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Decision 2006-002

ENMAX Power Corporation 2005 – 2006 Distribution Tariff January 13, 2006

ALBERTA ENERGY AND UTILITIES BOARD Decision 2006-002: ENMAX Power Corporation 2005 – 2006 Distribution Tariff Application No. 1380613 January 13, 2006 Published by Alberta Energy and Utilities Board 640 – 5 Avenue SW Calgary, Alberta T2P 3G4 Telephone: (403) 297-8311 Fax: (403) 297-7040 Web site: www.eub.gov.ab.ca

http://www.eub.gov.ab.ca/

Contents

1 INTRODUCTION................................................................................................................. 1

2 BACKGROUND ................................................................................................................... 2 2.1 Summary of Outstanding Board Directions/Directives ................................................. 3

3 LOAD AND REVENUE FORECAST ................................................................................ 3 3.1 Overview........................................................................................................................ 3 3.2 Economic Outlook ......................................................................................................... 4 3.3 Forecasting Methodology .............................................................................................. 5

3.3.1 Key Forecast Assumptions ............................................................................... 5 3.3.2 Residential Forecast .......................................................................................... 5 3.3.3 Commercial Forecast ........................................................................................ 6 3.3.4 Streetlighting Forecast ...................................................................................... 7 3.3.5 Obtaining Monthly Amounts from an Annual Forecast ................................... 7 3.3.6 Forecast Accuracy............................................................................................. 8 3.3.7 Potential Unexpected Factors ........................................................................... 8

3.4 Loss Factors ................................................................................................................... 8 3.5 Revenue Forecast Results .............................................................................................. 8

4 OPERATING EXPENSES................................................................................................... 9 4.1 Overview........................................................................................................................ 9 4.2 Staffing Levels and Vacant Position Allowance............................................................ 9 4.3 Other Staffing Level Matters ....................................................................................... 10 4.4 Operating, Maintenance and Administration (OM&A) by Function........................... 11

4.4.1 Distribution ..................................................................................................... 12 4.4.2 Network........................................................................................................... 13 4.4.3 Wholesale Services ......................................................................................... 14 4.4.4 General............................................................................................................ 15

4.5 Operating Expenses – Shared Services ........................................................................ 16 4.5.1 Shared Services Study..................................................................................... 17 4.5.2 Reasonableness of ENMAX Corporation Shared Services Costs .................. 19 4.5.3 Shared Services Allocations ........................................................................... 19 4.5.4 Shared Services 2 – South Service Centre Operating Costs ........................... 23

4.6 Incentive Compensation............................................................................................... 24 4.7 Operating Expenses Capitalized .................................................................................. 26 4.8 Management/Professional Compensation.................................................................... 27 4.9 Executive Compensation.............................................................................................. 28

5 OTHER REVENUE REQUIREMENTS.......................................................................... 29 5.1 Overview...................................................................................................................... 29 5.2 SAS Charge Forecast ................................................................................................... 30

5.2.1 Forecast ........................................................................................................... 30 5.2.2 Forecast Methodology .................................................................................... 30 5.2.3 Transmission Access Deferral Account and Rider ......................................... 31

5.3 Hearing Cost Reserve................................................................................................... 32 5.4 Revenue Requirement Offsets...................................................................................... 33 5.5 Pension Costs ............................................................................................................... 34 5.6 AESO Customer Contribution Carrying Charges Deferral Account ........................... 36

EUB Decision 2006-002 (January 13, 2006) • i

5.7 Uniform System of Accounts Deferral Account.......................................................... 37

6 RATE BASE ........................................................................................................................ 37 6.1 General ......................................................................................................................... 37

6.1.1 Overhead Capitalization Rate ......................................................................... 37 6.1.2 Review of Prior Year Large Capital Project Additions .................................. 38 6.1.3 Capital Expenditures....................................................................................... 39

6.2 Distribution .................................................................................................................. 39 6.3 Network........................................................................................................................ 39

6.3.1 Separation of Residential and Non-Residential Development........................ 40 6.3.2 Project C123 – Network 25kV System........................................................... 40 6.3.3 Project C10097 – Network Vault Protection .................................................. 40 6.3.4 Historical Forecasting Accuracy: System Infrastructure Development –

Quality of Supply............................................................................................ 41 6.3.5 Reliability of the Network System.................................................................. 41

6.4 Wholesale Services ...................................................................................................... 42 6.5 Information Technology, General Plant and Other...................................................... 42 6.6 Necessary Working Capital.......................................................................................... 43

6.6.1 Lead/Lags........................................................................................................ 43 6.6.2 Materials and Supplies Inventory ................................................................... 45 6.6.3 Customer Deposits .......................................................................................... 45 6.6.4 SAS Deferral Account .................................................................................... 45 6.6.5 Hearing Cost Reserve Account....................................................................... 45 6.6.6 AESO Deferral Account ................................................................................. 45 6.6.7 Goods and Services Tax (GST) ...................................................................... 46

7 DEPRECIATION ............................................................................................................... 46 7.1 Depreciation Overview ................................................................................................ 46 7.2 ELG Method ................................................................................................................ 46

7.2.1 Synchronization of Annual Accruals with Accumulated Accruals ................ 46 7.2.2 ELG Data Requirements ................................................................................. 50

7.3 Simplified Life Estimation Methods............................................................................ 50 7.3.1 General............................................................................................................ 50 7.3.2 Distribution Accounts ..................................................................................... 51 7.3.3 Network Accounts .......................................................................................... 53 7.3.4 General Accounts............................................................................................ 54

7.4 Treatment of Net Salvage ............................................................................................ 54 7.4.1 General............................................................................................................ 54 7.4.2 Salvage Data Requirements ............................................................................ 55

8 RETURN ON RATE BASE ............................................................................................... 55 8.1 Overview...................................................................................................................... 55 8.2 Construction Funds Collected From Customers (CFCFC) .......................................... 55 8.3 Capital Structure .......................................................................................................... 63 8.4 Cost of Debt ................................................................................................................. 63 8.5 Cost of Equity .............................................................................................................. 64

9 RENT PAID BY EPC FOR ENMAX PLACE ................................................................. 65

10 REFILING PROCESS ....................................................................................................... 66

ii • EUB Decision 2006-002 (January 13, 2006)

11 ORDER ................................................................................................................................ 67

APPENDIX 1 – HEARING PARTICIPANTS......................................................................... 69

APPENDIX 2 – SUMMARY OF BOARD DIRECTIONS ..................................................... 71

APPENDIX 3 – SUMMARY OF BOARD FINDINGS AND CONCLUSIONS................... 77

APPENDIX 4 – BOARD DETERMINED VACANT POSITION ALLOWANCE.............. 82

APPENDIX 5 – BOARD TEST - SALARIES AND WAGES ................................................ 83

APPENDIX 6 – BOARD DETERMINED MANAGEMENT SALARIES............................ 84

APPENDIX 7 – BOARD DETERMINED EXECUTIVE COMPENSATION..................... 85

APPENDIX 8 – BOARD APPROVED ELG METHOD......................................................... 86

APPENDIX 9 – BOARD APPROVED DEPRECIATION RATES....................................... 87

APPENDIX 10 – BOARD CALCULATIONS ILLUSTRATING TREATMENT OF CFCFC ............................................................................................................ 88

List of Tables Table 1. EPC Load and Revenue Forecast.............................................................................. 4

Table 2. ENMAX Corporation Shared Services Allocated to EPC .................................... 17

Table 3. Summary of Changes to Regulatory Hearing Cost Reserve Account.................. 33

Table 4. Appropriateness of a Simplified Depreciation Method......................................... 52

Table 5. Accounts Accepted for ELG Analysis Method....................................................... 53

EUB Decision 2006-002 (January 13, 2006) • iii

ALBERTA ENERGY AND UTILITIES BOARD Calgary Alberta ENMAX POWER CORPORATION Decision 2006-002 2005 – 2006 DISTRIBUTION TARIFF Application No. 1380613 1 INTRODUCTION

The Alberta Energy and Utilities Board (Board or EUB) received an Application (the Application), dated January 14, 2005, from ENMAX Power Corporation (EPC) concerning its 2005/2006 Distribution Tariff (DT) Revenue Requirements pursuant to section 1021 of the Electric Utilities Act, S.A. 2003, c. E-5.1 (EUA). The Application requested approval of EPC’s proposed revenue requirements for 2005 and 2006, in the amounts of $169.8 million and $179.0 million, respectively. On August 29, 2005 EPC revised the proposed revenue requirements for 2005 and 2006 to $170.1 million and $178.2 million, respectively. In response to previous Board directions contained in Decision 2004-066,2 EPC undertook several studies and incorporated the results in the Application. On January 25, 2005, the Board circulated a Notice of Hearing to interested parties on the Board’s EPC 2004 General Tariff Application (GTA) distribution list. The Notice of Hearing was also published in the Edmonton Sun, the Edmonton Journal, the Calgary Sun and the Calgary Herald on January 31, 2005. The Board established the following process schedule to deal with the Application: Register as an Intervener February 14, 2005 Issues for Clarification at Technical Meeting to EPC March 14, 2005 Technical Meeting March 21, 2005 Supplemental Information from EPC April 4, 2005 Information Requests (IRs) to EPC April 25, 2005 IR Responses from EPC May 24, 2005 Intervener Evidence June 13, 2005 IRs to Interveners June 27, 2005 IR Responses from Interveners July 11, 2005 Rebuttal Evidence August 8, 2005 Hearing Commencement August 29, 2005 Argument September 28, 2005 Reply October 18, 2005

The Board introduced two new processes, the Technical Meeting and Supplemental Information from the Applicant, into the proceeding in order to increase the understanding of the Application and relevant issues by the Board and interested parties. The Board considered that these

1 The Application mistakenly refers to section 103 of the EUA. 2 Decision 2004-066 – ENMAX Power Corporation 2004 Distribution Tariff Application Part B: 2004 Final

Distribution Tariff, dated August 13, 2004

EUB Decision 2006-002 (January 13, 2006) • 1

http://www.eub.gov.ab.ca/bbs/documents/decisions/2004/2004-066.pdf

2005–2006 DT ENMAX Power Corporation

additional processes would allow for more concise and focused interventions, and thereby help to reduce hearing time and overall costs. The Technical Meeting also presented an opportunity for EPC to provide interested parties with an informal opportunity to seek clarification of those aspects of the Application in which they were interested prior to the submission of IRs. Subsequent to the Technical Meeting, EPC provided Supplemental Information, which addressed issues and areas of concern identified during the Technical Meeting. A hearing was held at the Board’s Calgary office between August 29, 2005 and September 7, 2005. The Panel assigned to deal with the Application consisted of N. W. MacDonald, Presiding, R. G. Lock, and J. I. Douglas. Those who attended the hearing are listed in Appendix 1. The Board considers that the record closed on October 18, 2005 upon receipt of Reply Argument. 2 BACKGROUND

EPC’s application to the Board contained information concerning its forecast of the costs of providing DT service to its customers for the 2005/2006 test period. The Application also contained a forecast of the number, consumption level, and demand level of the DT customers it expected to serve in 2005 and 2006. EPC’s forecast load growth in 2005 would result in a 2.7% increase in revenue,3 and thereby largely offset its forecast increase in costs. EPC forecast a revenue requirement increase for 2005 of 0.1% from 2004.4

EPC forecast that load growth in 2006 would result in a 2.3% increase in revenue over 2005. EPC forecast a revenue requirement increase for 2006 of 2.6% over 2005.5

EPC’s applied for revenue requirements include the following:

• a new composite depreciation rate for Distribution and Network assets of 3.15%, to be effective January 1, 2005;

• continuation of the Hearing Cost Reserve (HCR) Account; • continuation of the Transmission Access Charge (TAC) deferral account and rider; • continuation of the Alberta Electric System Operator (AESO) Charge Deferral Account; • carrying costs of $0.2 million for 20066 relating to a customer contribution to the AESO

in respect of substations that are required to maintain the safety and reliability of EPC’s electric distribution system;7 and

• operating expense and capital expense deferral accounts to deal with the scoping and implementation costs associated with the development and implementation of the uniform system of accounts.8

3 Exhibit 003, p. 11 4 EPC Argument 5 EPC Argument 6 Exhibit 235 7 Exhibit 003, p. 1

8 Transcript Volume 1, p. 37, line 19 to p. 38, line 3

2 • EUB Decision 2006-002 (January 13, 2006)

2005 –2006 DT ENMAX Power Corporation

2.1 Summary of Outstanding Board Directions/Directives The Board ordered EPC to comply with 39 directives in Decision 2004-066. In its application, EPC listed how it had complied with the first 20 of the Board directives.9 EPC stated that the remaining directives were related to its Phase II application, and as such would be included therein. The Board has reviewed EPC’s compliance with directives 1-20 and considers that EPC has taken action towards satisfying each of these directives. The Board notes that in certain instances, such as EPC’s proposed approach to Depreciation, it does not consider that EPC is in complete alignment with the directives from 2004-066. However, the Board will provide further direction later in this Decision concerning any directive it considers requires further action by EPC. The Board is therefore satisfied that the directives 1-20 of Decision 2004-066 have been satisfied in EPC’s application or will be satisfied in the EPC refiling requested later in this Decision. The Board expects that EPC will satisfy the remaining 19 directives of Decision 2004-066 in its upcoming Phase II application. 3 LOAD AND REVENUE FORECAST

3.1 Overview EPC forecast an increase in energy delivery of 3.1% for 2005 over the current estimate for 2004,10 and a further increase of 2.3% in 2006 over the 2005 forecast. The revenue associated with this energy forecast, including the proposed rate increases, is projected to be $170.1 million and $178.2 million for the 2005 and 2006 test years, respectively.

