harmonization, a typical 800 kWh customer will experience a 

$6.72 or 7.45% increase on their total bill. Their bill will still be $5.29 lower each month than is 

paid by an 800 kWh Residential Regular customer. 

General Service less than 50 kW - A typical 2,000 kWh customer will experience a $1.43 or 

0.99% increase on their total bill. A typical 10,000 kWh customer will experience a $0.40 or 

0.04% increase on their total bill. Very minimal impact at all consumption levels. 

General Service greater than 50 kW – Rates are coming down at all consumption levels due to 

the impact of the regulatory asset (liability) rate rider. A typical 2,000 kW, 800,000 kWh 

customer will experience a $(344.29) or (0.45%) decrease on their total bill.


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 8 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

Large Use – Rates are coming down at all consumption levels due to the impact of the 

regulatory asset (liability) rate rider. A typical 5,400 kW, 2,400,000 kWh customer will 

experience a $(3,978.40) or (1.76%) decrease on their total bill. 

Street Lighting – Street lighting has increased as a result of the Cost of Service Allocation 

model. This increase is required to improve the Revenue to Cost ratios for street lighting. Street 

Lighting has been increased only by 37.0% between the current ratio and the minimum target 

ratio. An increase by 50% between the current ratio and the minimum target will create too high 

a rate increase. Festival hydro typically bills each month a total of 5,916 connections, will a kW 

demand of 937 kW and 269,570 kWh usage. The total increase monthly for all streetlights will 

be $3,146.15 or 9.73%. 

Sentinel Lights – Sentinel lighting has a total bill impact of approximately 12.86%. For the 

entire class, this represents a $253.62 increase in the total monthly bill for all sentinel lights. 

Considering there are approximately 64 customers, this works out to an average of 

approximately $4.13 per customer increase on a monthly basis. Festival Hydro believes this 

should not create an undue hardship for these customers and request that the proposed rate 

increase of 12.86% be accepted by the Board. 

Unmetered Scattered Load - Unmetered Scattered Load has decreased as a result of the Cost 

of Service Allocation model. This decrease was due to the fact USL was contributing above its 

maximum revenue to costs ratio target. Festival Hydro typically bills each month a total of 156 

connections, will a 52,477 kWh usage. The total decrease monthly for all USL customers will 

be $(1.90) or (3.92) %. 

Festival Hydro request that the Board approve the final schedule of proposed rates and 

charges as presented for the 2010 test year. 

24


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 8 

Appendix A 


APPENDIX A 

TABLE OF RATE AND BILL IMPACTS


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 8 

Appendix A 



RESIDENTIAL 

2009 BILL 2010 BILL IMPACT 

Volume 

RATE CHARGE 

RATE CHARGE Change Change 

Volume 

$ 

$ 

$ 

$ 

$ 

% 

% of Total Bill 

Consumption 

Monthly Service Charge 14.09 15.53 1.44 10.22% 56.05% 

100 kWh Distribution (kWh) 100 0.0158 1.58 100 0.0172 1.72 0.14 8.86% 6.21% 

Smart Meter Rider (per month) 1.00 1.00 0.00 0.00% 3.61% 

Low Voltage Cost Recovery Adder (kWh) 100 100 0.0001 0.01 0.01 0.00% 0.04% 

Regulatory Assets (kWh) 100 0.0000 0.00 100 (0.0009) (0.09) (0.09) 100.00% (0.33%) 

Sub-Total - Distribution 16.67 18.17 1.50 8.99% 65.57% 

RTSR - Network 103 0.0055 0.57 103 0.0049 0.50 (0.06) (11.07%) 1.81% 

RTSR - Connection 103 0.0042 0.43 103 0.0044 0.45 0.02 4.52% 1.63% 

Sub-Total - Delivery 17.67 19.12 1.46 8.24% 69.01% 

Wholesale Market & RRRP (kWh) 103 0.0065 0.67 103 0.0065 0.67 0.00 0.00% 2.42% 

Debt Retirement (kWh) 103 0.0070 0.72 103 0.0070 0.72 0.00 0.00% 2.60% 

Cost of Power Commodity (kWh) 103 0.0570 5.86 103 0.0570 5.88 0.01 0.25% 21.20% 

Total Bill Before Taxes 24.92 26.39 1.47 5.92% 95.24% 

GST 5.00% 1.25 5.00% 1.32 0.07 5.92% 4.76% 

Total Bill 26.16 27.71 1.55 5.92% 100.00% 

RESIDENTIAL 


Volume 

RATE CHARGE 

RATE CHARGE 

Volume 

$ 

$ 

$ 

$ $ % 


Consumption 







RTSR - Network (kWh) 257 0.0055 1.41 258 0.0049 1.26 (0.16) (11.07%) 2.91% 

RTSR - Connection (kWh) 257 0.0042 1.08 258 0.0044 1.13 0.05 4.52% 2.61% 





Total Bill Before Taxes 39.65 41.18 1.53 3.85% 0.95 

GST 5.00% 1.98 5.00% 2.06 0.08 3.85% 4.76% 

Total Bill 41.64 43.24 1.60 3.85% 100.00% 

RESIDENTIAL 


Volume 

RATE CHARGE 

RATE CHARGE 

Volume 

$ 

$ 

$ 

$ $ % 


Consumption 









Sub-Total - Delivery 27.98 29.50 1.52 5.44% 0.43 





GST 5.00% 3.21 5.00% 3.29 0.08 2.51% 4.76% 

Total Bill 67.43 69.12 1.69 2.51% 100.00%


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 8 

Appendix A 



RESIDENTIAL 


Volume 

RATE CHARGE 

RATE CHARGE 

Volume 

$ 

$ 

$ 

$ $ % 


Consumption 














GST 5.00% 4.68 5.00% 4.77 0.09 1.83% 4.76% 

Total Bill 98.38 100.18 1.80 1.83% 100.00% 

RESIDENTIAL 


Volume 

RATE CHARGE 

RATE CHARGE 

Volume 

$ 

$ 

$ 

$ $ % 


Consumption 


1,000 kWh Distribution (kWh) 1,000 0.0158 15.80 1,000 0.0172 17.20 1.40 8.86% 13.76% 


Low Voltage Cost Recovery Adder (kWh) 1,000 1,000 0.0001 0.10 0.10 0.00% 0.08% 

Regulatory Assets (kWh) 1,000 0.0000 0.00 1,000 (0.0009) (0.91) (0.91) 100.00% (0.7264%) 


RTSR - Network (kWh) 1,028 0.0055 5.65 1,031 0.0049 5.03 (0.63) (11.07%) 4.02% 

RTSR - Connection (kWh) 1,028 0.0042 4.32 1,031 0.0044 4.51 0.20 4.52% 3.61% 


Wholesale Market & RRRP (kWh) 1,028 0.0065 6.68 1,031 0.0065 6.70 0.02 0.25% 5.36% 

Debt Retirement (kWh) 1,028 0.0070 7.20 1,031 0.0070 7.21 0.02 0.25% 5.77% 




GST 5.00% 5.86 5.00% 5.95 0.09 1.54% 4.76% 

Total Bill 123.06 124.96 1.90 1.54% 100.00% 

RESIDENTIAL 


Volume RATE CHARGE Volume RATE CHARGE 


Consumption 

Monthly Service Charge 

$ 

$ 

14.09 

$ 

$ 

15.53 

$ 

1.44 

% 

10.22% 8.55% 














GST 5.00% 8.55 5.00% 8.65 0.10 1.17% 4.76% 

Total Bill 179.50 181.59 2.09 1.17% 100.00%


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 8 

Appendix A 



RESIDENTIAL 




Consumption 


$ 

$ 

14.09 

$ 

$ 

15.53 

$ 

1.44 

% 

10.22% 6.52% 












Cost of Power Commodity (kWh) 1,456 0.0660 96.11 1,461 0.0660 96.45 0.34 0.36% 40.49% 