9 Exhibit 003, p. 3 10 The estimate for 2004 is based on actual values for January to September and forecast values for October to

December. EUB Decision 2006-002 (January 13, 2006) • 3



These forecasts are summarized in the following table: Table 1. EPC Load and Revenue Forecast

FORECAST

ACTUAL 2003

ESTIMATE 2004

APPLICATION 2005

APPLICATION 2006

Delivered Energy (GWh) Growth Rate (%)

7,926

8,039 1.4

8,286 3.1

8,479 2.3

Average Sites (No.) Growth Rate (%)

367,951 378,207 2.8

390,079 3.1

399,662 2.5

DT Revenue From Existing Rates ($ Millions) Growth Rate (%)

177.1

165.3 -9.2

169.8 2.7

173.7 2.5

DT Proposed Revenue Increase ($ Millions) - 5.3 DT Proposed Revenue Increase (%) - 3.05% DT Proposed Revenue ($ Millions) 170.1 178.2

EPC’s revenue forecast on existing rates is based on the combination of EPC’s forecast energy, customers, and billing demand multiplied by EPC’s existing rates. 3.2 Economic Outlook EPC’s forecasts rely on three key forecast variables: Calgary housing starts, Calgary population growth and Alberta real Gross Domestic Product (GDP). The consensus forecast used by EPC for the 2005/2006 timeframe, at the time of its Application, forecasts that Calgary housing starts are expected to decrease from approximately 12,000 units in 2004 to 11,400 in 2005 and to 10,700 units in 2006. Population growth is forecast to remain relatively constant at approximately 2% per year over the forecast period. In addition, Alberta’s economic growth is expected to slow from 3.6% in 2004 to 3.5% in 2005 and to 3% by 2006. During the hearing, the Consumers Group (CG) requested that EPC update its economic forecast with updated numbers which were not available to EPC at the time that it developed its forecast. EPC undertook to do this analysis and showed the impact of using updated numbers to be negligible.11 The Board appreciates the willingness of EPC to undertake this update. Generally, the Board considers that even if the impact of this update had been significant, the Board would not have allowed an update of only certain, but not all, aspects of the Application within the test year. To be clear, the Board does not take issue with comparing past forecasts to actuals for prior years to judge the forecasting ability of the applicant. As discussed in later sections, this is a very important area to explore when judging any type of forecast, and is typically given a significant amount of weight. The Board approves the EPC economic forecast as set out in the Application.

11 Exhibit 326-16



3.3 Forecasting Methodology The energy and site forecasts were developed using the same methodology as used in the 2004 DT Application, and which was approved by the EUB in Decision 2004-066. This methodology is based on econometric modeling and share analysis that combines historical data with the forecast economic and population growth described in the previous section. 3.3.1 Key Forecast Assumptions The key forecast assumptions used by EPC for the 2005/2006 forecast are:

• Growth in total delivered energy is primarily driven by demographic/economic growth. • The forecast monthly patterns of energy consumption (weather normalized) and site

counts by DT rate class are the same as for 2002 and 2003. • No significant distributed generation will be built in 2005 or 2006. • No observable change in historical conservation trends.

The CG did not supply argument or reply on these assumptions. 3.3.2 Residential Forecast EPC forecast Residential (D100) energy using trend analysis by applying the average of 2002 to 2003 weather normalized (monthly) kWh per site to the forecast D100 average monthly sites. EPC estimated the average monthly number of Residential (D100) sites econometrically as a function of cumulative Calgary housing starts for the period 1986 to 2003 using the following equation:

Number of Residential sites = a + b*Cumulative Calgary housing starts EPC forecast the Residential energy to increase from an estimated 2,350 GWh in 2004 to 2,438 GWh in 2005 and to 2,497 GWh in 2006. EPC forecast Residential average monthly site counts to increase from 343,316 in 2004 to 354,487 in 2005 and to 363,380 in 2006. The CG submitted that over the most recent 4-year period of 2001-2004, EPC demonstrated a consistent trend (other than in 2004) in under-forecasting its annual Residential sales. EPC noted that half of the upward trend sited by the CG was due to a rounding error, and as such the forecast had been higher in two years and lower in two years. EPC further noted that if a six-year trend was analyzed, there was a clear trend of over-forecasting its annual Residential sales. The Board does not consider that there is a clear trend of under or over forecasting present in EPC’s Residential consumption forecast history. The Board considers EPC’s Residential energy consumption forecast to be reasonable and approves it as set out in the Application. The CG submitted that for 2004, EPC had forecast 343,100 sites, 501 sites less than the 2003 actual of 343,601 sites, and that EPC should be directed to use this 2004 data in its regression model, which was based on the actual number of sites and housing starts for the period 1986 to 2003. EPC noted that it was within 0.1% of forecast sites in 2004, and that adding this additional year would not materially impact the results of the regression model. The Board agrees with EPC that




this additional year of information will not materially impact the EPC Residential site forecast, and notes that complete 2004 site data was not available to EPC at the time that it developed its forecast. The Board has commented in a previous section on the use of selected updated forecast information, unavailable at the time of filing, well after an application’s filing date. The Board considers that EPC’s 2004 Residential site forecast error of 0.1% is indicative of a sound forecasting process, and therefore approves the EPC forecast number of Residential sites as set out in the Application. 3.3.3 Commercial Forecast EPC forecast total Commercial (D200, D300, D310 and D410) energy as a function of Alberta Real GDP and total Commercial energy in the preceding year for the period 1987 to 2003, using the following equation:

Commercial energy (t) = a + b*Alberta Real GDP (t) + c*Commercial energy (t-1) EPC forecast total Commercial energy to grow from 5,600 GWh in 2004, to 5,765 GWh in 2005 and to 5,897 GWh in 2006. EPC forecast total Commercial site counts to increase from 34,886 in 2004 to 35,587 in 2005 and to 36,277 in 2006. EPC noted that with the Board’s approval in Decision 2004-082,12 a number of sites from the former D300 and D400 rate classes have been redistributed among the D300, D310 and D410 rate classes. EPC allocated the forecast total Commercial kWh into the approved commercial classes (D200, D300, D310 and D410) based on the 2002/2003 annual average weather normalized distribution of these rates to Total Commercial. EPC forecast the site counts for each of the commercial DT rate classes (D200, D300, D310 and D410) for year end by calculating the 2002/2003 average kWh per site (weather normalized) for December and then applying the resulting averages to the December kWh forecast for each DT rate class. EPC forecast billing demand for D300, D310 and D410 using the 2002/2003 average monthly relationship between billing demands and energy. Total billing demand is forecast to rise from 1,414 MVA in 2004 to 1,451 MVA in 2005 and to 1,484 MVA in 2006 or by 2.6% and 2.3%, respectively. The CG recommended in argument that the Board direct EPC to correct the December forecast number of sites so there is consistency in the growth in number of D200 and D300 sites in relation to historical growth, and further that the corresponding sales forecasts and the resulting revenues should also be corrected in EPC’s refiling. EPC set out in reply that the revenue impact of the site forecast error would be less than 0.01% for both the 2005 and 2006 test years. The Board has verified the revenue impact of the site errors and is in agreement with EPC that the impact is indeed less than 0.01% for both 2005 and 2006. Further, the Board has calculated the potential error which this minor site error may have on EPC’s Phase II Cost of Service allocations, and has determined again the impact to be negligible. The Board does not consider

12 Decision 2004-082 – ENMAX Power Corporation, 2004 Distribution Tariff, Part C: Final Tariff, dated September 28, 2004




that an error of this magnitude is a requisite for EPC to update its commercial site forecast. The Board therefore approves EPC’s commercial energy consumption and site forecast as set out in the Application. The Board notes that EPC indicated improvements13 in customer, billing demand and energy forecasts within the Commercial rate classes may be possible by:

1. undertaking a more detailed analysis of the existing commercial rate class data which could include a comprehensive analysis of individual large customers;

2. creating a weather correction model for billing demand to support the forecast; 3. creating a more robust billing determinants database designed to facilitate data

analysis and scenario testing; 4. developing alternate forecast methodologies; and 5. acquiring more robust forecast software.

The Board is of the view that these options should be examined. Therefore, the Board directs EPC to examine the above possible improvements for Commercial load forecasting and implement those that provide benefits that outweigh costs at the time of the next GTA. The Board expects EPC to carry out its commitment to continue to update its site count history and forecasting methodology in future proceedings. 3.3.4 Streetlighting Forecast EPC forecast Streetlighting (D500) energy econometrically as a function of the Calgary population for the period 1990 to 2003, using the following equation: Streetlighting energy = a + b*Calgary population The forecast is then adjusted to reflect the annual energy savings from the City of Calgary’s 4-year streetlight conversion initiative which commenced in 2002 of retrofitting residential streetlights from a mix of 250, 200 and 150-Watt high-pressure sodium fixtures to 150 and 100-Watt high-pressure sodium flat lens fixtures. The total energy savings is estimated to be 14 GWh or approximately 15% of the 2001 total D500 energy. EPC forecasts these energy savings more than offset normal growth over the next year, and accordingly, EPC’s Streetlighting energy is forecast to decline from 89 GWh in 2004 to 83 GWh in 2005, then rise to 85 GWh in 2006. The CG did not comment on EPC’s streetlight forecast. The Board considers the EPC Streetlighting approach to be technically sound, and therefore approves it as set out in the Application. 3.3.5 Obtaining Monthly Amounts from an Annual Forecast EPC noted that monthly energy by DT rate class is forecast by applying the 2002/2003 average shares of monthly energy to the total annual energy for each rate class, using weather-normalized

13 Exhibit 162, BR.EPC-2



data in order to eliminate the impact of weather on normal consumption patterns for each rate class. EPC forecasts, for each DT rate class, December sites by applying the 2002/2003 average weather corrected kWh per site for December to the December kWh forecast. Monthly site counts for January to November are then interpolated by applying equal amounts of site count growth between December of one year (i.e., 2004) to December of the next year (i.e., 2005). The CG did not comment on this aspect of EEC’s forecasting process. The Board considers the process used to derive monthly energy from annual energy to be technically sound and approves the monthly energy forecast as set out in the Application. 3.3.6 Forecast Accuracy EPC stated its belief that its total energy forecast for 2005 and 2006 is accurate within +/- 2% of actual. EPC further stated that EPC’s total load forecasts over the period from 1993 to 2003 have averaged within 0.3% of the year ahead of actual. The CG stated concerns that not all of EPC’s 2004 billing determinants for all rate classes were within +/2% of forecast.14

The Board tested the accuracy of EPC’s billing determinants by way of Information Request.15 The response for this request showed that for EPC’s residential and commercial customers, all of EPC’s 2004 forecast billing determinants were within +/-2%. The Board commends EPC for achieving this level of accuracy in its 2004 forecast. 3.3.7 Potential Unexpected Factors CG stated in argument that its concerns around Potential Unexpected Factors were addressed in section 2.3.6 (Forecast Accuracy) of its Argument. The Board has ruled on this section previously and will not provide any further comment. 3.4 Loss Factors Parties did not supply comment on this section. The Board approves the loss factors as set out in the Application. 3.5 Revenue Forecast Results

The Board further examined EPC concerning the revenue it recovered in 2004 vs forecast. The Board notes that EPC confirmed an under recovery of $1.06 million vs forecast,16 for an overall error in its revenue forecast of -0.6%. The Board again commends EPC for achieving this level of accuracy and considers that it lends considerable credibility to the revenue forecasting methods of EPC.

14 CG Argument, p. 9 15 Exhibit 162, BR.EPC-2

16 Transcript, Volume 3, p. 494



The Board approves in full EPC’s Load and Revenue Forecast as set out in the Application. 4 OPERATING EXPENSES

4.1 Overview For 2005 and 2006, EPC has requested approval of operating, maintenance and administration expenses (OM&A) of $45.1 million and $46.6 million respectively. The Board notes that the amount of OM&A expenses approved for 2004 in Decision 2004-066 was $45.2 million, whereas the actual amount of 2004 OM&A expenses was $45.4 million. 4.2 Staffing Levels and Vacant Position Allowance In its argument, EPC indicated that staffing levels are expected to increase by 15.6 full time equivalents (FTEs) between the 2004 estimate and the 2005 forecast with a further increase of 9.3 FTEs in 2006. EPC included a vacant position allowance for 2005 of approximately $1.5 million (3.06%). EPC also included a vacant position allowance for 2006 of approximately $1.7 million (3.23%). EPC noted that, consistent with its past practice, actual vacancy rates were used to estimate the vacant position allowance in dollars for the forecast years. EPC also stated that the vacant position allowance is calculated as a percentage of the total of salaries, wages, fringe benefits and incentive compensation. In its argument, the CG submitted that there is insufficient evidence to explain how the higher vacancy rates forecast for 2005 and 2006 result in vacancy allowances of $1.5 million and $1.7 million; whereas the 2004 forecast of 2.7% results in a vacancy allowance of $1.6 million. In the CG’s view, the forecasts include negative vacancy rates and allowances for events not likely to occur in 2005 and 2006. The CG submitted that the best forecast to use for 2005 and 2006 is one based on the updated 2004 actuals with the removal of negative vacancy amounts and an adjustment to the Distribution function vacancies to recognize historical realities. The CG proposed that the negative vacancy rates should be assumed to be zero. The CG also submitted that the vacancy amount for the Distribution function should be 16 instead of the 10.2 shown for the 2004 actuals. In its reply argument, EPC stated that the CG was ignoring the actual 2004 vacancies for Distribution and the negative vacancy rates for wholesale services, executive & administration, human resources and legal. EPC submitted that there is no evidence to suggest that the actuals that the CG proposes to remove are in any way inaccurate. The Board notes that a considerable amount of time was spent by the CG during the oral portion of the proceeding dealing with this issue of staffing levels and the vacant position allowance. The Board notes that there was uncertainty among the EPC witnesses as to what was represented by the FTE figures presented in various schedules and as to why the FTE amounts on a monthly basis were changing.17 The Board considers that the whole area of FTEs and vacancies could have been presented in a more transparent way by EPC. An example of this problem is Section 4.2.1 of the Application (Exhibit 003), wherein EPC stated that it had approximately 20 vacant FTEs in the Distribution function in 2004 (confirmed

17 Transcript Volume 1, p. 56, line 13 to Transcript Volume 1, p. 145, line 10




by EPC’s witness at Line 23 of Page 103 of the Transcript), but the actual vacancy amount shown for the Distribution function for 2004 on Exhibit 268 (Undertaking respecting Vacancy rates before and after Allocations)18 is 10.2. Like the CG, the Board also found it confusing that even though the forecast vacancy rates for 2005 and 2006 were higher than the forecast 2004 rate, the forecast vacant position allowance amounts for 2005 and 2006 were lower than the 2004 amount. After reviewing the evidence on this issue, the Board discovered that the 2005 and 2006 forecast vacant position allowance amounts were calculated by EPC simply by multiplying the forecast vacancy rates of 3.06% (2005) and 3.23% (2006) by the corresponding forecasted salaries and wages as shown on Schedule 4.2. The Board considers this to be a very simplistic method for this calculation. This calculation ignores the fact that the dollar impact of a vacancy in one area may be different than the dollar impact of a vacancy in another area. For the Distribution function, the Board also notes that while the CG considered that 16 vacancies was appropriate for the calculation of the 2004 vacant position allowance, the CG recommended that EPC be granted funding for backfilling about ¼ of 17 positions in 2005 and about ¼ of 17 positions in 2006. The Board considers that the information presented in Exhibit 268 is a logical place to start with respect to calculating a vacant position allowance for 2005 and 2006. The information in this Exhibit is the actual company experience for 2004. The Board, for the purposes of this Decision and as outlined in Section 4.4.1 below, will accept the proposal of the CG with regard to the backfilling of the positions in the Distribution function. The Board also agrees with the CG that EPC would not normally prepare its forecast on the assumption of having negative vacancies and as such the Board will accept the CG’s recommendation of having forecast vacancy rates of zero for these functions. As a result of these findings the Board has determined the vacancy rates and vacant position allowance amounts for 2005 and 2006 for each function. The attached Appendix 4 contains the Board’s calculation of the vacant position allowance amounts for 2005 and 2006 which result in an operating expense reduction of $0.813 million in 2005 and $0.346 million in 2006. The composite vacancy rate determined by the Board is 4.6% for 2005 and 3.9% for 2006. The Board directs EPC, in its refiling, to include the amounts shown in Appendix 4 as its allowance for vacant positions. 4.3 Other Staffing Level Matters The CG also put forward some recommendations with regard to the forecasting of FTEs. The CG submitted that the proper assessment of utilities’ FTE and vacancy forecasts requires utilities to provide such information on a consistent basis. It appeared to the CG that EPC has this information on a historical basis, by function, and it should use such information to form an FTE vacancy allowance and vacancy rate forecast for future GTAs. The CG also recommended that the Board direct EPC to provide and utilize a table similar to the one provided in TM.EPC-9. In the CG’s opinion, this table would be useful in assisting the Board and all parties in understanding how EPC plans on filling its complement of positions as well as how prior FTEs were hired. The CG submitted that this table should provide data by month, include vacancies and allow a tracking of FTEs by month for the test period and prior years. In its reply argument, EPC submitted that it is not possible to accurately forecast a vacancy for a particular department or union class, because it is impossible to predict in which month a

18 Response to undertaking given by Mr. Kadonaga to Mr. Chairman at Transcript Volume 1, p. 87,line 16



position will become vacant or filled. EPC submitted that a monthly breakdown of a forecast would not add value, since it is not possible to accurately forecast at that level. In the opinion of EPC, a more meaningful presentation of average FTEs is that which is shown in Schedule 4.4. Finally, EPC submitted that it is appropriate to continue to calculate vacancy rates using actual results, rather than on forecast data for future test years. The Board reiterates the point it made above regarding the lack of transparency in EPC’s presentation with respect to FTEs. The Board expects EPC to address this issue in its future applications. The Board is of the view that the information presented in TM.EPC-9 is very detailed and is an excellent tool for regulatory purpose. With respect to EPC’s concerns regarding the difficulty of accurately forecasting FTEs on a monthly basis, the Board considers that this should not hinder EPC from making plausible monthly assumptions with respect to this issue. While the Board is of the view that the table in TM.EPC-9 could be an excellent presentation tool for future applications, it considers that the onus should be left on the Applicant to decide how to clearly present its FTE information. The Board considers that at a minimum, the following FTE information should be included as part of EPC’s future applications:

• a definition of what FTE represents and how it was calculated; • the number of FTEs included in EPC’s Distribution revenue requirement, by functional

area and by employee class; • the total number of FTEs allocated to EPC Distribution from other companies that are

included in the ENMAX group of companies, the allocation percentage used and the details of how the allocation percentage was calculated;

• the average salary amounts for each employee class by functional area (which, when calculated by the FTEs, will agree to the salary and wages amounts shown in the operating expenses schedules);

• the assumptions made by EPC with respect to the start date of new positions; • the actual FTE figures (on a most recent annual basis) by functional area and by

employee class; • the actual FTE figures (on a most recent annual basis) by functional area compared to the

approved amounts (the approved amounts for this Application are the 548.8 and the 558.1 shown in Exhibit 244) and the resulting actual vacancy calculated;

• the actual number of FTEs allocated to EPC Distribution from other companies that are included in the ENMAX group of companies, the actual allocation percentage used and details of how the allocation percentage was calculated.

The Board directs EPC, in its next GTA, to include a forecast vacancy rate for each of the functions shown on Exhibit 268 and the Board further expects that EPC will provide reasons for the assumptions behind the forecast vacancy rates. The Board acknowledges that the use of historical information is one method of arriving at the forecast vacancy rates for the test years. 4.4 Operating, Maintenance and Administration (OM&A) by Function EPC’s OM&A expenses fall into the following categories:

• Distribution • Network



• Wholesale Services • General • Shared Services

Specific recommendations for each category were provided by the parties and the Board will address these in the specific sections below. 4.4.1 Distribution The EPC Distribution business unit is responsible for the safe and reliable operation of the power distribution infrastructure and managing growth within the franchise area, excluding the downtown network. The forecast OM&A expenses for this area are $19.8 million for 2005 and $20.3 million for 2006. In its argument, the CG stated that it appears the primary reason for increase in salaries in 2005 over 2004 is the assumption that vacancies are 100% backfilled in 2005. The CG submitted that it is unrealistic to assume that there will be 100% backfill of all 17 vacancies in 2005 given the experience in 2004. The CG recommended that the net distribution labour increase for 2005 not exceed a 4% increase for salaries and wages and about one quarter of the increase requested for backfilling 17 positions. For 2006, the CG recommended that the net distribution labour increase should not exceed the forecast salaries and wages escalation rate of 4% plus one quarter of the increase for backfilling 17 positions. The CG stated that the impact of these recommendations would be OM&A reductions of at least $1.125 million in 2005 and $0.6 million in 2006. In its reply argument, EPC stated that the CG fails to take into account the vacant position allowance budgeted under the General function. EPC stated that $0.9 million of this vacant position allowance should be considered as part of the Distribution function. After this $0.9 million is removed from the 2005 Distribution costs of $19.8 million, the difference between the resulting figure of $18.9 million and the $18.5 million shown on Schedule 4.1 is $0.4 million, or 2.2%, which is consistent with inflation. EPC also submitted that labour costs such as contracting and consulting have to be taken into account when considering total labour costs. In Section 4.2.1 of the Application, EPC stated that it anticipated adding two trades positions in 2005 and no staff increase for 2006. Consequently, the Board agrees with the CG that the primary reason for the increase in FTEs between 2004 and 2005 would be the filling of vacancies. The Board also agrees with EPC that for a proper comparison between the 2004 salary expense and the 2005 forecast amount, the amount of the vacant position allowance attributable to the Distribution function has to be taken into account. The Board notes that as a result of its determinations in Section 4.2 above, the vacant position allowances for the Distribution function are now $1.1 million for 2005 and $0.8 million for 2006 (see Appendix 4 for details). The Board notes that by EPC’s own evidence,19 the number of vacancies filled in 2004 for the Distribution function was 4. The Board considers that the recommendation of the CG with regard to the staggered backfilling will be a more probable outcome than EPC’s suggestion that it will fill all 17 vacancies in 2005.

19 Exhibit 265



The Board has prepared a table (see Appendix 5) in which it compares the salaries and wages using the recommendations of the CG to the EPC applied for amounts. As can be seen in Appendix 5, the starting point is the 2004 actuals. To this, the Board has incorporated the 4% escalation rate for 2005 and 2006 recommended by the CG and the backfilling of approximately ¼ of 17 positions in 2005 and another ¼ of 17 positions in 2006 as recommended by the CG. In addition, the Board has incorporated the updated vacant position allowance in 2005 of $1.1 million. The Board made this adjustment to account for the fact that the 2004 actuals have no vacant position allowance included in them. As can be seen in Appendix 5, the resulting differences would be a reduction of $0.3 million in 2005 and an increase of $0.3 million in 2006. The Board considers that the reduction of $0.3 million in 2005 is offset by the increase of $0.3 million in 2006. Consequently, the Board has determined that no reduction is required to the Distribution function salaries and wages. The Board therefore approves the salaries and wages for the Distribution function of $24.5 million in 2005 and $25.2 million in 2006 as requested by EPC. 4.4.2 Network The Network group of EPC is responsible for the safe and reliable operation of the network infrastructure and for managing growth in the downtown area. The total forecast OM&A costs in this area are $3.3 million for 2005 and $3.4 million for 2006. In its argument, the CG submitted that the proper frame of reference to assess the 2005 forecast is the 2003-2004 actual results. Accordingly, the CG submitted that the 2005 forecast should be $2.9 million (which is the 2004 actual amount of $2.8 million plus inflation of 2.2%) while the 2006 forecast should be $3.0 million (which is the 2005 recommendation of $2.9 million plus inflation of 2.2%). The CG also submitted that EPC be directed to undertake a study of splitting its OM&A costs for the network system between primary and secondary systems and file its network OM&A costs on this basis. In its reply argument, EPC stated that the CG failed to take into account the vacant position allowance budgeted under the General function. EPC stated that $0.4 million of this vacant position allowance should be considered as part of the Network function. In EPC’s submission, after this $0.4 million is removed from the 2005 Network costs of $3.3 million, the difference is $0.1 million, or 3.0%, (based on Schedule 4.1). In EPC’s submission, a 3.0% increase is consistent with inflation. The Board notes that the 2004 actual OM&A expenditures for the Network function amounted to $2.8 million. The Board also notes that the 2005 and 2006 forecast amounts of $3.3 million and $3.4 million respectively, as presented on Schedule 4.1 do not include the impact of the vacant position allowance attributable to the Network function. Once the updated vacant position allowance for this function is taken into account, the comparable forecast amounts are $2.7 million for 2005 and $2.8 million for 2006. The Board considers that this is reasonable compared to the actual expenditures for 2004 and therefore no further reductions are necessary. With respect to the CG submission regarding the study of network OM&A costs, the Board notes that EPC did not reply to this issue. The Board agrees with the CG that since different classes of customers contribute to the costs of the primary and secondary Network system, it would be desirable for EPC to split its network OM&A costs between the two systems. Consequently, the Board directs EPC, as part of its next GTA, to undertake such a study and file its network OM&A costs between primary and secondary systems.



4.4.3 Wholesale Services The forecast expenses for the Wholesale Services function are $9.7 million for 2005 and $10.2 million for 2006. EPC attributed the majority of the increases in this area to salary escalation, inflation, and additional staff. EPC indicated that the increase of $370,000 from the 2004 actuals to the 2005 forecast in the revenue metering area of Wholesale Services is partly due to the addition of two new employees, amounting to $200,000, and the balance is due to fluctuations in the amount treated as capital versus Operating & Maintenance (O&M) due to variation in the level of capital expense from year to year. The CG was not convinced that EPC is not able to plan the level of O&M versus capital activity having regard to vintage of meters and previous maintenance records. The CG recommended that the Board direct EPC to develop such a plan for the purposes of forecasting revenue metering expense as part of its next GTA. Moreover, the increase in revenue metering expense due to the change in the mix of capital versus O&M activities should be disallowed as part of this Application as EPC failed to adequately explain why this activity cannot be leveled and normalized for the test year forecasts. In its reply, EPC stated that its evidence was not that it had no “plan”, but rather that it is difficult to accurately forecast the mix of maintenance versus capital expenditures related to meters, because one cannot predict what meters are going to be recertified by Measurement Canada. EPC stated that the considerations that make forecasting revenue metering expense difficult are beyond EPC’s control, and unanticipated fluctuations are to be expected. EPC submitted that the forecasts for 2005 and 2006 are effectively normalized, as Revenue Metering does forecast a certain number of meter replacements. EPC also submitted that the $0.170 million estimate of the CG is not attributable to a change in the mix of capital versus O&M activities, because there are also salary increases for existing staff to be taken into account. The Board agrees with EPC that it is difficult to forecast how many meters each year will have to be recertified. However, the Board notes that EPC has made an assumption with regard to this area in preparing its 2005 and 2006 forecasts. In its analysis of this area, the Board started with the 2004 actuals of $1.63 million20 and added inflation of 4% which resulted in a 2005 base number of $1.70 million. Next, the Board added to that amount the 2005 average salary of $72,010 for this area21 for two employees which results in approximately $0.14 million. The total of these two amounts is $1.84 million which is $0.16 million less than the 2005 forecast amount of $2.00 million. Based on the testimony of EPC’s witness,22 the Board considers that the $0.16 million is the amount that EPC is proposing is due to the mix of capital versus O&M. EPC has not indicated any new positions are being filled in this Revenue Metering area for 2006. The forecast increase of $0.06 million in 2006 is approximately 3% greater than the 2005 amount, which the Board finds is in line with the general inflation rates. While EPC, in its evidence,23 stated that unanticipated fluctuations are to be expected in the number of meters to be recertified, EPC forecast the 2006 expense level to be the same as the