GST 5.00% 11.24 5.00% 11.34 0.11 0.97% 4.76% 

Total Bill 235.94 238.22 2.28 0.97% 100.00% 

RESIDENTIAL - Hensall 




Consumption 


$ 

$ 

9.03 

$ 

$ 

13.06 

$ 

4.03 

% 

44.63% 32.83% 













GST 5.00% 1.66 5.00% 1.89 0.24 14.39% 4.76% 

Total Bill 34.77 39.78 5.00 14.39% 100.00% 





Consumption 


$ 

$ 

9.03 

$ 

$ 

13.06 

$ 

4.03 

% 

44.63% 20.16% 













GST 5.00% 2.81 5.00% 3.09 0.28 9.79% 4.76% 

Total Bill 59.02 64.79 5.78 9.79% 100.00%


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 8 

Appendix A 





Volume 

RATE CHARGE 

RATE CHARGE 

Volume 

$ 

$ 

$ 

$ $ % 


Consumption 















GST 5.00% 4.30 5.00% 4.62 0.32 7.45% 4.76% 

Total Bill 90.21 96.93 6.72 7.45% 100.00% 



Volume 

RATE CHARGE 

RATE CHARGE 

Volume 

$ 

$ 

$ 

$ $ % 


Consumption 















GST 5.00% 5.31 5.00% 5.66 0.35 6.59% 4.76% 

Total Bill 111.55 118.89 7.35 6.59% 100.00% 

GENERAL SERVICE < 50 kW 


Volume 

RATE CHARGE 


Volume 

$ 

$ 

$ 

$ 

$ 

% 


Consumption 



Low Voltage Cost Recovery Adder 2,000 0.0001 0.20 0.20 0.00% 0.14% 



Sub-Total 57.51 59.34 1.83 3.18% 40.74% 









GST 5.00% 6.87 5.00% 6.94 0.07 1.02% 4.76% 

Total Bill 144.23 145.66 1.43 0.99% 100.00%


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 8 

Appendix A 





Volume 

RATE CHARGE 


Volume 

$ 

$ 

$ 

$ 

$ 

% 


Consumption 






Sub-Total 85.91 87.53 1.62 1.88% 18.81% 

Other Charges (kWh) 4,112 0.0222 91.30 4,123 0.0219 90.37 (0.92) (1.01%) 19.42% 




GST 5.00% 22.09 5.00% 22.16 0.07 0.31% 4.76% 

Total Bill 463.97 465.42 1.45 0.31% 100.00% 



Volume 

RATE CHARGE 


Volume 

$ 

$ 

$ 

$ 

$ 

% 


Consumption 






Sub-Total 171.11 172.09 0.98 0.57% 15.30% 




Total Bill Before Taxes 1,071.15 1,071.53 0.38 0.04% 95.24% 

GST 5.00% 53.56 5.00% 53.58 0.02 0.04% 4.76% 

Total Bill 1,124.71 1,125.11 0.40 0.04% 100.00% 



Volume 

RATE CHARGE 


Volume 

$ 

$ 

$ 

$ 

$ 

% 


Consumption 






Sub-Total 206.61 207.32 0.71 0.35% 14.81% 




Total Bill Before Taxes 1,333.35 1,333.32 (0.03) (0.00%) 95.24% 

GST 5.00% 66.67 5.00% 66.67 (0.00) (0.00%) 4.76% 

Total Bill 1,400.01 1,399.98 (0.03) (0.00%) 100.00%


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 8 

Appendix A 





Volume 

RATE CHARGE 


Volume 

$ 

$ 

$ 

$ 

$ 

% 


Consumption 






Sub-Total 242.11 242.56 0.45 0.19% 14.48% 





GST 5.00% 79.78 5.00% 79.76 (0.02) (0.03%) 4.76% 

Total Bill 1,675.32 1,674.86 (0.47) (0.03%) 100.00% 

Consumption 

GENERAL SERVICE > 50 kW 


RATE CHARGE 


Volume 

Volume 


$ 

$ 

$ 

$ 

$ 

% 

Monthly Service Charge 209.76 206.40 (3.36) (1.60%) 6.48% 


100 kW Distribution (kW) 100 2.2603 226.03 100 2.5255 252.55 26.52 11.73% 7.93% 

Low Voltage Cost Recovery Adder 100 0.0591 5.91 5.91 0.00% 0.19% 


Regulatory Assets (kW) 100 0.0000 0.00 100 (0.3676) (36.76) (36.76) 100.00% (1.15%) 

Sub-Total 436.79 429.10 (7.69) (1.76%) 13.48% 

Other Charges (kWh) 30,843 0.0135 416.38 30,921 0.0135 417.43 1.05 0.25% 13.11% 

Other Charges (kW) 103 3.5180 361.69 103 3.0479 313.36 (48.33) (13.36%) 9.84% 

Cost of Power Commodity (kWh) 30,843 0.0607 1,872.80 30,843 0.0607 1,872.80 0.00 0.00% 58.81% 


GST 5.00% 154.38 5.00% 151.63 (2.75) (1.78%) 4.76% 

Total Bill 3,242.04 3,184.33 (57.71) (1.78%) 100.00% 

Consumption 



RATE CHARGE 

RATE CHARGE 

Volume 

Volume 


$ 

$ 

$ 

$ $ % 



250 kW Distribution (kW) 250 2.2603 565.08 250 2.5255 631.38 66.30 11.73% 8.25% 




Sub-Total 775.84 761.66 (14.17) (1.83%) 9.96% 

Other Charges (kWh) 77,108 0.0135 1,040.96 77,303 0.0135 1,043.59 2.63 0.25% 13.64% 




GST 5.00% 370.15 5.00% 364.22 (5.93) (1.60%) 4.76% 

Total Bill 7,773.15 7,648.66 (124.50) (1.60%) 100.00%


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 8 

Appendix A 



Consumption 



RATE CHARGE 

RATE CHARGE 

Volume 

Volume 


$ 

$ 

$ 

$ $ % 



500 kW Distribution (kW) 500 2.2603 1,130.15 500 2.5255 1,262.75 132.60 11.73% 6.61% 




Sub-Total 1,340.91 1,315.92 (24.99) (1.86%) 6.89% 


Other Charges (kW) 514 3.5180 1,808.44 515 3.0479 1,570.74 (237.70) (13.14%) 8.23% 



GST 5.00% 920.53 5.00% 909.32 (11.21) (1.22%) 4.76% 

Total Bill 19,331.08 19,095.74 (235.34) (1.22%) 100.00% 

Consumption 

GENERAL SERVICE > 50 kW (Interval metered) 


RATE CHARGE 

RATE CHARGE 

Volume 

Volume 


$ 

$ 

$ 

$ $ % 



2,000 kW Distribution (kW) 2,000 2.2603 4,520.60 2,000 2.5255 5,051.00 530.40 11.73% 6.57% 



Regulatory Assets (kW) 2,000 0.0000 0.00 2,000 (0.3676) (735.12) (735.12) 100.00% (0.95596%) 

Sub-Total 4,731.36 4,641.48 (89.88) (1.90%) 6.04% 


Other Charges (kW) 2,056 3.7877 7,788.31 2,061 3.5879 7,396.07 (392.24) (5.04%) 9.62% 



GST 5.00% 3,678.22 5.00% 3,661.83 (16.39) (0.45%) 4.76% 

Total Bill 77,242.70 76,898.41 (344.29) (0.45%) 100.00% 

Consumption 

GENERAL SERVICE > 50 kW (interval metered with transformer) 


RATE CHARGE 

RATE CHARGE 

Volume 

Volume 


$ 

$ 

$ 

$ $ % 


1,600,000 kWh Distribution (kWh) 1,600,000 0.0000 0.00 1,600,000 0.0000 0.00 0.00 0.00% 0.00% 

4,000 kW Distribution (kW) 4,000 2.2603 9,041.20 4,000 2.5255 10,102.00 1,060.80 11.73% 6.69% 



Transformer Credit 4,000 (0.6000) (2,400.00) 4,000 (0.6000) (2,400.00) 0.00 0.00% (1.59%) 

Regulatory Assets (kW) 4,000 0.0000 0.00 4,000 (0.3676) (1,470.24) (1,470.24) 100.00% (0.97%) 

Sub-Total 6,851.96 6,675.56 (176.40) (2.57%) 7.55% 

Other Charges (kWh) 1,644,969 0.0135 22,207.08 1,649,125 0.0135 22,263.19 56.10 0.25% 14.74% 

Other Charges (kW) 4,112 3.7877 15,576.62 4,123 3.5879 14,792.14 (784.49) (5.04%) 9.79% 

Cost of Power Commodity (kWh) 1,644,969 0.0607 99,882.53 1,649,125 0.0607 100,134.87 252.34 0.25% 66.29% 


GST 5.00% 7,225.91 5.00% 7,193.29 (32.62) (0.45%) 4.76% 

Total Bill 151,744.11 151,059.05 (685.06) (0.45%) 103.13%


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 8 

Appendix A 



Consumption 

LARGE USER (> 5000 kW) 


RATE CHARGE 


Volume 

Volume 


$ 

$ 

$ 

$ 

$ 

% 

Monthly Service Charge 10,447.04 8,730.51 (1,716.53) (16.43%) 3.93% 







Sub-Total 13,110.78 10,983.44 (2,127.34) (16.23%) 8.44% 


Other Charges (kW) 5,424 4.2538 23,073.89 5,441 3.8375 20,877.89 (2,196.00) (9.52%) 9.41% 


Total Bill Before Taxes 215,114.24 211,325.29 (3,788.95) (1.76%) 98.73% 

GST 5.00% 10,755.71 5.00% 10,566.26 (189.45) (1.76%) 4.76% 

Total Bill 225,869.96 221,891.55 (3,978.40) (1.76%) 103.49% 

Consumption 



RATE CHARGE 

RATE CHARGE 

Volume 

Volume 


$ 

$ 

$ 

$ $ % 








Sub-Total 14,146.29 11,859.20 (2,287.09) (16.17%) 7.90% 





GST 5.00% 13,865.54 5.00% 13,633.19 (232.34) (1.68%) 4.76% 

Total Bill 291,176.26 286,297.07 (4,879.19) (1.68%) 103.76% 

Consumption 



RATE CHARGE 

RATE CHARGE 

Volume 

Volume 


$ 

$ 

$ 

$ $ % 








Sub-Total 15,379.04 12,901.76 (2,477.28) (16.11%) 7.10% 





GST 5.00% 18,561.76 5.00% 18,281.32 (280.44) (1.51%) 4.76% 

Total Bill 389,796.98 383,907.76 (5,889.22) (1.51%) 103.74%


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 8 

Appendix A 



Consumption 



RATE CHARGE 

RATE CHARGE 

Volume 

Volume 


$ 

$ 

$ 

$ $ % 








Sub-Total 17,302.13 14,528.16 (2,773.97) (16.03%) 7.83% 





GST 5.00% 21,354.99 5.00% 20,985.98 (369.01) (1.73%) 4.76% 

Total Bill 448,454.77 440,705.62 (7,749.15) (1.73%) 104.53% 



Volume 

RATE CHARGE 


Volume 

$ 

$ 

$ 

$ 

$ 

% 


Billing Determinants Monthly Service Charge 5,916 0.4500 2,662.20 5,916 0.8099 4,791.37 2,129.17 79.98% 13.50% 

5,916 Connections Distribution (kWh) 325,344 0.0000 0.00 325,344 0.0000 0.00 0.00 0.00% 0.00% 

325,344 kWh Distribution (kW) 938 2.0977 1,967.47 938 3.6453 3,418.99 1,451.52 73.78% 9.64% 


938 kW Regulatory Assets (kW) 938 0.0000 0.00 938 (0.2998) (281.14) (281.14) 100.00% (0.7923%) 

Sub-Total 4,629.67 7,931.00 3,301.33 71.31% 22.35% 


Other Charges (kW) 964 2.6816 2,585.81 967 2.2977 2,221.24 (364.57) (14.10%) 6.26% 



Total Bill Before Taxes 30,796.89 33,793.23 2,996.34 9.73% 95.24% 

GST 5.00% 1,539.84 5.00% 1,689.66 149.82 9.73% 4.76% 

Total Bill 32,336.74 35,482.89 3,146.15 9.73% 100.00% 



Volume 

RATE CHARGE 


Volume 

$ 

$ 

$ 

$ 

$ 

% 


Billing Determinants Monthly Service Charge 1 0.4500 0.45 1 0.8099 0.81 0.36 79.98% 12.25% 

1 Connections Distribution (kWh) 62 0.0000 0.00 62 0.0000 0.00 0.00 0.00% 0.00% 

62.47 kWh Distribution (kW) 0.17 2.0977 0.35 0.17 3.6453 0.60 0.26 73.78% 9.13% 


0.17 kW Regulatory Assets (kW) 0.17 0.0000 0.00 0.17 (0.2998) (0.05) (0.05) 100.00% (0.75%) 

Sub-Total 0.80 1.36 0.57 71.09% 20.63% 

Other Charges (kWh) 64 0.0135 0.87 64 0.0135 0.87 0.00 0.25% 13.15% 

Other Charges (kW) 0.17 2.6816 0.46 0.17 2.2977 0.39 (0.06) (14.10%) 5.93% 



GST 5.00% 0.29 5.00% 0.31 0.03 8.89% 4.76% 

Total Bill 6.07 6.61 0.54 8.89% 100.00%


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 8 

Appendix A 





Volume 

RATE CHARGE 


Volume 

$ 

$ 

$ 

$ 

$ 

% 



83 Connections Distribution (kWh) 19,558 0.0000 0.00 19,558 0.0000 0.00 0.00 0.00% 0.00% 

19,558 kWh Distribution (kW) 57 4.1925 237.23 57 7.7054 436.00 198.77 83.79% 19.59% 


57 kW Regulatory Assets (kW) 57 0.0000 0.00 57 (0.4023) (22.76) (22.76) 100.00% (1.02%) 

Sub-Total 302.80 574.03 271.23 89.58% 24.06% 

Other Charges (kWh) 20,107 0.0135 271.45 20,158 0.0135 272.13 0.69 0.25% 12.23% 



Total Bill Before Taxes 1,878.21 2,119.75 241.54 12.86% 93.51% 

GST 5.00% 93.91 5.00% 105.99 12.08 12.86% 4.76% 

Total Bill 1,972.12 2,225.74 253.62 12.86% 98.27% 



Volume 

RATE CHARGE 

RATE CHARGE 

Volume 

$ 

$ 

$ 

$ $ % 



1 Connections Distribution (kWh) 236 0.0000 0.00 236 0.0000 0.00 0.00 0.00% 0.00% 

235.63 kWh Distribution (kW) 0.68 4.1925 2.85 0.68 7.7054 5.24 2.39 83.79% 19.55% 

Low Voltage Cost Recovery Adder 0.68 0.6805 0.46 0.46 0.00% 0.00% 

0.68 kW Regulatory Assets (kW) 0.68 0.0000 0.00 0.68 (0.4023) (0.27) (0.27) 100.00% (1.02%) 

Sub-Total 3.64 6.90 3.26 89.58% 24.03% 

Other Charges (kWh) 242 0.0135 3.27 243 0.0135 3.28 0.01 0.25% 12.24% 

Other Charges (kW) 0.70 2.7136 1.90 0.70 2.1362 1.50 (0.40) (21.08%) 5.59% 



GST 5.00% 1.13 5.00% 1.28 0.15 12.84% 4.76% 

Total Bill 23.75 26.80 3.05 12.84% 98.27% 

Unmetered Scattered 


Volume 

RATE CHARGE 

RATE CHARGE 

Volume 

$ 

$ 

$ 

$ $ % 


Consumption 

Monthly Service Charge 1 14.06 14.06 1 12.91 12.91 (1.15) (8.19%) 27.68% 

336 kWh Distribution (kWh) 336 0.0142 4.78 336 0.0129 4.34 (0.44) (9.15%) 9.31% 

Low Voltage Cost Recovery Adder 336.40 0.0001 0.03 0.03 0.00% 0.00% 

1 Connection Regulatory Assets (kW) 336 0.0000 0.00 336 (0.0008) (0.27) (0.27) 100.00% (0.5815%) 

Sub-Total 18.84 17.01 (1.83) (9.70%) 36.40% 

Other Charges (kWh) 346 0.0222 7.68 347 0.0220 7.64 (0.04) (0.48%) 16.39% 


Total Bill Before Taxes 46.23 44.41 (1.81) (3.92%) 95.17% 

GST 5.00% 2.31 5.00% 2.22 (0.09) (3.92%) 4.76% 

Total Bill 48.54 46.64 (1.90) (3.92%) 99.93%


EB-2009-0263 

Exhibit 8 

Tab 1 

Schedule 8 

Appendix A 



Unmetered Scattered 


Volume 

RATE CHARGE 

RATE CHARGE 

Volume 

$ 

$ 

$ 

$ $ % 


Consumption 

Monthly Service Charge 156 14.0600 2,193.36 156 12.9081 2,013.66 (179.70) (8.19%) 27.85% 

52,478 kWh Distribution (kWh) 52,478 0.0142 745.18 52,478 0.0129 676.96 (68.22) (9.15%) 9.36% 

Low Voltage Cost Recovery Adder 52,477.67 0.0001 5.25 5.25 0.00% 0.00% 

156 Connections Regulatory Assets (kW) 52,478 0.0000 0.00 52,478 (0.0008) (42.31) (42.31) 100.00% (0.59%) 

Sub-Total 2,938.54 2,653.57 (284.98) (9.70%) 36.63% 

Other Charges (kWh) 53,953 0.0222 1,197.75 54,089 0.0220 1,192.04 (5.70) (0.48%) 16.49% 



GST 5.00% 360.58 5.00% 344.32 (16.26) (4.51%) 4.76% 

Total Bill 7,572.17 7,230.69 (341.48) (4.51%) 99.93%


EB-2009-0263 

Exhibit 9 

Index 




9 – Deferral and 

Variance Accounts 

1 1 Deferral and Variance Accounts & 

Balances 

2 Clearance of Deferral/Variance Accounts 

by way of a Deferral and Variance 

Account Rate Rider 

A Methods of Disposition of Accounts 

3 Proposed Rates and Bill Impacts 

4 Smart Meters 

B Letter from PRP International Inc. 

Fairness Advisory Services


EB-2009-0263 

Exhibit 9 

Tab 1 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

DEFERRAL AND VARIANCE ACCOUNTS & BALANCES: 

This Schedule contains descriptions of Deferral and Variance Accounts (“DVAs”) currently used 

by Festival Hydro and the status of these accounts as at December 31, 2008. 

RSVA/RCVA ACCOUNTS 

1588 Retail Settlement Variance Account – Power 

Description: This account is used to recover the net difference between the energy 

amount billed to customers and the energy charge to Festival Hydro using the settlement 

invoice from the Independent Electricity System Operator (“IESO”). This account will 

continue on a go forward basis. 

1588 Retail Settlement Variance Account - Power, Sub-account Global Adjustments 

Description: This is a sub account to the RSVA Power account which is used to recover 

the net difference between the provincial benefit amount billed to non RPP customers and 

the global adjustment charge to Festival Hydro for non RPP using the settlement invoice 

from the IESO. This account will continue on a go forward basis. 

The main driver of this variance account balance is the difference in the monthly rates 

between the global adjustment charged by the IESO and the provincial benefit rate 

charged to the customer. In the month of December 2008, the global adjustment charged 

on the IESO bill was $13.37 per MWh. The rate charged to non-RPP consumers was 

$3.90 per MWh. This created a large difference on account at the end of December 31, 

2008. 

As part of the account disposition, Festival Hydro has determined the amount owing to 

each rate class, based on historical data of customer kWh sales to non-RPP customers 

(i.e. customers with retailers or on spot pricing).


EB-2009-0263 

Exhibit 9 

Tab 1 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

1580 Retail Settlement Variance Account - Wholesale Market Service Charges 

Description: This account is used to record the net of the amount charged by the IESO 

based on the settlement invoice for the operation of the IESO-administered markets and 

the operation of the IESO-controlled grid, and the amount billed to customers using the 

OEB-approved Wholesale Market Service Rate. This account will continue on a go 

forward basis. 

1582 Retail Settlement Variance Account - One-time Wholesale Market Service 

Description: This account is used to record the net of non-recurring amounts not included 

in the Wholesale Market Service Rate charged by the IESO based on the settlement 

invoice and the amount charged to customers for the same services using the OEBapproved 

rate. This account will continue on a go forward basis. 