20 Exhibit 191 21 Exhibit 206 22 Transcript Volume 2, p. 261, lines 10 to 21

23 EPC Reply Argument – Section 1.1.2 Wholesale Services



2005 level. The Board considers this to mean that EPC considers that the number of meters to be recertified in 2006 will be the same as the number in 2005. Given that the Board has found that it is difficult to forecast how many meters each year will have to be recertified, the Board considers that this number has an even chance of being higher or lower than the 2004 actual amount. Consequently, the Board will approve the level of expenditures at $1.84 million as calculated by the Board above. The Board therefore directs EPC, in its refiling, to reduce the forecasted operating expenses for the Wholesale Services by $160,000 in 2005 and $160,000 in 2006. The Board rejects the recommendation of the CG that the Board direct EPC to develop a formal plan for the purposes of forecasting revenue metering expense for the next GTA. However, the Board expects that EPC will provide, in its next GTA, any reasons and documentation necessary to support its assumptions regarding the number of meters to be recertified during the test periods. 4.4.4 General The forecast General OM&A expenses are $6.2 million for 2005 and $2.4 million for 2006. The main reason for the decrease in forecast costs between 2005 and 2006 relates to the transitional issue of Transmission Costs. With EPC’s Transmission Tariff coming under EUB jurisdiction effective January 1, 2006, EPC assumed that such transitional issues will no longer exist after January 1, 2006, and has therefore moved approximately $4.0 million from Distribution General to the Transmission Tariff for 2006. In its argument, the CG submitted that EPC has not complied with the Board’s direction to file an O&M benchmarking study. In the opinion of the CG, the absence of any supporting information to determine whether the conversion of the 6% overhead rate used by EPCOR Distribution Inc. (EPCOR) to the 19% used by EPC was carried out correctly renders the benchmarking study useless. The CG submitted that EPC should be directed to complete such a study for the purposes of the next GTA. The CG also recommended that in light of the fact that EPC’s overhead capitalization rate is significantly higher than the rate used by other utilities, the Board direct EPC to review its cost structure and its overhead capitalization policies in relation to other utilities. In its reply argument, EPC disagreed with the assertions of the CG that the benchmarking report was useless and that EPC had failed to comply with the Board direction regarding the benchmarking study. EPC stated that due to circumstances beyond its control, the author of the study was not available to appear as a witness but instead the study was admitted on the basis of an affidavit. EPC felt that the written questions the CG asked on the study should have been directed to EPCOR, since the questions related to the capitalization rate of EPCOR. In response to the issue of the overhead capitalization rate, EPC noted that merely comparing the rate used by EPC to the rate used by other utilities does not result in an appropriate “apples to apples” comparison. EPC stated that if the goal is to ensure that all utilities use the same percentage overhead capitalization rate (and EPC submitted that this should not be the goal), it would be necessary to ensure that the underlying methodologies are the same. EPC also submitted that there is no relationship between the level of overhead charged to capital and the level of O&M. EPC stated that its indirect allocation approach ensures that all of the appropriate costs associated with placing a utility project into service are captured and also ensures complete visibility of EPC’s total operating and maintenance expenses.



In its reply argument, the CG submitted that for those expenditures, such as rent, engineering and supervision, common to capital and O&M activities, the portion applicable to capital projects should be clearly identified based on time required and only those applicable amounts should be included in capitalized O&M. The Board acknowledges the fact that EPC did indeed present a benchmarking study for O&M expenses. To that extent, the Board agrees with EPC that it did comply with the Board’s direction in this area. The Board also agrees with EPC that the circumstance of the author of the study not being able to appear as a witness was beyond the control of EPC. However, the Board reminds EPC that it bears the responsibility for all of the evidence it provides, regardless of whether or not an outside party actually prepares the evidence. The Board expects EPC to remember this responsibility when it is engaging outside parties. EPC could have taken steps to periodically review the work of Cap Gemini with the intention of fully understanding the information presented. The Board agrees with the CG that a key element in interpreting the benchmarking study would have been an understanding of how the Cap Gemini consultant dealt with the fact that EPCOR and EPC have different overhead capitalization rates. The Board considers that this understanding was not obtained from the study performed by Cap Gemini partially due to the fact that the Cap Gemini consultant was not available for cross examination. As a result, the Board directs EPC to collaborate with EPCOR and, as part of EPC’s next GTA, complete another O&M benchmarking study that compares the EPC and EPCOR distribution systems. The Board also directs that this study include details on how the effect of the different overhead capitalization rates was taken into account including a comparison of the administrative accounts considered to be eligible for overhead capitalization. In regard to the matter of the capitalization rate used by EPC, the Board agrees that on the surface, the rate used by EPC is higher than that used by other utilities. However, the Board also notes EPC’s statement that the underlying methodologies have to be compared. The Board considers that it would be very useful for all parties to understand just what items each utility includes in its capitalized overhead. This would enable meaningful comparisons to be made. However, at this time the Board concludes that this proceeding is not the best forum in which to evaluate that matter. In light of the ongoing process involving TFOs initiated by the Board in Decision 2003-06124 and Decision 2003-071,25 the Board will provide further direction to all stakeholders in due course. The Board comments further on the matter of overhead rates in Section 6.1.1. 4.5 Operating Expenses – Shared Services ENMAX employs a shared services model to provide corporate services to the ENMAX group of companies, including EPC and EEC. These shared services include the following:

24 Decision 2003-061 – AltaLink Management Ltd. and TransAlta Utilities Corporation Transmission Tariffs for

May 1, 2002 to April 30, 2004; TransAlta Utilities Corporation Transmission Tariffs for January 1, 2002 - April 30, 2002, dated August 3, 2003

25 Decision 2003-071 – ATCO Electric Ltd. 2003-2004 General Tariff Application (Application 1275494) and Rate Case Deferrals Application (Application 1275539) 2001 Deferral Application (Application 1275540), dated October 2, 2003





• Executive and Administrative (E&A); • Human Resources, Legal and Facilities (HLF); • Information Services (IS); • Finance and Supply Chain Management (SCM); and • Regulatory.26

EPC submitted that the manner in which ENMAX shared services costs are allocated to EPC is based on well known methods used in the utility industry, and was developed giving consideration to prior decisions of regulatory bodies, including the EUB.27 The shared services allocation model was produced in EPC’s 2004 DT proceeding, and was produced again as part of this Application.28 EPC submitted that the allocation model is sound, transparent and well supported. EPC has forecasted shared services costs of $20.9 million for 2005 and $22.6 million for 2006. Table 2. ENMAX Corporation Shared Services Allocated to EPC

Component 2003 Actual

2004 Decision

2004 Estimate

2005 Application

2006 Application

Executive & Administrative 2.6 2.1 1.9 2.8 2.9

Human Resources, Legal & Facilities 3.8 4.1 5.1 5.2 5.4

Information Services 5.5 6.4 5.5 6.0 7.1

Finance & Supply Chain Management 6.5 5.7 5.6 5.3 5.5

Regulatory 2.9 2.0 2.4 1.6 1.7

Total 21.3 20.3 20.5 20.9 22.6 4.5.1 Shared Services Study BearingPoint LLP (Bearing Point) was retained pursuant to a Board direction in Decision 2004-066 to complete an independent study demonstrating that EPC could not obtain any of the services provided by ENMAX at a lower cost, either by developing internal resources or by directly procuring the services from the market.29 BearingPoint’s 2005/2006 Distribution Tariff Shared Services Cost Study, dated April 4, 2005 (BearingPoint Study) was filed with the EUB.30 BearingPoint concluded that EPC could not effectively or efficiently obtain the shared services provided by ENMAX at a lower cost, either by developing internal resources or by directly procuring such services from the market for 2005.31 BearingPoint described Internal and External Cost Provision in Exhibit 133, pages 8 and 9. EPC noted that the external provision costs estimated by BearingPoint do not include the cost of management of the external contract, and that the internal and external provision costs estimated 26 Further details regarding these shared services functions is set out in Section 4.2.5.4 of the Application. 27 Exhibit 003, p. 37 28 Exhibit 326-4 29 Decision 2004-066, p. 46 30 Exhibit 133 31 Exhibit 133, p. 1; RRT Exhibit 85, p. 1





by BearingPoint show an end state after significant planning and operational change that could not be immediately achieved, and could only be achieved after expending significant costs.32 Furthermore, the ranges shown in the BearingPoint Study are ranges of best practices, rather than being a high and low of normal practices. Having regard to the challenges of making an “apples to apples” comparison outlined by BearingPoint in the BearingPoint Study,33 EPC submitted that it would not be appropriate to “cherry-pick” data from that study. The CG had three concerns with regards to the BearingPoint Study that result in CG’s submission that the study is of limited use:

1. Limitations to the scope of the study undertaken. 2. BearingPoint did not examine the financial statements of EPC or ENMAX

Corporation.34 3. BearingPoint does not take into account the impact on costs arising from the use

of differing capitalization rates.35 The CG noted BearingPoint did not undertake any review of year-over-year changes in shared services costs to understand or determine the sensitivity of the 2005 forecasted ENMAX costs to the Internal and External Cost Provision estimates.36 The CG submitted the expectation is the costs of the shared costs would generally be between the low and high end of Internal Cost Provision. The CG noted that in the area of Finance and Supply Chain Management, EPC’s Shared Services Costs of $5.3 million exceed the high end of the external cost provision option of $5.10 million and thus are out of the range of reasonableness. Though EPC and BearingPoint placed qualifiers on the study,37 the CG submitted that based upon the research and expert opinion brought forward by BearingPoint, the results indicate EPC’s costs in the Finance and Supply Chain Management cost function are out of the range of reasonableness when measured against the external cost provision. Based on the foregoing, the CG submitted the validity and usefulness of the study does not lend credibility to the reasonableness of the costs filed by ENMAX and allocated to EPC. Notwithstanding the limited usefulness of the BearingPoint Study, the CG submitted the evidence tends to suggest the forecast EPC shared services costs appear to be overstated such that the costs of shared services are, in the aggregate for all of the five shared service areas, higher than the total of the low-end of the range of the External Cost Provision option for EPC.38 EPC replied that the CG’s criticisms of the BearingPoint Study must be evaluated in light of what the study was intended to do, and not what the CG would like it to have done. Furthermore, EPC stated that it is entirely appropriate for BearingPoint to use forecast shared services costs in completing its assessment. Those are the costs that EPC has applied for. BearingPoint was not retained to investigate ENMAX’s forecast accuracy, or the appropriateness of the allocation 32 Transcript Volume 4, p. 712 lines 9-17 33 Exhibit 133, pp. 6-7 34 Exhibit 163, CG.EPC-31 (b) 35 Exhibit 162, BR.EPC-17 (c) 36 Exhibit 163, CG.EPC-31 (d) 37 Exhibit 162, BR-EPC-17

38 Exhibit 271



factors, and such an investigation was not required in order to comply with the Board’s directive. In addition, some shared services categories, such as Human Resources and Legal and Facilities, might have embedded costs that are not included in the comparators studies by BearingPoint. These embedded costs include, for example, costs related to safety, reliability and communication.39

The Board notes the directive set out in Decision 2004-066 on page 46:

The Board directs EPC, in its next GTA Application, to file an independent study demonstrating that EPC could not obtain any of the services provided by ENMAX Corporation at a lower cost, by developing internal resources or by directly procuring such services from the market.

This directive does not contemplate the additional requirements that the CG would have preferred to have been included. Though the Board agrees with the CG that there are limitations with regards to the study, the Board also agrees with EPC that the study is one of best practices and not intended to be a benchmark study. The Board is satisfied that the study provides the Board with the information required to test the overall reasonableness of the shared services costs provided by ENMAX to EPC. However, the Board notes that examination of individual costs is still required in some cases as covered in the following sections. 4.5.2 Reasonableness of ENMAX Corporation Shared Services Costs During the hearing process, the CG submitted there was insufficient information on the record to properly assess the base level of 2004 costs and the changes in costs from the 2004 base year to 2005 and from 2005 to 2006. To assist in this review, the CG structured a matrix to assist in the assessment of these cost variances and a completed version was provided in Exhibit 326-28. The CG submitted that in order to expedite the review of shared services costs in an efficient and effective manner, EPC should provide a detailed explanation of all material variances over 10% in a detailed account-by-account budget of each of the five areas of shared services and at the same level of detail as contained in Exhibit 326-004. The Board is concerned about the lack of information originally filed with the Application and agrees that the requested information would be of assistance to the Board and interveners in EPC’s next application. Accordingly, the Board directs EPC to provide a detailed explanation of all material variances over 10% in its next GTA application. The Board directs that this explanation be provided at the level of detail shown on Schedule 4.2.5 for Executive and Administration, Schedule 4.2.6 for Human Resources, Schedule 4.2.7 for Information Services, Schedule 4.2.8 for Finance and Supply, and Schedule 4.2.9 for Regulatory. 4.5.3 Shared Services Allocations

i) CEO/CFO Certification The CEO/CFO certification project is an internal control project that will inventory, assess, and monitor internal financial controls in three key areas: revenue stream and controls; financial data;

39 Transcript Volume 4, p. 723, line 23 to p. 724, line 4




and information technology.40 EPC submitted that the benefits of this project are increased confidence in financial statements, improved efficiency of processing, and improved quality through implementation of a continuous internal control monitoring and improvement process.41

In part, this project will ensure that ENMAX’s corporate governance practices will satisfy the Canadian equivalent of the Sarbanes-Oxley standard. While strictly speaking, ENMAX is not subject to the Canadian equivalent of the Sarbanes-Oxley requirements, EPC submitted these requirements have become the de facto standard for good corporate governance,42 and the standard of corporate governance is a factor in setting credit ratings.43 Failure to follow these standards can have a number of consequences, including increased cost of debt, for example.44

ENMAX forecast $750,000 for CEO/CFO certification in 2005 of which $280,000 has been allocated to the DT.45 EPC requested that though the project has been delayed to 2006, the 2005 forecast allocation was reasonable at the time it was made, and should be approved. The CG noted ENMAX ceased to be a public issuer effective February 18, 2005.46 Since the provisions of the CEO/CFO certification pertain only to public companies, the CG submitted ENMAX is not required to engage in costs requiring such certification. As well, if ENMAX wants to get this certification for purposes of issuing debt, the CG submitted this must be for non-utility related debt. The CG recommended that none of the $750,000 forecast for 2005 allocated to DT be allowed for recovery. EPC submitted that there are some investments for which municipal financing is not available; the timing of municipal financing is limited; there is no guarantee that municipal financing will always be available;47 and it is reasonable to assume that the 0.25% administration charge assumes prudent management. These forecast costs also include costs related to general governance, diligence, and fiduciary responsibilities. EPC submitted that the ENMAX Board of Directors engages consultants or undertakes education as necessary to be appropriately diligent in pension governance, executive compensation, safety governance and other general governance issues, all of which benefit customers. The Board notes that this new information was provided in an undertaking and there was no breakdown of these costs among these various categories. The Board notes that EPC was cross-examined extensively on the purpose of the CEO/CFO certification costs and none of the responses mentioned these other costs. The Board has no way of determining the portion of the forecast CEO/CFO costs related to general governance, diligence, and fiduciary responsibilities and will place no weight on this late evidence.