1584 Retail Settlement Variance Account - Retail Transmission Network Charges 

Description: This account is used to record the net of the amount charged by the IESO, 

based on the settlement invoice for transmission network services, and the amount billed 

to customers using the OEB-approved Transmission Network Charge. This account will 

continue on a go forward basis. 

1586 Retail Settlement Variance Account - Retail Transmission Connection Charges 

Description: This account is used to record the net of the amount charged by the IESO, 

based on the settlement invoice for transmission connection services, and the amount 

billed to customers using the OEB-approved Transmission Connection Charge. This 

account will continue on a go forward basis. 

22 

23 

24


EB-2009-0263 

Exhibit 9 

Tab 1 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

Non RSVA/RCVA Accounts 

1508 Other Regulatory Assets 

Description: This account includes amounts of regulatory-created assets, not included in 

other accounts, resulting from the ratemaking actions of the OEB. 

1508 Other Regulatory Assets - Sub-account OEB Cost Assessments 

Description: This account includes amounts paid for OEB Cost Assessment for the period 

January 1, 2004 to April 30, 2006 in excess of amounts previously included in rates 

(1999 OEB costs). This account will come to an end with its proposed disposition. 

1508 Other Regulatory Assets - Sub-account Pension Contributions 

Description: This account includes amounts paid for OMERS pension expense for the 

period January 1, 2004 to April 30, 2006 not included in rates. This account will come to 

an end with its proposed disposition. 

1518 RSVA Retail 

Description: This account is used to record the net of the revenues derived from certain 

retailer services, and the incremental costs incurred to provide these services. This 


1525 Miscellaneous Deferred Debits 

Description: This account includes all debits not elsewhere provided for which will 

benefit future periods are carried forward and charged to expense over the term of the 

benefit. At December 31, 2008, there was a balance of $1,145 in this account, 

representing incremental costs incurred related to the 2010 Cost of Service Rate 

Application. Within the Cost of Service Rate application, Festival Hydro has requested 

an increase of $40,000 per year for the next 4 years in our Regulatory Expense account 

(USOA #5655) to cover the costs of the 2010 Cost of Service Rate Application. The plan 

is to charge this amount of $1,145 in 2010 to the #5655 account.


EB-2009-0263 

Exhibit 9 

Tab 1 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

1548 RSVA STR 

Description: This account is used to record the net of the revenues derived from Service 

Transaction Request services, and the incremental costs incurred to provide these 

services. This account will continue on a go forward basis. 

1550 Low Voltage (LV) Variance Account 

Description: This account is used to record the net of the amount charged by Hydro One 

for low voltage services, and the amount billed to customers based on Festival Hydro’s 

approved LV rates. This account will continue on a go forward basis. 

1555 Smart Meter Capital and Recovery Offset Variance 

Description: This account records the net of the amounts paid for capitalized direct costs 

related to the smart meter program and the amounts charged to customers using the OEBapproved 

smart meter rate rider. This account will continue on a go forward basis. 

1556 Smart Meter OM&A Variance 

Description: This account records the incremental operating, maintenance, amortization 

and administrative expenses directly related to smart meters. This account will continue 

on a go forward basis. There were no costs charged to this account to December 31, 

2008. 

1562 Deferred Payments in Lieu of Taxes 

Description: This account records the amount resulting from the OEB-approved PILs 

methodology for determining the 2001 deferral account allowance and the PILs proxy 

amount determined for 2002 and subsequent periods ending April 30, 2006. This account 

will come to an end based the outcome of the Deferred PILs combined proceedings. 

1563 Contra Account -Deferred Payments in Lieu of Taxes 

Description: This account was used as a result of Festival Hydro using the third 

accounting method approved for recording entries in account # 1562. This account will


EB-2009-0263 

Exhibit 9 

Tab 1 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

come to an end based the outcome of the Deferred PILs combined proceedings.1565 

CDM Expenditures and Recoveries 

Description: This account records the amount spent on Board approved CDM programs 

and the revenue proxy equivalent to Festival Hydro’s third tranche of MARR. Festival 

Hydro never calculated any carrying charges on this account, even prior to February 28, 

2005. This account came to an end at December 31, 2007. 

1566 CDM Expenditures and Recoveries Contra 

Description: This account is the contra account to Acct 1565. Festival Hydro never 

calculated any carrying charges on this account, even prior to February 28, 2005. This 

account came to an end at December 31, 2007. 

1590 Recovery of Regulatory Asset Balances 

Description: This account records the net of amounts collected from customers from the 

2006 EDR Regulatory Asset filing. This Regulatory Asset rate rider was removed from 

Festival Hydro’s Distribution Rates effective May 1, 2008. Separate sub-accounts are 

maintained for expenses, interest, and recovery amounts. A residual balance of $42,229 

remained as at December 31, 2008. This account will continue on a go forward basis. 

Festival Hydro will not request disposition of this account at this time, rather as part of 

the generic review process. 

2405 Other Regulatory Liabilities 

Description: Accrued low voltage charges from Hydro One for periods prior to May 1, 

2006. The liabilities owing to Hydro One were set up when determined and are billed 

monthly as a standard charge by Hydro One on their monthly low voltage bills. This 

balance is owed to Hydro One; not our customers. This account will come to an end 

when Hydro One has been fully paid in February 2010. A residual will remain at that 

time requiring disposition. 

26


EB-2009-0263 

Exhibit 9 

Tab 1 

Schedule 1 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

New Accounts Being Requested: 

Use of the following approved account is being requested as part of the 2010 rate application: 

1574 Deferred Rate Impact Amounts 

Description: As authorized by the OEB in its decision in EB-2008-0663 (PILs), this 

account shall be used to record the difference between the revised Distribution Rates and 

actual Distribution Rates charged to customers for the period May 1, 2009 to the date in 

which final 2010 distribution rates are approved and enacted. Festival Hydro request that 

this account can be used by Festival Hydro to record the difference between the revised 

Distribution Rates and actual Distribution Rates charged to customers for the period May 

1, 2010 to the date in which final 2010 distribution rates are approved and enacted. This 


Calculation of Carrying Charges: 

Carrying charges have been applied to all variance accounts, except the CDM accounts (#1565 & 

#1566). Nor are there any carrying charges on #Acct 1525 Miscellaneous deferred debits, which 

is a small balance of $1,145 recorded in December 2008. For all other variance accounts, 

previous to April 30, 2006, Festival Hydro applied a rate of interest equal to its deemed interest 

rate for debt of 7.25%, as per Chapter 3 of the 2000 Electricity Distribution Handbook. Effective 

May 1, 2006, the rate of interest being applied is the rate prescribed by the Board for approved 

deferred and variance accounts. Carrying charges are calculated using simple interest applied to 

the monthly opening balance in the account (excluding accumulated interest). 

Another exception to the calculations noted above was for account # 1508 OEB Cost assessment 

and Pension contributions, which were subject to an annual rate of 3.88% up to April 30, 2006, 

and the Board prescribed rate thereafter. 

26


EB-2009-0263 

Exhibit 9 

Tab 1 

Schedule 1 



1 

TABLE OF RATES USED FOR VARIANCE ACCOUNTS 

May 2002 to April 30, 2006 7.25 % 

Q2 2006 4.14% 

Q3 2006 to Q3 2007 4.59% 

Q4 2007 to Q1 2008 5.14% 

Q2 2008 4.08% 

Q3 2008 to Q4 2008 3.35% 

Q1 2009 to Q2 2010 (used 

1.00% 

the Q2 2009 OEB approved 

rate for the 2010 rate 

application)


EB-2009-0263 

Exhibit 9 

Tab 1 

Schedule 2 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

CLEARANCE OF DEFFERAL and VARIANCE ACCOUNTS - REQUEST FOR 

DISPOSITION BY WAY OF A DEFERRAL AND VARIANCE ACCOUNT RATE 

RIDER 

The OEB earlier in 2009 initiated a process to determine how the Board can effectively clear 

distributors various deferral accounts and on July 31, 2009 issued EB-2008-0046 Report of the 

Board on Electricity Distributors Deferral and Variance Account Review (EDDVAR). 

As noted under the Executive Summary “the Board has decided that at the time of rebasing all 

account balances should be reviewed and disposed of unless otherwise justified by the distributor 

or as required by a specific Board decision or guideline”. 

Festival Hydro supports the disposition of all RSVA and most RCVA accounts as part of the 

2010 Cost of Service Rate application for the following reasons. 

12 

13 

14 

15 

16 

 

the balances in the RSVA accounts for Festival Hydro are very large at the end of 

December 31, 2008. They represent a four year accumulation of balances since our last 

rebasing took place in 2006, which was based on December 31, 2004 deferral and 

variance account balances. Balances subsequent to December 31, 2008 would then be 

cleared based on the EDDVAR guidelines. 

17 

18 

19 

20 

21 

22 

 

Festival Hydro would prefer to have the rate rider spread over the four year period at 

which time we expect to complete our next Cost of service study, rather than the one year 

recommended in EDDVAR. As noted above, these balances represent 4 years of 

accumulated balances, so we would prefer to return to customers over a four year period. 

The RSVA balances in particular are very large and in the interest of mitigating rate 

impact we recommend returning to the customers over a four year period. 

23 

24 

25 

26 

 

With the deferral and variance account rate rider being part of the Cost of Service Rate 

application, Festival Hydro knows exactly how this rate rider, in conjunction with other 

rate changes, will impact the overall bill. We prefer the comprehensive approach via the 

Cost of Service application.


EB-2009-0263 

Exhibit 9 

Tab 1 

Schedule 2 



1 

2 

3 

4 

We would recommend, however, that the following accounts not be part of the request for 

disposition at this time. 

Accounts 1562 and 1563 - PILs and PILs contra, which are subject to a separate review 

by the OEB. 

5 

6 

 

1590 Recovery of Regulatory Asset Accounts, which is a smaller balance. We propose 

disposition through the EDDVAR process. 

7 

8 

9 

 

Account 2405 Miscellaneous Liabilities is not being dispersed as this is an amount owing 

directly to Hydro One and will be reduced monthly as it is paid. It is not included on 

either Group 1 or Group 2 of the account listing in the EDDVAR document. 

10 

11 

12 

Account 1525 Miscellaneous Deferred Debits of $1,145 is also not part of the disposition 

as it was just established in 2008 to record incremental costs associated with the 2010 

Cost of service rate application. 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

Festival Hydro requests the disposition of the following RSVA and non-RSVA/RCVA Accounts. 

The disposition is requested for over a four year period for all accounts. The allocation factors 

used are taken from Table 1 – Summary of Default Allocation Factors of the EDDVAR. 

1580 RSVA – Wholesale Market Charge 

Disposal of principal balance as at December 31, 2008 of $(1,385,017) and interest owing 

to April 30, 2010 of $(101,009) over a four year period is requested. 

Method of recovery: Allocation to rate classes on basis of 2010 kWh sales. 

1582 RSVA – Wholesale Market – One time charges 

Disposal of principal balance as at December 31, 2008 of $36,083 and interest receivable 

to April 30, 2010 of $4,109 over a four year period is requested. 

Method of recovery: Allocation to rate classes on basis of 2010 kWh sales.


EB-2009-0263 

Exhibit 9 

Tab 1 

Schedule 2 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

26 

27 

28 

29 

30 

1584 RSVA – Retail Transmission Network Charge 

Disposal of principal balance as at December 31, 2008 of $(908,899) and interest owing 



1586 RSVA – Retail Transmission Connection Charge 

Disposal of principal balance as at December 31, 2008 of $(924,005) and interest owing 



1588 RSVA – Power – Sub account Global Adjustment 

Festival Hydro has segregated the RSVA Power account into two segments for purposes 

of disposition – sub account global adjustment and remainder of 1588. 

Festival Hydro is requesting disposal of sub account global adjustment principal balance 

as at December 31, 2008 of $553,697 and interest owing to April 30, 2010 of $21,773 

over a four year period. 

Method of recovery: Allocation to rate classes on basis of 2010 kWh sales to non –RPP 

customers. Historical data of kWh sales to non-RPP customers has been used to 

determine the portion of 2010 forecasted kWh sales which would be sold to each class of 

non-RPP customers. 

1588 RSVA – Power – Remainder after Sub account Global Adjustment 

Festival Hydro has segregated the RSVA Power account into two segments for purposes 

of disposition – sub account global adjustment and remainder of 1588. 

Festival Hydro is requesting disposal of the remainder, after removal of the sub account 

global adjustment. Disposal of the remaining principal balance as at December 31, 2008 

of $179,553 and interest owing to April 30, 2010 of $131,591 over a four year period is 

requested. 


1508 Other Regulatory Assets - Sub-account OEB Cost Assessments 



Method of recovery: Allocation to rate classes on basis of distribution revenue.


EB-2009-0263 

Exhibit 9 

Tab 1 

Schedule 2 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

1508 Regulatory Assets - Sub-account Pension Costs 

Disposal of principal balance as at December 31, 2008 of $240,195 and interest 

receivable to April 30, 2010 of $36,895 over a four year period is requested. 

Method of recovery: Allocation to rate classes on basis of distribution revenue. 

1518 RCVA Retail 

Disposal of principal balance as at December 31, 2008 of $(57,020) and interest owing to 

April 30, 2010 of $(2,914) over a four year period is requested. 

Method of recovery: Allocation to rate classes on basis of number of customers per class. 

1548 RCVA STR 



Method of recovery: Allocation to rate classes on basis of number of customers per class. 

1550 Low Voltage (LV) Variance Account 



Method of recovery: Allocation to rate classes on basis of 2010 kWh sales.1565 

1565 CDM Expenditures and Recoveries and 

1566 CDM Contra Account 

These accounts are equal and offsetting at an amount of $670,623, which represents the 

full amount of Festival Hydro’s third tranche funding. Festival Hydro request that these 

balances be removed from the accounts. There is no disposition required. 

22 

23 

24 

25 

26 

27 

28 

29 

The variance account balances for which we are requesting disposition are presented in the 

following table. We are requesting disposition of the audited December 31, 2008 balances and 

the forecasted interest through April 30, 2010. An interest rate of 1.00% has been used to project 

carrying charges from January 1, 2009 to April 30, 2010. This rate is based on the Q2 2009 

Board approved rate for approved deferral and variance accounts. The total amount Festival 

Hydro request to return to customers is $(2,167,467) over a 4 year period commencing May 1, 

2010.


EB-2009-0263 

Exhibit 9 

Tab 1 

Schedule 2 



1 

Festival Hydro Inc. – Accounts Requested for Disposition. 


Account 

Number 

Principal Amounts 

as of Dec-31 2008 

Interest to 

Dec31-08 

Interest Jan- 

1 to Dec31- 

09 

Interest Jan1- 

10 to Apr30-10 

Total Claim 

RSVA - Wholesale Market Service Charge 1580 $ (1,385,017) $ (82,542) $ (13,850) $ (4,617) $ (1,486,026) 

RSVA - One-time Wholesale Market Service 1582 $ 36,083 $ 3,628 $ 361 $ 120 $ 40,192 

RSVA - Retail Transmission Network Charge 1584 $ (908,899) $ (61,078) $ (9,089) $ (3,030) $ (982,096) 

RSVA - Retail Transmission Connection Charge 1586 $ (924,005) $ (90,942) $ (9,240) $ (3,080) $ (1,027,267) 

RSVA - Power 1588/1589 $ 733,250 $ 143,587 $ 7,333 $ 2,444 $ 886,614 

Sub-Totals $ (2,448,588) $ (87,346) $ (24,486) $ (8,162) $ (2,568,583) 

Other Regulatory Assets 1508 $ 322,576 $ 47,478 $ 3,226 $ 1,075 $ 374,355 

Retail Cost Variance Account - Retail 1518 $ (57,020) $ (2,154) $ (570) $ (190) $ (59,934) 

Retail Cost Variance Account - STR 1548 $ 23,828 $ 3,086 $ 238 $ 79 $ 27,232 

Smart Meters Revenue and Capital 1555 $ - $ - $ - 

Smart Meter Expenses 1556 $ - $ - $ - 

Low Voltage 1550 $ 72,949 $ 3,651 $ 729 $ 243 $ 77,573 

Other Deferred Credits 2405 $ (18,110) 

$ - $ (60) $ (18,170) 

Sub-Totals $ 344,223 $ 52,061 $ 3,623 $ 1,147 $ 401,055 

Totals per column $ (2,104,365) $ (35,285) $ (20,863) $ (7,015) $ (2,167,527) 

2 

3 

Annual interest rate: 

Smart Meter Spending 

1.00% Smart Meters


EB-2009-0263 

Exhibit 9 

Tab 1 

Schedule 2 

Appendix A 


APPENDIX A 

METHODS OF DISPOSITION OF ACCOUNTS


EB-2009-0263 

Exhibit 9 

Tab 1 

Schedule 2 

Appendix A 



The following shows the details and calculations of the proposed regulatory asset rate rider by customer classification. 

Table 3 - Method of Disposition of Accounts 

Deferral and Variance Accounts: Amount ALLOCATOR Residential GS < 50 KW 

GS > 50 Non 

TOU GS > 50 TOU 

Residential 

Hensall Large Users 

Small 

Scattered 

Load 

Sentinel 

Lighting 

Street 

Lighting Total 

WMSC - Account 1580 $ (1,486,026) 

kWh $ (334,205) $ (159,769) $ (801,114) $ - $ (9,811) $ (168,844) $ (1,622) $ (605) $ (10,057) $ (1,486,026) 

One-Time WMSC - Account 1582 $ 40,192 

kWh $ 9,039 $ 4,321 $ 21,667 $ - $ 265 $ 4,567 $ 44 $ 16 $ 272 $ 40,192 

Network - Account 1584 $ (982,096) 

kWh $ (220,872) $ (105,589) $ (529,446) $ - $ (6,484) $ (111,587) $ (1,072) $ (400) $ (6,647) $ (982,096) 

Connection - Account 1586 $ (1,027,267) 

kWh $ (231,030) $ (110,446) $ (553,798) $ - $ (6,782) $ (116,719) $ (1,121) $ (418) $ (6,952) $ (1,027,267) 

Power - Account 1588 Sub acct Global Adjustment $ 575,470 Non RPP kWh $ 38,481 $ 20,246 $ 420,267 $ - $ 1,128 $ 91,439 $ - $ - $ 3,908 $ 575,470 

Power - Account 1588 (Remainder) $ 311,144 

kWh $ 69,976 $ 33,452 $ 167,737 $ - $ 2,054 $ 35,353 $ 340 $ 127 $ 2,106 $ 311,144 

Subtotal - RSVA $ (2,568,583) 

$ (668,610) $ (317,784) $ (1,274,686) $ - $ (19,629) $ (265,792) $ (3,432) $ (1,279) $ (17,370) $ (2,568,583) 

Other Regulatory Assets - Account 1508 $ 374,355 Dx Revenue $ 208,367 $ 63,091 $ 82,311 $ - $ 3,898 $ 11,717 $ 1,345 $ 261 $ 3,365 $ 374,355 