40 Exhibit 163, response to CG.EPC-32(k). See also exhibits 291-293. 41 Exhibit 163, response to CG.EPC-32(k) 42 Transcript Volume 4, p. 785, line 14 to p. 786 line 25 43 Transcript Volume 4, p. 816, lines 1 to 6 44 Transcript Volume 4, p. 788, lines 4 to16 45 Exhibit 163, response to CG.EPC-32(k) 46 Transcript Volume 4, p. 805

47 Transcript Volume 4, p. 808, line 17 to p. 809 line 6



The CG noted that EPC’s utility debt is secured through a municipal government agency (i.e. Alberta Capital Finance Authority (ACFA)) and proceeds flow through the City of Calgary to ENMAX and then to EPC based on contractual arrangements between ENMAX and EPC.48 The Board notes that since ENMAX is not a public issuer it is not subject to the Canadian equivalent of the Sarbanes-Oxley requirements. Further, EPC stated it has no evidence to suggest there is a real or probable risk of it not being able to continue to get financing through ACFA.49 The Board agrees with the CG’s submission that any purported advantages of the CEO/CFO certification would primarily be to the benefit of ENMAX’s non-regulated operations. Accordingly, the Board directs EPC to remove the 2005 forecast of $280,000 for CEO/CFO Certification from the DT revenue requirement. ii) Finance and Supply Chain Management – Other Costs EPC’s forecast of “other expenses” in the Finance and Supply Chain Management cost function is $0.8 million in both 2005 and 2006. The CG noted that although the Board, in Decision 2004-066, approved an amount of $0.6 million for 2003 and 2004, actuals for 2003 and 2004 were only $0.2 million, $0.4 million lower than approved.50 The CG further noted that EPC explained that the $0.4 million reduction in 2004 was “due to lower financing costs than anticipated when the application was prepared.”51 The CG submitted that since EPC failed to provide any evidence why it should be increased from actual levels, the “other” category of Finance and Supply Chain Management should be reduced by $0.4 million in each of 2005 and 2006. The Board notes the actual levels referred to by CG in the foregoing are incorrect. The Board approved $0.8 million in Decision 2004-066,52 not $0.6 million as referenced by CG.53 The Board also notes that the CG’s submission was incorrect in that EPC explained a $0.6 million reduction, not a $0.4 million reduction. EPC argued that the CG failed to account for the limitations of municipal financing discussed in the CEO/CFO Certification Costs. However, EPC admitted that it provided no evidence to suggest that there is a real or probable risk of not being able to continue to get financing via ACFA.54 Since EPC has the ability to obtain better financing through ACFA,55 the Board concludes that additional financing costs over and above ACFA costs are not required for EPC. Accordingly, the Board directs EPC to reduce the “other category” of Finance and Supply Chain Management by $0.6 million for 2005 and 2006 in its refiling. iii) Financing Costs EPC is requesting $700,000 for financing costs in 2005. EPC explained these costs were “categorized as interest in the last application, but they are actually the costs to set up and

48 Exhibit 163, CG.EPC-74 49 Transcript Volume 4, p. 809, line 7 to p. 809, line11 50 Exhibit 163, CG.EPC-50 (a) Attachment, p. 10 51 Exhibit 267 52 Decision 2004-066, p. 46 53 Exhibit 211, CG-EPC-50(a) 54 Transcript Volume 4, p. 809, line 7 to p. 80911 55 Exhibit 163, CG.EPC-74






maintain debt vehicles to help finance large capital expenditures.” 56 EPC goes on to state these costs are more like “standby charges” and are needed “to finance the expansion of ENMAX.”57 The CG notes that ENMAX’s debt requirements are met by financing from the Alberta government. The CG submitted the evidence demonstrates that these financing costs are for purposes of financing the expansion of ENMAX, and for reasons other than for utility purposes.58 The CG argued that the entire $0.7 million in 2005 should be disallowed as non-utility related. EPC noted that the $700,000 referred to by the CG represents total financing costs, and not the financing costs allocated to the DT. EPC also noted that disallowance of the “Financing Cost” referred to here and the disallowance of the “Finance and Supply Chain Management –Other Costs” referred to above cannot both be made since the costs are the same. The Board agrees that if disallowances to both “Financing Cost” and “Finance and Supply Chain Management – Other Costs” were to be made, the same costs would be removed twice. Accordingly, the Board does not approve the reduction in revenue requirement for Financing Costs suggested by the CG since the Board has already reduced the revenue requirement in the above section. iv) Governance Costs EPC and EEC are proposing to increase their governance costs in 2005 by $1.10 million. The CG submitted while the increase in these costs may be reasonable, there is no reason to allocate the entire cost to EPC and EEC. The CG submitted these governance costs relate to the ENMAX group of companies and undoubtedly include costs expended to look after the non-regulated entities, as well as the transmission function. Therefore, these costs should be split 50/50 as between the regulated and unregulated entitles. EPC replied that though the governance costs are currently allocated 50/50 between EPC and EEC, of the portion allocated to EPC, only 28.75% of the board of director costs ($0.086 million),59 and 30.94% of the compliance costs ($0.248 million),60 are allocated to the DT.61 The balance of the 50% allocated to EPC is allocated to other EPC businesses and subsidiaries, including unregulated businesses. The Board agrees with EPC that the costs have already been appropriately allocated to all regulated and unregulated businesses within the ENMAX group of companies. The Board approves the Governance costs as filed. v) Other Expenses EPC shows cost increases in the “other” category of Shared Services in the amount of $1.3 million in 2005 and $0.8 in 2006. Of the $1.3 million in 2005, $0.4 million is allocated to EPC and in 2006, of the $0.8 million, $0.3 million is allocated to EPC. These costs are all described as 56 Exhibit 163, CG-EPC 32 (c) 57 Transcript Volume 4, pp. 737 to 738 58 Transcript Volume 4, pp. 811 to 813 59 $0.3 million x 28.75%. See the response to CG.EPC-32 (exhibit 163). 60 ($0.3 million + $0.5 million) x 30.94%. See the response to CG.EPC-32 (exhibit 163).

61 Exhibit 260



“general cost increases”.62 The CG submitted the proposed costs under the “other” category are not supported by the evidence and should be disallowed in their entirety. The Board agrees with EPC’s submission that much of the costs in the “other” category are accounted for by adjusting the non-salary costs listed in Exhibit 326-028 by the general inflationary factor of 2.2%. Accordingly, the Board accepts EPC’s inclusion of these costs in the 2005-06 revenue requirement. 4.5.4 Shared Services 2 – South Service Centre Operating Costs The 2005 forecast for the operating costs for the South Service Centre (SSC) are $1.39 million which is a 10.8% increase over the 2004 actual. The 2006 forecast for the operating costs for the South Service Centre are $1.42 million which is a 2.23% increase over the 2005 forecast.63 The Attachment to CG.EPC-48(a) indicates the SSC has a total of 160,000 square feet.64 The amount allocated to EPC is 128,231 square feet, or 80% (128,000/160,000 = 80%).65 While the facilities have been allocated in this manner, it is not clear from the record if the operating costs related to the SSC are also allocated on a similar basis. Therefore, the CG submitted the Board should direct EPC to include information on the allocation of SSC operating costs to EPC as part of its refiling. The Board notes that the CG had the opportunity to question EPC on its operating costs for the SSC during the hearing process but did not. The Board considers it inappropriate to in effect extend the hearing process through the use of the refiling process. The CG noted the forecast increases for 2005 and 2006 are both in excess of 2%, notwithstanding EPC’s evidence historical experience suggests the average annual increase for the preceding two years was less than 2%. As well, the evidence is the most recent forecast indicates a substantial reduction in 2005 costs. Consequently, the CG submitted any increase in operating costs for this facility year over year should not exceed 2%. Applying the 2% escalation to the 2004 actual amount results in $1,278,000 for 2005 ($1,253,000 * 1.02) and $1,304,000 for 2006 ($1,278,000 *1.02) or a reduction of $110,000 in 2005 and $115,000 in 2006. The CG submitted EPC should be directed to include these revised amounts for SSC operating costs in its refiling. EPC submitted it would not be appropriate to base the 2005 and 2006 costs on the 2004 actuals. Actual costs vary from year to year as a result of factors such as the number of snowfalls, and concomitant changes in snow removal costs, and as a result of utility rates and billing cycles. Snow removal costs in 2004 were significantly lower than those in 2003, contributing to a decrease in costs from 2003 to 2004. 66 Since the operating costs are influenced by a number of factors and demonstrate significant year to year variability, EPC submitted it is not appropriate to simply take the 2004 actual cost and effectively increase it to account for only a single factor, namely inflation.

62 Exhibit 326-028 63 Exhibit 208, Exhibit 326-10, CG.EPC-48(a) 64 Exhibit 208 65 Exhibit 326-11 66 Exhibit 326-10



The Board notes that EPC has forecast increases in SSC Operating Costs in both 2005 and 2006 even though there was a decrease in costs from 2003 to 2004. The Board agrees with EEC that operating costs such as snowfall removal are difficult to forecast and a one year downtrend due to reduced snow removal costs does not necessarily equate to an overall reduction in operating costs. As such, the Board is satisfied that the SSC Operating Costs are reasonable, but does consider that forecasting for operating costs which are subject to weather related volatility should be based on periods of time longer than one year. The Board requests that EPC consider inclusion of such analysis in future applications. 4.6 Incentive Compensation EPC has forecast $4.1 million in short term incentives for 2005, and $4.4 million for 2006. EPC has also forecast $0.4 million in long term incentives for both 2005 and 2006. In argument, EPC requested the Board reconsider the position that it took in Decision 2004-066 in relation to incentive compensation. EPC stated that it must be able to attract and retain highly skilled employees in a competitive labour market and in order to do that, EPC’s total compensation must be in line with the market. EPC submitted that the purpose of an incentive program is to make a part of employees’ compensation dependent upon operational goals. EPC submitted that it is not possible to separate the benefit of the work performed by employees between customers and the company. In its argument, the CG submitted that EPC should be directed to provide, on an annual basis, the amount of short term incentives paid out in the same format as provided in Exhibit 326-27. Also, consistent with the Board’s ruling on this issue in EPC’s last GTA, any components of short term incentive for 2005 and 2006 related to earnings, return on equity or similar measures, should only be funded 50% by ratepayers. The CG suggested that the Board direct EPC to set up a short term incentive deferral account for the 2005 and 2006 test years and that since the targets or amounts for 2006 had not yet been reviewed or determined, EPC should not be allowed to recover any amount for 2006 short term incentive other than what the Board approves for 2005. With respect to the long term incentive amounts of $0.4 million in each of 2005 and 2006, the CG argued that these should be denied in their entirety. In the opinion of the CG, the payout of the long term incentives is totally discretionary and has no specific or measurable goals or objectives. The CG noted that if the Board decides that customers should pay for the long term incentives, it should be on a deferral account basis. The CG stated that EPC should be required to provide details substantiating the basis for the amount of long term incentive requested in its next GTA. EPC replied that the CG’s argument effectively suggests that the ENMAX Board of Directors would act imprudently and arbitrarily withhold long term incentive payments. EPC stated that there is no evidence to suggest this. In its argument, ATCO Electric Ltd. (AE) stated that incentive pay forms an important part of the total remuneration package for a utility and that in the case of EPC, the evidence suggests that this component of employee compensation is necessary to bring EPC to the market median. AE also stated that continued disallowance of part or all of incentive compensation based on financial measures could impact the overall health of the utility. AE submitted that if the Board is persuaded that the financial key performance indicators (KPIs) can be achieved without




sacrificing the quality of service to customers then the Board should allow recovery of all forecast incentive payments in the utility revenue requirement. The Board notes that the target for OM&A is $50.9 million67 while the revenue requirement for Operating Expenses is $45.2 million.68 The Board directs EPC, in its refiling, to explain why this KPI is higher than the requested revenue requirement and the effect this may have on the benefits normally available when targets are achieved. The Board has reviewed the material that was filed on this issue and in the Board’s view it has not been presented with any compelling new evidence that would convince the Board that the findings in Decision 2004-066 are no longer relevant. The Board considers that all amounts that relate to financial measures, with the exception of revenue from new sources, provide benefits to both EPC’s customers and the companies themselves. As a result customers should only pay for 50% of the incentive compensation amounts related to financial measures. The Board finds that the revenue from new sources applies to the non-regulated activities of ENMAX and as such would not benefit the customers of EPC DT. The Board therefore directs EPC, in its refiling, to reduce the amount of 2005 short term incentive compensation as follows: 50% of OM&A, 100% of Revenue from New Sources, 50% of Return on Equity, 50% of cash Flow from Operations, and 50% of Risk Adjusted Return on Portfolio. As a result, the 2005 short-term incentives approved by the Board amount to approximately $2.96 million. The Board will allow short-term incentives in the amount of $3.08 million for 2006 which provides for a 4% inflation factor over the 2005 Board approved amount. The Board further directs EPC, in its refiling, to structure the 2006 short term incentive such that it corresponds to the methodology approved for 2005 and does not exceed the approved $3.08 million in total for 2006. If the short-term incentives paid out are less than the Board approved amounts of $2.96 million for 2005 and $3.08 million for 2006, the Board directs EPC to provide a one-time credit to customers with the difference between the payout and the Board allowed amounts at the time of the next GTA. On the issue of long term incentives, the Board is not satisfied that EPC has clearly demonstrated that this payment is necessary to ensure that ENMAX’s compensation is in line with the market median. As mentioned in the Executive Compensation section (Section 4.9 of this Decision) while the Board acknowledges that an internal study was prepared, the Board notes that EPC deemed the results of this study to be confidential, and consequently it was not made available for examination. The Board notes that EPC believes it is not paying at the market median for its executives, but the market median amount for executives is not disclosed. The Board also notes that one of EPC’s witnesses indicated that the payment of the long term incentive is totally discretionary.69 The Board is unable to determine the extent to which, if any, a discretionary payment would help ENMAX move toward its goal of having compensation at the market median. 67 Exhibit 326-026 68 Exhibit 243, Schedule 4.1 Revised August 29, 2005 69 Transcript Volume 5, p. 1046, lines 14-15