Retail Cost Variance Account - Acct 1518 $ (59,934) # of Customers $ (51,782) $ (5,956) $ (667) $ - $ (1,251) $ (6) $ (51) $ (194) $ (27) $ (59,934) 

Retail Cost Variance Account (STR) Acct 1548 $ 27,232 # of Customers $ 23,528 $ 2,706 $ 303 $ - $ 568 $ 3 $ 23 $ 88 $ 12 $ 27,232 

Low Voltage - Account 1550 $ 77,573 

kWh $ 17,446 $ 8,340 $ 41,820 $ - $ 512 $ 8,814 $ 85 $ 32 $ 525 $ 77,573 

Other Deferred Credits - Acct 2425 $ - 

Dx Revenue $ - $ - $ - $ - $ - $ - $ - $ - $ - $ 

- 

Subtotal - Non RSVA, Variable $ 419,226 

$ 197,558 $ 68,182 $ 123,767 $ - $ 3,728 $ 20,528 $ 1,401 $ 187 $ 3,875 $ 419,226 

Smart Meters Revenue and Capital, 1555 (Fixed) $ - # of Metered Customers $ - $ - $ - $ - $ - $ - $ - $ - $ - $ 

- 

Smart Meter Expenses, 1556 (Fixed) $ - # of Metered Customers $ - $ - $ - $ - $ - $ - $ - $ - $ - $ 

- 

Subtotal - Non RSVA Fixed $ - 

$ - $ - $ - $ - $ - $ - $ - $ - $ - $ 

- 

Total to be Recovered $ (2,149,357) 

$ (471,052) $ (249,602) $ (1,150,919) $ - $ (15,901) $ (245,264) $ (2,031) $ (1,093) $ (13,495) $ (2,149,357) 

Balance to be collected or refunded, Variable $ (2,149,357) 

$ (471,052) $ (249,602) $ (1,150,919) $ - $ (15,901) $ (245,264) $ (2,031) $ (1,093) $ (13,495) $ (2,149,357) 

Balance to be collected or refunded, Fixed $ - 

$ - $ - $ - $ - $ - $ - $ - $ - $ - $ 

- 

Number of years for Variable 4 

Number of years for Fixed 4 

Balance to be collected or refunded per year, Variable $ (537,339) 

$ (117,763) $ (62,400) $ (287,730) $ - $ (3,975) $ (61,316) $ (508) $ (273) $ (3,374) $ (537,339) 

Balance to be collected or refunded per year, Fixed $ - 

$ - $ - $ - $ - $ - $ - $ - $ - $ - $ 

- 

Class 

Residential GS < 50 KW GS > 50 GS > 50 TOU 

Residential 

Hensall 

Large Users 

Scattered 

Load 

Sentinel 

Lighting 

Street 

Lighting 

Deferral and Variance Account Rate Riders, Variable 

$ (0.0009) $ (0.0010) $ (0.3676) 

$ (0.0010) $ (0.4765) $ (0.0008) $ (0.4023) $ (0.2998) 

Billing Determinants kWh kWh kW kW kW kW kWh kW kW 

Deferral and Variance Account Rate Riders, Fixed (per 

month) $ - $ - $ - $ - 

$ - $ - 

$ - 

Billing Determinants # metered cust. # metered cust. # metered cust. # metered cust.


EB-2009-0263 

Exhibit 9 

Tab 1 

Schedule 3 



1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

PROPOSED RATES AND BILL IMPACTS 

The proposed rates and bill impacts that result from the disposal of the balances, as requested, 

are set out in Table 4 below. These represent the impact on a typical consumer in each class. 

Since there is a large net liability position owing, all customers will benefit positively over the 

next four years as a result of this rate rider. 

RATE CLASS PROPOSED RATE TOTAL BILL IMPACTS 

Residential $(0.0009)/kWh (0.072%) 

Residential Hensall $(0.0010)/kWh (0.090%) 

GS


Account 

Number 

Opening 

Principal 

Amounts as of 

Jan-1-05 1 

Transactions 

(additions) during 

2005, excluding 

interest and 

adjustments 6 

2005 

Transactions 

(reductions) Adjustments 

during 2005, during 2005 - 

excluding interest instructed by 

and adjustments 6 Board 2 

Adjustments 

during 2005 - 

other 3 

Closing 

Principal 

Balance as of 

Dec-31-05 

Opening 

Interest 


Jan-1-05 


EB-2009-0263 

Exhibit 9 

Tab 1 

Schedule 3 



Interest Jan-1 

to Dec31-05 

Closing 

Interest 


Dec-31-05 

RSVA - Wholesale Market Service Charge 1580 $ 618,769 $ 429,910 $ - $ - $ - $ 1,048,679 $ 133,659 $ 53,961 $ 187,620 

RSVA - One-time Wholesale Market Service 1582 $ 138,765 $ 36,083 $ - $ - $ - $ 174,848 $ 12,450 $ 11,052 $ 23,502 

RSVA - Retail Transmission Network Charge 1584 $ (153,971) $ (102,098) $ - $ - $ (15,904) $ (271,973) $ (8,898) $ (18,131) $ (27,029) 

RSVA - Retail Transmission Connection Charge 1586 $ (251,478) $ (253,552) $ - $ - $ 167,321 $ (337,709) $ (45,567) $ (29,261) $ (74,828) 

$ - $ - 

Sub-Totals $ 352,085 $ 110,343 $ - $ - $ 151,417 $ 613,845 $ 91,644 $ 17,621 $ 109,265 

$ - $ - 

Other Regulatory Assets - Sub-Account - OEB Cost Assessments 1508 $ - $ 109,610 $ (39,233) $ - $ 10,410 $ 80,787 $ - $ 2,502 $ 2,502 

Other Regulatory Assets - Sub-Account - Pension Contributions 1508 $ - $ 175,111 $ - $ - $ - $ 175,111 $ - $ 3,021 $ 3,021 

Other Regulatory Assets - Sub-Account - Other 7 1508 $ 12,145 $ - $ - $ - $ - $ 12,145 $ - $ - $ - 

Other Regulatory Assets - Sub-Account - Other 7 1508 $ - $ - $ - $ - $ - $ - $ - $ - $ - 

Other Regulatory Assets - Sub-Account - Other 7 1508 $ - $ - $ - $ - $ - $ - $ - $ - $ - 

Retail Cost Variance Account - Retail 1518 $ 96,427 $ (4,353) $ - $ - $ - $ 92,074 $ 11,827 $ 8,268 $ 20,095 

Retail Cost Variance Account - STR 1548 $ 69,527 $ 6,368 $ - $ - $ - $ 75,895 $ 6,966 $ 5,944 $ 12,910 

Misc. Deferred Debits 1525 $ 39,807 $ - $ - $ - $ - $ 39,807 $ 4,617 $ 2,769 $ 7,386 

LV Variance Account 1550 $ - $ - $ - $ - $ - $ - $ - $ - $ - 

Smart Meter Capital and Recovery Offset Variance - Sub-Account - Capital 1555 $ - $ - $ - $ - $ - $ - $ - $ - $ - 

Smart Meter Capital and Recovery Offset Variance - Sub-Account - Recoveries 1555 $ - $ - $ - $ - $ - $ - $ - $ - $ - 

Smart Meter Capital and Recovery Offset Variance - Sub-Account - Stranded Meter 1555 $ - $ - $ - $ - $ - $ - $ - $ - $ - 

Smart Meter OM&A Variance 1556 $ - $ - $ - $ - $ - $ - $ - $ - $ - 

Conservation and Demand Management Expenditures and Recoveries 1565 $ - $ 229,276 $ - $ - $ - $ 229,276 $ - $ - $ - 

CDM Contra 1566 $ - $ (551,353) $ - $ - $ - $ (551,353) $ - $ - $ - 

Qualifying Transition Costs 5 1570 $ 227,020 n/a n/a $ (30,266) $ - $ 196,754 $ 53,699 $ 15,726 $ 69,425 

Pre-Market Opening Energy Variances Total 5 1571 $ (182,229) n/a n/a $ - $ - $ (182,229) $ - $ (61,655) $ (61,655) 

Extra-Ordinary Event Costs 1572 $ - $ - $ - $ - $ - $ - $ - $ - $ - 

Deferred Rate Impact Amounts 1574 $ - $ - $ - $ - $ - $ - $ - $ - $ - 

Other Deferred Credits 2425 $ (162,675) $ (161,827) $ 36,152 $ - $ - $ (288,350) $ - $ - $ - 

Sub-Totals $ 100,022 $ (197,168) $ (3,081) $ (30,266) $ 10,410 $ (120,083) $ 77,109 $ (23,425) $ 53,684 

Deferred Payments in Lieu of Taxes 1562 

2006 PILs & Taxes Variance 1592 

Sub-Totals 

-162675 

see PILs reconciliation requested 


Total $ 452,107 $ (86,825) $ (3,081) $ (30,266) $ 161,827 $ 493,762 $ 168,753 $ (5,804) $ 162,949 

The following is not included in the total claim but is included on a memo basis: 

Deferred PILs Contra Account 8 1563 


RSVA - Power (including Global Adjustment) 1588 $ (625,598) $ (461,753) $ - $ - $ - $ (1,087,351) $ 164,344 $ (40,961) $ 123,383 

RSVA - Power - Sub-Account - Global Adjustment 4 1588 $ - $ (419,704) $ - $ - $ - $ (419,704) $ - $ (12,540) $ (12,540) 