EPC stated that the long-term incentive plan discretionary pool for executives is generated as a result of ENMAX exceeding targeted earnings levels.70 The Board concludes from this statement that if the Board awarded long-term incentive payments in the revenue requirement then the Board is assisting ENMAX in the achievement of exceeding targeted earning levels, which defeats the purpose of the incentive plan. Furthermore, the achievement of exceeding targeted earning levels should be funded by the shareholder not by customers. For the above reasons, the Board directs EPC, in its refiling, to remove the long term incentive amounts from its forecasted operating costs. 4.7 Operating Expenses Capitalized EPC stated that every capital project is allocated approximately 19% overhead, which results in lower OM&A. In EPC’s opinion, the 19% rate is required in order to recognize all appropriate costs associated with placing a utility project into service. EPC explained that the dollar value is budgeted and that the capitalization rate falls out of the dollar amount, not the other way around. EPC submitted that the rate is reviewed on a regular basis and that the triggers for a review include a change in accounting policy, a large change in capital expenditures, an organizational change or a major under- or over- recovery of overhead costs. In EPC’s opinion, none of these triggers apply to the current test period. The CG submitted that based on the 2004 experience, the significant changes in capital, which ultimately may have led to an over-recovery of overhead costs, were not significant enough to trigger a change. The CG submitted that the Board should direct EPC to provide evidence it has established a formal policy and approach process to ensure the capitalization rate is appropriate in all circumstances, including details in support of that position, as part of its next GTA. While EPC has a review process in place for the capitalization overhead rate, the Board is surprised that the significant variation in the 2004 actual capital expenditures did not result in a change in the rate itself. EPC’s evidence was that there is no formal document that is signed to indicate that a change has been approved. The Board considers that the review process itself should be documented more clearly to assist the Board and interested parties in understanding what materials are actually reviewed and how decisions that affect the rate are made. Therefore, the Board directs EPC to keep written evidence of any and all capital overhead review meetings that occur (e.g. agendas, materials presented for discussion, minutes, etc.) and have these available for review at the next GTA if so requested. The Board also has a concern with respect to the impact that the capitalization rate can have on OM&A (and therefore earnings) and rate base. The Board notes that Exhibit 162: BR.EPC-3 (in particular parts a, c, and d) shows that EPC applies 19% to its capital projects. Exhibit 163: CG.EPC-49(c)(ii) Attachment also shows that the capitalized overhead rate is 19%. Further, the Board notes the following testimony of EPC’s witness, Mr. Thompson, who stated the following at Transcript Volume 6, Page 1357:

A MR. THOMPSON: Right. In our system we just apply the 19 percent, sir.

70 Exhibit 163, CG.EPC-45(e)



The Board notes that if EPC’s actual capital spending, before the application of the capitalized overhead, in 2005 for example, was to be $10 million higher than the approved amount, EPC’s rate base will be increased by $1.9 million. In addition to this, EPC’s OM&A expenses will be decreased by $1.9 million which would accordingly increase EPC’s earnings. Due to the fact that EPC’s 2004 actual capital expenditures were significantly higher than its forecast, the Board is concerned that this situation may occur again in 2005. To guard against the possibility of this over-recovering of the capitalized overhead, the Board directs that the maximum amounts of capitalized overhead that EPC can apply to capital expenditures are as follows: $14.8 million in 2005 and $12.1 million in 2006. These are the capitalized overhead amounts as forecasted by EPC.71 In the event that EPC’s actual capital expenditures in either or both of these years is less than the forecasted amount, the Board directs that the amount of overhead capitalized be in accordance with the 19% rate. 4.8 Management/Professional Compensation In its argument, EPC stated that it provided evidence, the Mercer report, that ENMAX’s compensation and benefit plans are approximately at the median for base salary, total cash compensation, and total direct compensation, but below median for total remuneration. EPC stated that ENMAX targets total cash compensation, total direct compensation and total remuneration at the market median level for comparable positions in a relevant peer group. In EPC’s opinion, Mercer’s findings were not materially challenged and the salary and wage expenses should be approved as filed. In its argument, the CG submitted that the Mercer study is of limited use in verifying the level of compensation for EPC Distribution employees. The CG stated that it was prepared to accept the 4% increase for 2005 and 2006 but the additional 1% for each test year was not supportable and should not be approved. The CG also submitted that a pro-rata portion of the costs of the Mercer report should be borne by the other, non-regulated affiliates of EPC Distribution and EEC Calgary RRT. The CG suggested that this pro-rationing be based on the number of FTEs. In addition, the CG recommended that the Board direct EPC to conduct an independent survey of the level of EPC Distribution employee compensation by the same categories in the Mercer report and include the results in their next GTA filings. EPC argued that the CG did not provide any evidence to support its argument that 4% is acceptable but that 5% is not. EPC submitted that ENMAX’s approach of targeting the 50th percentile is reasonable. In EPC’s opinion, there is no basis for allocating any portion of the costs of the Mercer study to any other business units other than the EPC DT and the EEC RRT. EPC stated that the study was commissioned and prepared for the sole purpose of complying with the directive of the Board for inclusion in the 2005 RRT and DT Applications. The Board considers that ENMAX’s approach of targeting the 50th percentile is reasonable. ENMAX’s definition of the 50th percentile is the market median (EPC Argument – Section 3.2.6). However, the CUPE employees were found to be 8.5% below market median for total remuneration while the management/professional employees were found to be 7.7% below market median for total remuneration.72 The Board has difficulty understanding why EPC only requested a 4% inflation increase to cover wage settlements with CUPE employees though the CUPE employees were further below the market median than the management/professional

71 Exhibit 174 72 Exhibit 091, The Mercer Report



employees, while requesting a 5% inflation increase for its management/professional employees. The Board considers that there is no persuasive evidence to suggest that a 5% inflation increase is necessary for its management/professional employees given the 4% requested increase for CUPE employees. Accordingly, the Board considers the 5% inflation requested increase should be reduced to 4% for its management/professional employees. The Board has calculated the reduction amounts for 2005 and 2006 that are attributable to the disallowance of 1% for Management/Professional compensation and for simplicity, directs EPC to include these disallowances as reductions to O&M. Please see Appendix 6 for the details of the Board’s calculations. The Board also considers that the scope of the Mercer study did exceed the direction given by the Board from Decisions 2004-06573 and 2004-066. In that direction, the Board was only concerned about the employees for EEC RRT and EPC DT. While the Board considers that the statement by Mercer that an increased sample size leads to more statistical confidence, it also considers that with approximately 550 EPC DT employees to sample from, the sample size was large enough. Therefore, the Board directs that, in its refiling, EPC provide details that allocate the costs of the Mercer study to all areas of ENMAX. The cost allocation methodology should be based on the actual 2004 FTEs. In its refiling, EPC should remove from the hearing cost reserve account the sum of the amounts allocated to the other areas of ENMAX. The Board rejects the recommendation made by the CG with regard to having EPC conduct another independent study of compensation levels. The Board was satisfied that the Mercer study presented in this Application, albeit with an expanded scope, was acceptable. 4.9 Executive Compensation In its argument, EPC stated that in order to determine executive compensation, the Human Resources Committee of the ENMAX Board of Directors prepares a confidential executive compensation review, relying on a number of external sources. According to EPC, these external sources forecast base pay increases for 2005 of approximately 4%. In addition, EPC stated that as determined by Mercer, ENMAX is currently below its objective of compensating at the market median. Consequently, the 2005 forecast includes an additional 1% increase to close the gap. The CG argued that there has been no independent and verifiable study completed to determine the appropriateness of the EPC DT executive compensation. The CG considers a 4% increase in compensation for executives from the 2004 Decision base pay is not unreasonable. The CG submitted that the Board should direct EPC to recalculate the base pay amount shown in Exhibit 326-20 to allow a 4% increase per FTE. The CG also submitted that a 4% increase should also be allowed for the Benefits category compared to the 2004 Decision. EPC argued that the CG did not provide any evidence to support its argument that 4% is acceptable but that 5% is not. The CG recommended that the Board direct EPC Distribution and EEC Calgary RRT to commission an executive compensation survey to be completed for EPC’s next GTA.

73 Decision 2004-065 – ENMAX Energy Corporation 2004 Regulated Rate Tariff Part C: Non-Energy Costs and Terms and Conditions, dated August 13, 2004





In its argument, AE stated that there is no independent, testable, market-based assessment of the reasonableness of executive compensation on the record. When EPC was asked to produce the market survey it completed, EPC refused to do so on the basis of confidentiality. AE submitted that it would be fundamentally unfair for the Board to hold utilities in Alberta to a different standard of justification. AE took the position that even if the Board determines that it can make a determination regarding the reasonableness of executive compensation for purposes of this proceeding, EPC’s continued reluctance to be forthcoming and provide adequate justification suggests that EPC should be directed to complete an independent executive compensation review that examines market competitiveness on a position-by-position basis for its next GTA. In its reply argument, AE stated that while EPC supposedly relied on a number of external consulting sources, only two reports were filed during the proceeding. AE submitted that the failure by EPC to provide this information served to further hinder the ability of parties to adequately test the evidence in this area. AE also stated that the relevance of the Mercer study to the determination of the reasonableness of EPC’s request in relation to senior executive compensation is unclear. The Board notes that it is incumbent upon the Applicant to justify its forecast amounts. The Board considers that in the case of the 5% increase requested for senior executives, EPC has failed to provide adequate justification. The Board notes that EPC has used the Mercer report as justification that ENMAX is currently below its objective of compensating at the market median. The Board is of the view that since that the Mercer study specifically excluded senior executive compensation, it should not be used to justify an increase for senior executives. While the Board acknowledges that an internal study was prepared, EPC deemed the results of this study to be confidential and it was not made available for examination. The Board notes that EPC believes it is not paying at the market median for its executives, yet the market median amount for executives is not disclosed. The Board also notes that while the interveners made submissions with respect to salary increases, they did not take any issue with respect to the number of FTEs included in the executive compensation forecast. Consequently, the Board has determined the level of executive compensation for the DT as outlined in Appendix 7. The Board directs that in its refiling, EPC reduce its operating expense forecasts for executive compensation by the amount outlined in Appendix 7. The Board also directs EPC to include in its next GTA, testable evidence that it has performed a position by position review of its executive compensation to determine its market competitiveness. The Board considers that it is up to EPC whether or not it wishes to do this internally or externally. However, the Board directs EPC to make the results available for examination at the next GTA. 5 OTHER REVENUE REQUIREMENTS

5.1 Overview

EPC also requested recovery of other costs not included in OM&A, Return on Rate Base, or Depreciation. EPC stated that the following items composed their Other Revenue Requirement request:

• System Access Service (SAS) Charge • Hearing Cost Reserve



• Revenue Requirement Offsets • Pension Costs • AESO Charge Deferral Account • AESO Interest Carrying Charges

5.2 SAS Charge Forecast

5.2.1 Forecast EPC noted that all distribution system owners in Alberta, including EPC, purchase SAS, as defined in the EUA, from the Alberta Electric System Operator (AESO). The AESO is responsible for administering a tariff that recovers all of the costs required to deliver energy from supply points across the Province to the distribution system owners. Distribution system owners and individuals taking service from the AESO are obliged to pay the rates of the AESO for SAS under Section 30 of the EUA. EPC forecast the AESO SAS charges for 2005 to be $56.2 million and $57.5 million for 2006. EPC also forecast load settlement related charges from the AESO of $1.0 million in 2005 and $1.0 million in 2006. 5.2.2 Forecast Methodology EPC developed its SAS Charge forecasts by applying the 2003 AESO rates to its forecasts of 2005 and 2006 billing determinants (i.e. billing demand and energy) for each of its 33 Points of Delivery (POD – note that a POD is defined as the transition point from the Transmission system to the Distribution system). EPC stated it used the AESO 2003 rates because EPC’s currently approved rates are based on 2003 AESO rates. EPC’s POD energy forecasts for 2005 and 2006 were developed by scaling up its metered energy forecasts for 2005 and 2006 to account for distribution line losses (losses) and unaccounted for energy (UFE). EPC’s forecast billing demand for 2005 and 2006 was based on the average of the 2002 and 2003 ratio of POD energy to POD billing demand (this ratio is known as the load factor), applied to the 2005 and 2006 forecasts of POD energy. EPC also used a forecast of average hourly pool price for 2005 and 2006 in conjunction with the AESO rates (a component of which is based on hourly pool price) in determining its SAS revenue forecast. The CG had no issue with respect to the forecast AESO billing determinants for 2005 and 2006. EPC confirmed during the hearing that it began with its 2005 and 2006 metered energy forecasts as the base for its 2005 and 2006 POD energy forecasts.74 The Board approved in full EPC’s 2005 and 2006 metered energy forecasts in Section 3 of this Decision. The Board considers the methodology used by EPC of basing its POD energy forecast on a historically accurate metered energy forecasting methodology to be reasonable. The Board further considers that the methodology of using a most recent two year historical average load factor in forecasting POD billing demand is also appropriate.

74 Transcript Volume 3, p. 496



Finally, the Board has reviewed the EPC calculation of its SAS expense forecasts,75 and considers that the 2005 and 2006 EPC SAS charge forecasts are reasonable. The Board therefore approves the 2005 and 2006 EPC SAS charge forecasts as applied for. 5.2.3 Transmission Access Deferral Account and Rider EPC stated that it had received approval in Decisions 2004-066 and 2004-082 for a Transmission Access Cost (TAC) Deferral Account and Rider with an annual true-up to recover all non-volume variances between its forecast and actual AESO charges. EPC requested a continuation of a TAC Deferral Account and Rider for 2005 and 2006 using a methodology similar to that approved by the EUB in Decision 2004-082 for 2004. EPC stated that the TAC Deferral Account will contain non-volume variances between forecast and previously outlined actual AESO Tariff charges as well as any other applicable AESO rates, deferral account dispositions or riders. EPC proposed that a recovery rider for this deferral account would comply with Decision 2004-066 and be on a ¢/kWh basis and would not vary by rate class. The CG suggested in argument that EPC’s deferral account should be the difference between the revenue it receives through the Transmission portion of its DT rates and its actual Transmission costs. Further, the rider used to collect EPC’s deferral account should not be a simple ¢/kWh rider as approved by the Board in 2004, but rather should consider the changes anticipated to the AESO tariff for 2006 and beyond. EPC replied that such a form of a TAC deferral account would be different than the TAC deferral account approved in Decision 2004-066. The Board is in agreement with EPC that the TAC deferral should contain non-volume variances between forecast and actual tariff charges as well as any other applicable AESO rates, deferral account dispositions or riders. If the Board were to rule that the deferral account be based simply on actual Transmission costs compared to actual Transmission revenue, it would be eliminating the volume forecast risk element from EPC’s Transmission component. The Board’s intent is not to eliminate this forecast risk, and thus approves in full the requested EPC TAC deferral account calculation procedure as applied for. The Board also considers that EPC’s applied for form of TAC rider in 2005 is still appropriate, given the relative similarity of the 2003 and 2005 AESO Tariff. The Board therefore approves in full EPC’s applied for methodology of using a ¢/kWh rider for all of its customers for its 2005 deferral account. However, with respect to the form of rider used to recover EPC’s 2006 TAC deferral account, the Board notes that in Decisions 2005-096,76 2005-131,77 and 2005-132,78 the 2006 AESO tariff underwent a significant price increase and change in cost recovery methodology. As such, in this instance, the Board sees merit in the CG’s request that EPC examine cost causation issues of any amount contained in its 2006 TAC deferral account and that EPC should propose an appropriate 75 Exhibit 162, BR.EPC-18 76 Decision 2005-096 – Alberta Electric System Operator (AESO) 2005/2006 General Tariff Application, dated

August 28, 2005 77 Decision 2005-131 – Alberta Electric System Operator (AESO) Refiling of 2005/2006 General Tariff

Application per Decision 2005-096, dated December 6, 2005 78 Decision 2005-132 – Alberta Electric System Operator (AESO) Review and Variation of Customer Related

POD Charge, dated December 6, 2005 EUB Decision 2006-002 (January 13, 2006) • 31









allocation of the TAC deferral costs by rate class and the form of rider(s) for recovery of its 2006 TAC deferral account at the time EPC applies for its 2006 TAC deferral rider. The Board will therefore refrain from approving a form of the 2006 TAC deferral account rider at this point in time and directs EPC to examine and report on this matter to the Board at the time of its 2006 TAC deferral rider application. 5.3 Hearing Cost Reserve EPC noted that its 2004 Hearing Cost Reserve (HCR) account was approved in Decision 2004-066 with an approved opening balance of $2.8 million effective January 1, 2004. EPC stated that two 2004 cost orders had been approved by the EUB and have been debited to the HCR, namely EPC’s 2004 Interim DT Proceeding and the Generic Cost of Capital Proceeding. EPC has also forecast a cost order for EPC’s 2004 DT Application based on submitted cost claims. EPC forecast that a result of these three items, the 2004 year end balance carrying over into 2005 would be $0.7 million. EPC requested funding of $1 million for 2005 and stated that this amount, along with the $0.7 million forecast to be carried forward from 2004, would be sufficient to meet hearing costs for 2005. EPC stated that hearing costs for 2005 consist of EPC’s 2005-2006 DT Application (Phase I), the EUB assessment and miscellaneous orders, and forecast the 2005 year end balance to be $0.1 million. EPC requested funding amount of $1.3 million for 2006, and stated that this funding plus the $0.1 million forecast to be carried forward from 2005 would be sufficient to meet hearing costs for 2006. EPC forecast that hearing costs for 2006 consist of EPC’s 2005-2006 DT Application (Phase II), the EUB assessment and miscellaneous orders, and forecast the 2006 year end balance to be $0.1 million. In argument, EPC proposed to revise its HCR at the time of its refiling, by adjusting its 2005 opening balance from $0.7 million to $1.1 million to account for the 2004 actual closing balance, and also by removing miscellaneous order costs of $0.2 million in 2005 and 2006. EPC stated that as a result of these revisions, EPC was now requesting funding of $0.3 million for 2005 and $1.2 million for 2006.79 The CG stated that $0.75 million was a more appropriate amount for 2005, given that the proceeding was only for a Phase I application, and that total costs for the 2004 Phase I and II proceeding were only $0.75 million. The CG also noted that there was a larger balance in the HCR at year end 2004 than originally forecast in the Application (i.e. $1.1 million vs $0.7 million). The CG further submitted that the 2006 HCR amount should be targeted to reach zero, to be consistent with Decision 2005-01980 related to AltaLink. The Board agrees there was a forecast error in EPC’s starting balance for 2005. The Board also agreed with the CG statement that the entire hearing costs for the Phase I and II portions of the 2004 EPC proceeding were $0.75 million. The Board considers that a value of $0.65 million will represent an upper boundary on EPC’s hearing costs for 2005 and 2006. As such, the Board 79 Exhibit 163, response to CG.EPC-46(b)

80 Decision 2005-019 – AltaLink Management Ltd. and TransAlta Utilities Corporation 2004-2007 General Tariff Application, dated March 12, 2005






considers that EPC’s revised 2005 starting balance of $1.1 million should be sufficient to cover its hearing reserve costs for 2005, and will not award any extra amount. The Board therefore denies EPC’s updated request for $0.3 million for hearing reserve funding in 2005. The Board has reviewed the items on which EPC based its forecast for 2005 and 2006 and notes the similarities. The Board does not consider that there is anything to suggest that the magnitude of cost items in 2006 will not be similar to 2005. Using EPC’s 2005 year-end forecast of $0.1 million, the Board considers that an amount of $1.0 million will be required by EPC in 2006, resulting in a total hearing cost reserve for 2006 of $1.1 million. The Board therefore approves a hearing reserve cost funding amount of $1.0 million for 2006. For the above reasons, the Board directs EPC to reduce its updated 2005 hearing cost reserve request of $0.3 million by $0.3 million, and similarly to reduce its updated 2006 hearing cost reserve request of $1.2 million by $0.2 million. In summary, the Board directs EPC to modify Schedule 5.3 (Regulatory Hearing Cost Reserve Account) as noted in Table 3. Table 3. Summary of Changes to Regulatory Hearing Cost Reserve Account

Component 2005 ($ million)

2006 $ million)

Opening Balance (1.1) (0.05) Funding 0 (1.0) 2005-2006 DT 0.65 0.65 Miscellaneous Orders 0 0 5.4 Revenue Requirement Offsets EPC forecast revenue requirement offsets of $2.5 million for 2005, and $2.7 million for 2006.81 EPC stated that the offsets relate to Wholesale Services, and Distribution, Network, and Other. EPC stated that Wholesale services related to such items as reconnects, disconnects, and temporary services within the City of Calgary, revenues and expenses related to the provision of meter reading services to the City of Calgary Waterworks, and the provision of various services to other municipalities (Red Deer, Lethbridge, Cardston, Fort Macleod and the Municipality of Crowsnest Pass). Distribution, Network and Other included items such as pole and duct rental, contractual services and other revenues associated with land rental, scrap sales and interest. EPC noted that in 2004 the Board directed EPC to calculate revenue offsets based on fully allocated costs, and that EPC complied in its refiling. EPC noted that it had engaged BearingPoint to conduct an independent cost allocation study to determine the extent to which fully allocated costs were above the original incremental revenue and incremental expenses originally budgeted by EPC.

81 Exhibit 3, page 50; exhibit 245, schedule 5.4. 2004 actuals are set out in exhibit 245 (schedule 5.4).



The CG noted that EPC had provided details of Distribution, Network and Other revenue offsets in Schedule 5.4 of its Application, along with a reconciliation of these revenue offset amounts in Exhibit 270. The CG suggested that this undertaking response reflected certain changes in the Distribution, Network and other revenue offset amounts, including an additional amount of $0.5 million for inventory and scrap sales in 2006 and that based on a review of this information, it recommended the Distribution, Network, and Other revenue offsets as set out in Exhibit 270 be approved. The CG submitted EPC should be directed to assess computer hardware and enterprise software costs applicable to the wholesale services function and, to the extent material, include these costs in the pool of wholesale services costs allocated to Calgary water and other Municipalities at the next GTA. The CG also recommended that EPC be directed to allocate a share of administration costs to Calgary water and the Municipalities on the basis of the sub total of all other wholesale services costs for purposes of the EPC refiling. EPC submitted that it was not appropriate, in the circumstances, to allocate computer hardware, enterprise software costs and administration wholesale costs to Calgary water and other Municipalities. EPC stated that in any allocation, it was desirable to have costs allocated based on actual usage. The result of BearingPoint’s study clearly showed, as a result of interviews,82 for example, that the amount of time spent dealing with Calgary water, and the other municipal clients, was different.83 This should therefore be reflected in the allocation, rather than using the sub-totals (which are effectively weighted averages) as suggested by the CG. An allocation based on actual usage is superior, in EPC’s submission, to any form of indirect allocation, including that recommended by the CG. Indeed, it must be noted that there is no evidence on the record to challenge the allocation methodology developed by BearingPoint, a respected and experienced independent third party, and EPC submitted that the allocation methodology developed by BearingPoint should be approved. The Board, for the purpose of this Decision, will accept the BearingPoint study allocation. However, the Board directs EPC to further study and show cause as to why some portion of wholesale computer hardware, enterprise software costs and administration should not be allocated to Calgary water and other Municipalities in a fully allocated cost study and submit the results of this further study at EPC’s next GTA. 5.5 Pension Costs EPC stated that ENMAX sponsors a pension plan with both a Defined Benefit (DB) and Defined Contribution (DC) option, a Supplemental Retirement Plan (SRP) and other post-retirement benefits as part of its compensation program. With respect to the SRP, EPC stated by way of response to a CG information request that it proposes to amend its 2005 and 2006 revenue requirements in EPC’s 2005-2006 DT re-filing to reflect the cash funding cost of SRP as opposed to an accrual method.84 EPC stated that this change will bring the treatment of SRP in line with the cash funding treatment used with the DB 82 Exhibit 97, p. 10 83 Transcript Volume 3, p. 626, line 9 to page 627 line12 and Exhibit 97, p. 28

84 Exhibit 163, CG.EPC 55(c)



pension. EPC submitted that the change results in an increase of $226,000 to EPC’s revenue requirement for 2005 and a decrease of $169,000 for 2006. The CG opposed the proposed change in accounting for SRP costs from the currently approved accrual method to a “cash” basis, stating that as EPC had suggested the change only after the Application was filed and as part of the IR responses, it appeared to be an after-thought and, arguably, is an attempt to capture the higher costs on a cash funding basis during the test years. The CG submitted that the accrual method resulted in a more stable Revenue Requirement than under the cash basis and should continue to be used, and therefore recommended that EPC be directed to re-file its SRP expense under the accrual method and adjusted downward. The Board notes the magnitude of the CG estimate of revenue requirement impact of the change and considers that the aggregate additional cost of $57,000 spread over 2005 and 2006 should be more than offset in future by cost savings related to having a similar accounting treatment for both plans. The Board therefore approves EPC’s request to change to a “cash basis” accounting treatment for its SRP. With respect to the DB option, EPC stated that the last valuation of the ENMAX DB pension plan was conducted at December 31, 2003, and that at that time, the ENMAX Plan had a solvency ratio of 0.723. EPC noted that Alberta Finance requires plans with a solvency ratio of less than 0.85 to file a plan valuation on an annual basis. EPC noted that in 2005 ENMAX will prepare a plan valuation based on its financial position at December 31, 2004. EPC stated that the DB plan solvency deficiency is estimated to be $34.1 million as at December 31, 2004, and that the cash funding obligation to pay for this deficiency is expected to be $9.0 million per year over the next five years. To mitigate the impact to distribution system consumers, EPC proposed to amortize the amount of the deficiency over 10 years by way of a deferral account. Thus EPC applied for DB Pension contributions of $2.2 million for 2005 and 2006. EPC also noted that in addition to making contributions to fund the solvency deficiency under the DB option, ENMAX was required to make regular contributions to fund the normal actuarial cost estimated to be approximately $2.7 million in 2005 and $2.9 million in 2006. EPC requested an additional payment of approximately $0.7 million for 2005 and 2006 to fund deficiencies on commuted values expected to be paid from the plan, and included these amounts in the OM&A revenue requirement under salaries and wages. The CG stated that EPC’s proposal to include an additional $2.2 million in pension expense to fund the DB plan solvency deficiency should be rejected, as the deficiency arose in large part due to the reduction in the discount rate used by the actuary in 2003 and 2004. Since 2003, the solvency position of the DB plan had improved by about $1.7 million and also the investment returns have increased in 2004 to about 10.05%, compared to 0.75% for the three-year period ending December 31, 2003. The CG also submitted that EPC’s decision to take a more aggressive investment portfolio, with 70% invested in equity, appeared to play a large role in contributing to the solvency deficit, and further submitted that the industry average is about 56% in equities and 44% in fixed securities. The Board notes the comments of the CG concerning the actuarial assumption of discount rates in addition to the investment approach taken by EPC versus the industry as a whole. The Board



further notes the more recent actuarial and return results which indicate a reduction in the pension deficit. The Board considers however, that the statutory legislation that EPC’s pension deficit be retired within five years85 be given the most weight in arriving at its Decision. The Board considers that EPC’s applied for amounts and deferral methodology represent a balanced approach to retiring its pension deficit, in that recognition has been given to the fact that the investment conditions and actuarial assumptions which led to the deficit forecast appear to be changing to the benefit of the pension fund. The Board therefore approves EPC’s pension funding request and deferral account as applied for. The Board does consider that EPC should consider the investment approach of other utilities in the Province, and include a discussion of how its approach compares to other utilities at the time of its next DT Phase I application. The Board also expects that EPC provide an updated actuarial study at the time of its next application, such that the Board can monitor and make changes if required to insure that the EPC pension funding deficit is retired within five years. 5.6 AESO Customer Contribution Carrying Charges Deferral Account EPC stated that this deferral account will include the carrying cost of customer contributions required by the AESO from EPC in its capacity as a Distributor. EPC stated that its distribution system requires certain substation facilities (classified as transmission facilities in the EUA) to be constructed, and that the AESO has placed the “approval for the need to construct” document for these facilities before the EUB.86 EPC noted that as part of that application, however, the AESO stated its intention to require a full contribution for the facility from the customer.