Recovery of Regulatory Asset Balances 1590 $ (325,303) $ (164,597) $ - $ - $ - $ (489,900) $ (7,685) $ (31,755) $ (39,440) 

1

2006 


EB-2009-0263 

Exhibit 9 

Tab 1 

Schedule 3 



Opening 

Principal 


Jan-1-06 

Transactions 



interest and 

adjustments 6 

Transactions 

(reductions) 

during 2006, 

excluding interest 

and adjustments 6 

Adjustments 

during 2006 - 

instructed by 

Board 2 

Adjustments 

during 2006 - 

other 3 

Transfer of 

Boardapproved 

amounts to 

1590 as per 

2006 EDR 

Closing 

Principal 


Dec-31-06 

Opening 

Interest 


Jan-1-06 


to Dec31-06 

Transfer of 

Boardapproved 

amounts to 

1590 as per 

2006 EDR 

Closing 

Interest 


Dec-31-06 

$ 1,048,679 $ (745,813) 

$ - $ - $ (618,769) $ (315,903) $ 187,620 $ 19,879 $ (193,455) $ 14,044 

$ 174,848 $ - 

$ - $ - $ (138,765) $ 36,083 $ 23,502 $ 5,099 $ (25,863) $ 2,738 

$ (271,973) $ (114,640) 

$ - $ - $ 172,526 $ (214,087) $ (27,029) $ (13,437) $ 23,492 $ (16,974) 

$ (337,709) $ (297,660) 

$ - $ - $ 56,271 $ (579,098) $ (74,828) $ (20,428) $ 72,978 $ (22,278) 

$ - 

$ - $ - $ - 

$ - $ - 

$ 613,845 $ (1,158,113) 

$ - $ - $ (528,737) $ (1,073,005) $ 109,265 $ (8,887) $ (122,848) $ (22,470) 

$ - 

$ - $ - $ - 

$ - $ - 

$ 80,787 $ 18,644 $ (17,050) $ - $ - $ - $ 82,381 $ 2,502 $ 4,107 $ - $ 6,609 

$ 175,111 $ 65,084 $ - $ - $ - $ - $ 240,195 $ 3,021 $ 9,757 $ - $ 12,778 

$ 12,145 $ - $ - $ - $ - $ (12,145) $ - $ - $ - $ - $ - 

$ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - 

$ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - 

$ 92,074 $ (18,182) $ - $ - $ - $ (96,427) $ (22,535) $ 20,095 $ 2,314 $ (21,148) $ 1,261 

$ 75,895 $ 5,247 $ - $ - $ - $ (69,527) $ 11,615 $ 12,910 $ 2,442 $ (13,687) $ 1,665 

$ 39,807 $ - $ - $ - $ - $ (39,807) $ 0 $ 7,386 $ 962 $ (8,348) $ - 

$ - $ 96,835 $ (72,164) $ - $ - $ - $ 24,671 $ - $ 212 $ - $ 212 

$ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - 

$ - $ (44,066) $ - $ - $ - $ - $ (44,066) $ - $ (549) $ - $ (549) 

$ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - 

$ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - 

$ 229,276 $ 262,199 $ - $ - $ - $ - $ 491,475 $ - $ - $ - $ - 

$ (551,353) $ (115,100) $ - $ - $ - $ - $ (666,453) $ - $ - $ - $ - 

$ 196,754 n/a n/a $ - $ - $ (196,754) $ - $ 69,425 $ 6,218 $ (75,643) $ 

0 

$ (182,229) n/a n/a $ - $ - $ 182,229 $ - $ (61,655) $ (4,403) $ 66,058 $ - 

$ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - 

$ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - 

$ (288,350) $ (26,323) $ 94,027 $ - $ - $ - $ (220,646) $ - $ - $ - $ - 

$ (120,083) $ 244,338 $ 4,813 $ - $ - $ (232,431) $ (103,363) $ 53,684 $ 21,060 $ (52,768) $ 21,976 




$ 493,762 $ (913,775) $ 4,813 $ - $ - $ (761,168) $ (1,176,368) $ 162,949 $ 12,173 $ (175,616) $ (494) 


$ (1,087,351) $ 1,009,228 $ - $ - $ - $ 625,598 $ 547,475 $ 123,383 $ 87,586 $ (103,869) $ 107,100 

$ (419,704) $ 808,178 $ - $ - $ - $ - $ 388,474 $ (12,540) $ 6,374 $ - $ (6,166) 

$ (489,900) $ 24,171 $ - $ - $ - $ 415,055 $ (50,674) $ (39,440) $ (16,182) $ - $ (55,622) 

1 

2

2007 


EB-2009-0263 

Exhibit 9 

Tab 1 

Schedule 3 



Opening 

Principal 


Jan-1-07 

Transactions 



interest and 

adjustments 6 

Transactions 

(reductions) 

during 2007, 



Adjustments 

during 2007 - 

instructed by 

Board 2 

Adjustments 

during 2007 - 

other 3 

Closing 

Principal 


Dec-31-07 

Opening 

Interest 


Jan-1-07 


to Dec31-07 

Closing 

Interest 


Dec-31-07 

$ (315,903) $ (746,700) $ - $ - $ - $ (1,062,603) $ 14,044 $ (40,297) $ (26,253) 

$ 36,083 $ - $ - $ - $ - $ 36,083 $ 2,738 $ 483 $ 3,221 

$ (214,087) $ (268,107) $ - $ - $ (2,651) $ (484,845) $ (16,974) $ (15,016) $ (31,990) 

$ (579,098) $ (318,500) $ - $ - $ 27,885 $ (869,713) $ (22,278) $ (31,619) $ (53,897) 

$ - $ - $ - $ - 

$ - 

$ (1,073,005) $ (1,333,307) $ - $ - $ 25,234 $ (2,381,078) $ (22,470) $ (86,449) $ (108,919) 

$ - $ - $ - $ - 

$ - 

$ 82,381 $ - $ - $ - $ - $ 82,381 $ 6,609 $ 3,898 $ 10,507 

$ 240,195 $ - $ - $ - $ - $ 240,195 $ 12,778 $ 11,355 $ 24,133 

$ - $ - $ - $ - $ - $ - $ - $ - $ - 

$ - $ - $ - $ - $ - $ - $ - $ - $ - 

$ - $ - $ - $ - $ - $ - $ - $ - $ - 

$ (22,535) $ (19,977) $ - $ - $ - $ (42,512) $ 1,261 $ (1,529) $ (268) 

$ 11,615 $ 5,590 $ - $ - $ - $ 17,205 $ 1,665 $ 651 $ 2,316 

$ 0 $ - $ - $ - $ - $ 0 $ - $ - $ - 

$ 24,671 $ 166,549 $ (136,787) $ - $ - $ 54,433 $ 212 $ 1,418 $ 1,630 

$ - $ - $ - $ - $ - $ - $ - $ - $ - 

$ (44,066) $ (64,041) $ - $ - $ - $ (108,107) $ (549) $ (3,564) $ (4,113) 

$ - $ - $ - $ - $ - $ - $ - $ - $ - 

$ - $ - $ - $ - $ - $ - $ - $ - $ - 

$ 491,475 $ 179,149 $ - $ - $ - $ 670,624 $ - $ - $ - 

$ (666,453) $ (4,170) $ - $ - $ - $ (670,623) $ - $ - $ - 

$ - n/a n/a $ - $ - $ - $ 0 $ - $ 

0 

$ - n/a n/a $ - $ - $ - $ - $ - $ - 

$ - $ - $ - $ - $ - $ - $ - $ - $ - 

$ - $ - $ - $ - $ - $ - $ - $ - $ - 

$ (220,646) $ - $ 101,268 $ - $ - $ (119,378) $ - $ - $ - 

$ (103,363) $ 263,100 $ (35,519) $ - $ - $ 124,218 $ 21,976 $ 12,229 $ 34,205 




$ (1,176,368) $ (1,070,207) $ (35,519) $ - $ 25,234 $ (2,256,860) $ (494) $ (74,220) $ (74,713) 

1 


$ 547,475 $ (109,223) $ - $ - $ - $ 438,252 $ 107,100 $ 23,005 $ 130,105 

$ 388,474 $ (123,892) $ - $ - $ - $ 264,582 $ (6,166) $ 8,360 $ 2,194 

$ (50,674) $ 108,564 $ - $ - $ - $ 57,890 $ (55,622) $ (104) $ (55,725)

2008 


EB-2009-0263 

Exhibit 9 

Tab 1 

Schedule 3 



Opening 

Principal 


Jan-1-08 

Transactions 



interest and 

adjustments 6 

Transactions 

(reductions) 

during 2008, 



Adjustments 

during 2008 - 

instructed by 

Board 2 

Adjustments 

during 2008 - 

other 3 

Closing 

Principal 


Dec-31-08 

Opening 

Interest 


Jan-1-08 


to Dec31-08 

Closing 

Interest 


Dec-31-08 

$ (1,062,603) $ (322,414) $ - $ - $ - $ (1,385,017) $ (26,253) $ (56,289) $ (82,542) 

$ 36,083 $ - $ - $ - $ - $ 36,083 $ 3,221 $ 407 $ 3,628 

$ (484,845) $ (424,054) $ - $ - $ - $ (908,899) $ (31,990) $ (29,088) $ (61,078) 

$ (869,713) $ (54,292) $ - $ - $ - $ (924,005) $ (53,897) $ (37,045) $ (90,942) 

$ - $ - $ - $ - 

$ - 

$ (2,381,078) $ (800,760) $ - $ - $ - $ (3,181,838) $ (108,919) $ (122,015) $ (230,934) 

$ - $ - $ - $ - 

$ - 

$ 82,381 $ - $ - $ - $ - $ 82,381 $ 10,507 $ 3,279 $ 13,786 

$ 240,195 $ - $ - $ - $ - $ 240,195 $ 24,133 $ 9,559 $ 33,692 

$ - $ - $ - $ - $ - $ - $ - $ - $ - 

$ - $ - $ - $ - $ - $ - $ - $ - $ - 

$ - $ - $ - $ - $ - $ - $ - $ - $ - 

$ (42,512) $ (14,508) $ - $ - $ - $ (57,020) $ (268) $ (1,886) $ (2,154) 

$ 17,205 $ 6,623 $ - $ - $ - $ 23,828 $ 2,316 $ 770 $ 3,086 

$ 0 $ 1,145 $ - $ - $ - $ 1,145 $ - $ - $ - 

$ 54,433 $ 153,284 $ (134,768) $ - $ - $ 72,949 $ 1,630 $ 2,021 $ 3,651 

$ - $ - $ - $ - $ - $ - $ - $ - $ - 

$ (108,107) $ (56,766) $ - $ - $ - $ (164,873) $ (4,113) $ (5,130) $ (9,243) 

$ - $ - $ - $ - $ - $ - $ - $ - $ - 

$ - $ - $ - $ - $ - $ - $ - $ - $ - 

$ 670,624 $ - $ - $ - $ - $ 670,624 $ - $ - $ - 

$ (670,623) $ - $ - $ - $ - $ (670,623) $ - $ - $ - 

$ - n/a n/a $ - $ - $ - $ 0 $ - $ 

0 

$ - n/a n/a $ - $ - $ - $ - $ - $ - 

$ - $ - $ - $ - $ - $ - $ - $ - $ - 

$ - $ - $ - $ - $ - $ - $ - $ - $ - 

$ (119,378) $ - $ 101,268 $ - $ - $ (18,110) $ - $ - $ - 

$ 124,218 $ 89,778 $ (33,500) $ - $ - $ 180,496 $ 34,205 $ 8,613 $ 42,818 




$ (2,256,860) $ (710,982) $ (33,500) $ - $ - $ (3,001,342) $ (74,713) $ (113,402) $ (188,115) 

1 


$ 438,252 $ 294,998 $ - $ - $ - $ 733,250 $ 130,105 $ 13,482 $ 143,587 

$ 264,582 $ 289,115 $ - $ - $ - $ 553,697 $ 2,194 $ 12,196 $ 14,390 

$ 57,890 $ 36,934 $ - $ - $ - $ 94,824 $ (55,725) $ 3,150 $ (52,575)


EB-2009-0263 

Exhibit 9 

Tab 1 

Schedule 3 



Projected Interest from Jan 1, Projected Interest from Jan 1, 

Projected Interest on Projected Interest on Claim before 

Forecasted 

Forecasted 

Dec 31 -08 balance Dec 31 -08 balance from 

2009 to April 30, 2010 on 2010 to April 30, 2010 on 

Forecasted 

Transactions, 

Total Claim 

Transactions, Excluding 

from Jan 1, 2009 to Jan 1, 2010 to April 30, 

Forecasted Transx (Excl Forecasted Transx (Excl 

Transactions Excluding Interest from 

Jan 1, 2009 to Dec 31, 

Interest from Jan 1, Interest) from Jan 1, 2009 to 

Dec 31, 2009 9 2010 9 Interest) from Jan 1, 2010 to 

2010 to April 30, 2010 December 31, 2009 

April 30, 2010 

2009 

$ (13,850) $ (4,617) $ (1,486,026) $ (257,931) $ (85,977) $ (3,439) $ (287) $ (1,833,660) 

$ 361 $ 120 $ 40,192 $ - $ - $ - $ - $ 

40,192 

$ (9,089) $ (3,030) $ (982,096) $ (169,622) $ (56,541) $ (2,256) $ (188) $ (1,210,702) 

$ (9,240) $ (3,080) $ (1,027,267) $ (21,717) $ (7,239) $ (289) $ (24) $ (1,056,536) 

$ (31,818) $ (10,606) $ (3,455,197) $ (449,270) $ (149,757) $ (5,984) $ (499) $ (4,060,706) 

$ 824 $ 275 $ 97,265 $ - $ - $ - $ - $ 

97,265 

$ 2,402 $ 801 $ 277,090 $ - $ - $ - $ - $ 

277,090 

$ - 

$ 

- 

$ - 

$ 

- 

$ - 

$ 

- 

$ (570) $ (190) $ (59,934) $ (18,000) $ (6,000) $ (240) $ (20) $ 

(84,194) 

$ 238 $ 79 $ 27,232 $ 6,000 $ 2,000 $ 80 $ 7 $ 

35,318 

$ - $ - $ 1,145 $ (1,145) $ - $ (15) $ - $ 

(15) 

$ 729 $ 243 $ 77,573 $ 25,000 $ 8,333 $ 333 $ 28 $ 

111,268 

$ - $ - $ - $ 249,020 $ 2,240,192 $ 3,320 $ 7,467 $ 2,500,000 

$ (1,649) $ (550) $ (176,314) $ (175,100) $ (228,972) $ (2,335) $ (763) $ 

(583,484) 

$ - $ - $ - 

$ - $ - $ 

- 

$ - $ - $ - 

$ 149,502 $ - $ 498 $ 

150,000 

$ 670,624 

$ 

670,624 

$ - $ - $ (670,623) 

$ 

(670,623) 

$ - $ - $ 0 

$ 

0 

$ - $ - $ - 

$ 

- 

$ - $ - $ - 

$ 

- 

$ - $ - $ - 

$ 

- 

$ - $ - $ (18,110) $ 55,479 $ 7,900 $ - $ - $ 

45,269 

$ 1,975 $ 658 $ 225,948 $ 141,254 $ 2,172,955 $ 1,144 $ 7,217 $ 2,548,517 

$ - 

$ 

- 

$ (29,844) $ (9,948) $ (3,229,249) $ (308,016) $ 2,023,199 $ (4,840) $ 6,718 $ (1,512,188) 

1 

$ 7,333 $ 2,444 $ 886,614 $ 50,000 $ 16,667 $ 667 $ 56 $ 

954,003 

$ 5,537 $ 1,846 $ 575,470 $ - $ - $ - $ - $ 

575,470 

$ 2,323 $ 774 $ 45,346 $ - $ - $ - $ - $ 

45,346

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

25 

26 

27 

28 

29 

SMART METERS 


EB-2009-0263 

Exhibit 9 

Tab 1 

Schedule 4 



On October 28, the Ontario Energy Board issued Guideline G-2008-0002 Smart Meter Funding 

and Cost Recovery. The guideline sets out the Board’s filing instructions in relation to the 

funding of, and the recovery of costs associated with smart meter activities conducted by 

electricity distributors. 

Festival Hydro has been authorized to conduct smart meter activities by virtue of paragraph 8 of 

Section 1(1) of O. Reg. 427/06, conditional on our meters being acquired pursuant to and in 

compliance with a Request for Proposal issued by London Hydro Inc. A letter was received 

from PRP International Fairness Advisory Services regarding the Attestation of the Fairness 

Commissioner for the London Hydro & Consortium Smart Meter Project as it relates specifically 

to the two highest ranked proponents for Festival Hydro. Refer to Appendix B to see a copy of 

this letter. Festival Hydro plans have all smart meters fully deployed by December 31, 2010 

with a total capital outlay of $2.5 million. Appendix 2-S below details the installations, capital 

expenditures, operating expenses and funding adder revenues to be collected over the 

forthcoming years. A continuity of the smart meter accounts are provided above as part of the 

Deferral and Variance Account Continuity Schedule. 

As Festival Hydro intends to install smart meters in the 2010 rate test year, Festival Hydro is 

requesting the standard $1.00 smart meter funding adder be approved by the Board as 

part of the 2010 Cost of Service rate application. Festival Hydro is proposing no changes to 

its current Board-approved smart meter funding adder of $1.00, which was approved as part of 

Festival Hydro’s 2009 IRM Application. The rater rider will continue to be applicable to 

Residential, Residential Hensall, G.S. < 50 kW, G.S. > 50 kW and Large Use. 

No disposition of accounts 1555 and 1556 is requested at this time.

1 

2 

3 

4 

OEB Appendix 2-S 

Smart Meters 


Year Smart Meters Installed Percentage of 

applicable 

customers 

converted (%) 

Residential GS < Other 1 

50 kW 

Funding 

Adder 

Revenues 

Collected* 


EB-2009-0263 

Exhibit 9 

Tab 1 

Schedule 4 



Account 1555 Account 1556 

Capital 

Expenditures 

2006 0 0 0 $44, 058 0 0 

Operating 

Expenses 

2007 0 0 0 $68,162 0 0 

2008 0 0 0 $61,896 0 0 

2009 0 0 0 $175,368 $250,000 0 

2010 17,528 1,968 0 100.0% $234,000 $2,250,000 $150,000 

2011 (and 

beyond) 

(if 

required) 

Estimate 

$235,000 

per year 

based on 

$1.00 rate 

adder


EB-2009-0263 

Exhibit 9 

Tab 1 

Schedule 4 

Appendix B 


APPENDIX B 

LETTER FROM PRP INTERNATIONAL FAIRNESS ADVISORY SERVICES


EB-2009-0263 

Exhibit 9 

Tab 1 

Schedule 4 

Appendix B 


Filed August 28, 2009

Festival Hydro's Notice of Application for Electrical Distribution Change

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