EPC stated that assuming that the substation construction is approved, EPC will be required to make a customer contribution of approximately $6.05 million to the AESO in 2005.87 EPC requested a carrying cost related to this contribution of $0.2 million for 2006.

The CG did not comment on this topic in argument but suggested in reply that any carrying charges should be collected as part of a transmission deferral account. The Board notes that EPC has not included the forecast value of $6.05 million in its rate base forecast or capital expenditures for 2005 and 2006. The Board therefore does not consider it appropriate that EPC be awarded any cash return on this forecast expenditure. However, the Board will allow EPC to include a non-cash return in the form of AFUDC for any customer contribution expenditures incurred during 2006. Assuming it is approved, following the substation’s completion and in-service date, it is open to EPC to apply at the time of the next GTA to add the $6.05 customer contribution together with associated AFUDC to the rate base. The Board therefore denies the requested cash amount of $0.2 million related to AESO Customer Contribution Carrying Charges in the 2006 revenue requirement.

85 EPC Argument, p. 42 86 Application No. 1359795 ENMAX 6S 138/13.8 kV Substation - Need Application 87 $6.05 million (2004$) as set out in Table 4.5-1, p. 7 of the Need Application. This estimate will be revised

before construction begins and the customer contribution required will be adjusted accordingly.



In the event that the AESO fails to return any EPC contribution plus AFUDC to EPC in the future, EPC will have the opportunity to apply to recover these costs as part of a future Phase I application. 5.7 Uniform System of Accounts Deferral Account EPC stated that it is an active participant in the process that has been initiated in relation to the development of a uniform system of accounts. In EPC’s view, at the present time, there is considerable uncertainty regarding the timing and scope of the implementation of the uniform system of accounts. As a result, EPC submitted that it is appropriate and reasonable to establish both an operating expense and capital expense deferral account to deal with the scoping and implementation costs. The Board notes that in this Application, EPC has not requested approval of any amounts. The CG did not object to the establishment of a deferral account for these costs, subject to the ability of the Board and interveners to examine these costs in future proceedings. The Board considers that this is an important initiative and that all utilities should be encouraged to move it forward with priority. The Board considers that EPC’s participation in this process is valid and that EPC should participate fully to see this matter implemented as soon as reasonably practical. Consequently, EPC should be entitled to recover any prudently incurred costs associated with the scoping and implementation process. The Board approves the establishment of the EPC requested operating expense and capital expense deferral accounts to deal with the scoping and implementation costs incurred by EPC in association with the development of a uniform system of accounts. For clarity, the Board considers that this approval is simply for the establishment of the deferral account, and that no costs have been approved for collection. The Board agrees with the CG that interveners and the Board should have the ability to examine these costs in future proceedings. To that end, the Board directs EPC, in its refiling, to include a proposal for a review process for any amounts recorded in the Uniform System of Accounts deferral accounts. 6 RATE BASE

6.1 General The Board notes that some of the issues in this General section were raised by the CG in the context of Network expenditures. However, the Board considers that these issues should be addressed in the context of both Distribution and Network expenditures and will deal with these issues in this General section. 6.1.1 Overhead Capitalization Rate The CG recommended that EPC be directed to review all overheads capitalized, remove such expense from projects with contributions from other projects and consistently apply 19% to the balance of its 2005-2006 forecast network capital expenditures. The CG suggested that EPC used a capitalized overhead rate of 22% for its 2005-2006 forecast network capital expenditures. In its reply, EPC noted that the CG has simply assumed that the “overhead” column in CG.EPC-19(a) includes only the 19% overhead capitalization rate and does not include any overhead



related costs such as AFUDC for example. EPC confirmed that the capitalized overhead rate used was 19%, and not 22%. The Board notes that the matter of the capitalized overhead rate calculation was examined in substantial detail, both through the IR process as well as at the hearing. In understanding the calculation of the capitalized overhead rate, the Board has reviewed the evidence on this subject and in particular Exhibit 174, the attachment to BR.EPC-003(a), and Exhibits 278 and 314. The Board is satisfied that the material presented in these exhibits clearly presents that the capitalized overhead rate was calculated to be approximately 19%. Consequently, the Board rejects the suggestion of the CG on this matter. However, the Board directs EPC, in its next GTA, to provide greater detail on the calculation of the capitalized overhead rate. The Board considers that information similar to that presented in Exhibits 174, 278 and 314 of this proceeding would be beneficial to parties in understanding how the capitalized amounts are derived. The Board further directs EPC to clearly set out the components of shared services and other OM&A expenses that are considered to be subject to administrative overhead capitalization including reasons why the capital component of these accounts cannot be determined by direct assignment. 6.1.2 Review of Prior Year Large Capital Project Additions The CG expressed concerns regarding the situation where projects that were not forecast to occur in a test period end up being included in rate base on an actual basis. In the opinion of the CG, there is little or no review on the need, timing, cost justification or prudence of such projects. The CG submitted that to facilitate a post-audit review of large projects (over $100,000) added in a year, but not included in the forecast, EPC should be directed to file business cases identifying the need, timing, cost justification and prudence at the next GTA. In its reply, EPC did not offer any comments on this subject. The Board considers that all additions to rate base should be justified. In addition, the Board and interested parties should have the ability to examine these additions, whether or not they are included in a test-year forecast. The Board considers that parties should be provided the opportunity to examine any additions to rate base which had not been included in forecasts within GTAs. The Board realizes that if it was left until the IR stage for interested parties to request a business case for unforecast additions, it would result in increased hearing time for the parties to examine these business cases. In the Board’s view, this would not be an efficient way to proceed. In response to the suggestion of the CG that the threshold amount be $100,000, the Board notes that its current threshold for the inclusion of a business case for forecasted capital projects is $500,000. The Board has not been presented with any persuasive evidence to amend this threshold amount. Consequently, the Board directs EPC, in its next GTA, to include business cases for any actual capital project additions to rate base in 2005 and 2006 that are greater than $500,000 and that were not included in the capital forecast in this Application. To assist in this matter, the Board and interested parties need to know exactly what capital projects are included in this Application. As a result, the Board directs EPC, in its refiling, to expand Schedules 6.3.1.3 and 6.3.1.4 to include the project number, description and forecast amounts that comprise the various capital programs.



Further, the Board directs EPC to include information respecting each forecast project, including project number, description and forecast amounts that comprise the various capital programs for the forecast years of its next GTA. The Board also directs EPC to include corresponding schedules that contain actual results for 2005 and either actual 2006 results or an updated forecast for 2006 at the time of its next GTA. This information will enable the Board and interested parties to compare the 2005 and 2006 results to the approved forecasts for those years and verify that business cases have been filed where necessary. 6.1.3 Capital Expenditures EPC has forecast gross capital expenditures of $91.7 million for 2005 and $73.1 million for 2006. For 2005, approximately 47% of the forecast capital expenditures are driven by growth, with the remaining 53% driven by upgrade and improvement costs. For 2006, 64% of the forecast capital expenditures are driven by growth. EPC indicated that business cases have been provided for every capital project or program in excess of $500,000. The CG expressed concerns regarding the forecasting accuracy of EPC with respect to certain categories of EPC’s capital expenditures. The Board will deal with specific capital expenditure programs in the sections that follow. 6.2 Distribution The capital expenditures for the Distribution program are made up of electrical infrastructure including equipment, apparatus and associated necessary costs and activities to deliver power to users, outside the downtown core, at voltages equal to or less than 25 KV. The forecasted capital expenditures for the Distribution program for 2005 and 2006 comprise the majority of the capital spending for both years (62% in 2005 and 78% in 2006). The CG had no specific objections to the forecast provided for the Distribution program capital expenditures. The Board is satisfied with the forecast EPC provided for Distribution and approves the forecast as filed, subject to the comments that are applicable to the entire capital expenditures area. 6.3 Network The capital expenditures for the Network program are comprised of civil infrastructure, electrical apparatus and associated necessary costs and activities to deliver power to users, in the downtown network, at voltages equal to or less than 25 KV. The forecasted capital expenditures for the Network program for 2005 and 2006 are $6.6 million in 2005 and $6.7 million in 2006. In EPC’s opinion, the continuing strong economic environment in Alberta and within Calgary continues to be the primary driver of these expenditures. In its argument, the CG submitted a number of recommendations with regard to the capital expenditures for the network program. The Board will address each one of these recommendations separately.



6.3.1 Separation of Residential and Non-Residential Development The Board considers the recommendation of the CG to show the capital expenditures for the residential and non-residential development area of the Network capital program separately is simply a reiteration of what EPC proposed in its response to Exhibit 134, TM.EPC-7(a). The Board notes that all parties are in agreement with this recommendation and the Board considers this approach would be useful in future Phase II deliberations. Accordingly, the Board directs EPC, in its next GTA, to show the capital expenditures for the residential and non-residential development area of the Network capital program separately. The Board also directs EPC, in its next GTA, to file separate business cases for the residential and non-residential development areas in accordance with the threshold amount of $500,000. 6.3.2 Project C123 – Network 25kV System In its argument, the CG noted that $0.45 million of the forecasted 2005 and 2006 capital expenditures in each year are related to this project. While the CG did not object to the costs of this project, it did disagree with EPC’s characterization of these costs as “system” related. The CG submitted that it appeared that the primary beneficiaries would be the 29 downtown customers. The CG submitted that EPC should address this issue as part of its Phase II filing. EPC did not address this issue in its reply argument. The Board considers that EPC has already made its judgment as to the proper treatment of these forecast capital costs. However, the Board sees no reason why interested parties cannot address this issue as part of EPC’s Phase II Application. Therefore, the Board accepts the submission of the CG that EPC address this issue as part of its Phase II filing. 6.3.3 Project C10097 – Network Vault Protection In its argument, the CG submitted that the $0.4 million for Project C10097 costs in 2005 should be disallowed. The CG submitted that including this project in 2005 amounts to “double-dipping” as EPC had received forecast approval for this amount in 2004 but did not spend the money. The CG believed that if EPC is granted approval for this project in 2005, it will send EPC a very strong signal that it is okay to defer forecasted approved projects and include them again in its next application. In its reply argument, EPC took exception to what it called an unfounded allegation about “double-dipping”. EPC noted that customers have benefited significantly from forecast variances and submitted that this is an issue that should be considered on a “macro”, rather than a “micro” basis. EPC noted that the actual capital expenditures for 2004 exceeded the approved expenditures by approximately $24.264 million and as a result EPC under-recovered. The Board is aware that the 2004 actual capital expenditures for EPC were significantly greater than the approved forecast amounts. The Board has expressed its concerns with respect to this issue in conjunction with its comments on Section 4.7, the operating expenses capitalized. The Board agrees with EPC that the issue of the accuracy of capital expenditure forecasting should be dealt with on a macro basis instead of examining each separate project. The Board considers that the management of EPC has to deal with the capital spending on an overall level, as priorities and timeline estimates continually change. The Board also considers that the fact that EPC did indeed under-recover in 2004 demonstrates that the $0.4 million in question was a single item in



a much larger program and that EPC is not engaging in what the CG refers to as “double-dipping”. Consequently, the Board rejects the recommendation of the CG. 6.3.4 Historical Forecasting Accuracy: System Infrastructure Development – Quality

of Supply In its argument, the CG presented a table that documented an analysis between the actual capital expenditures and the forecast capital expenditures in this network area from 2000 to 2004. The results of this analysis were that over the last five years, EPC has over-forecast in this network area by 53%, or $0.9 million. The CG expressed a concern about EPC’s tendency to consistently over-forecast capital costs in this area and submitted that based on this forecasting history, EPC’s forecast costs in this area should be reduced by 50% in 2005 and 50% in 2006. In its argument, EPC noted that customers have benefited significantly from forecast variances and submitted that this is an issue that should be considered on a “macro”, rather than a “micro” basis. EPC noted that the actual capital expenditures for 2004 exceeded the approved expenditures by approximately $24.264 million and as a result EPC under-recovered. The discussion regarding 2004 capital expenditures set out in section 6.3.3 above applies equally here. The fact that on an overall basis, the 2004 actual capital expenditures were more than the forecast amount, the Board does not have persuasive evidence that EPC has a tendency to over-forecast capital expenditures. Consequently, the Board rejects the recommendation of the CG. 6.3.5 Reliability of the Network System In its argument, the CG expressed a concern that without a firm or measurable yardstick to assess the degree to which EPC is providing safe, reliable and economic service, EPC may be under or over installing Network capital additions. The CG recommended that EPC provide details of industry practices forming the basis for measuring the reliability of EPC’s network system with that of other electric distribution utilities as part of its next GTA. The CG went on to state that if there are no industry indices available related to Network reliability, EPC should provide evidence on the reliability of its own Network system over the most recent five year period and compare this to what it expected over the test period. EPC did not address this issue in its reply argument. The Board considers that it is necessary for the Network system to be safe and reliable. The Board considers that it would be beneficial to be able to compare the reliability of the EPC Network system to the Network systems of other electric distribution utilities, if such a comparison is possible. The Board also is of the view that it would be beneficial to compare the annual results of this reliability index to the forecasted amounts. Consequently, the Board directs EPC, in its next GTA, to provide details of comparisons between the reliability of its network system with the network systems of other distribution utilities. The details provided should be comprehensive enough to permit the Board and interested parties to understand, among other things, what the reliability measures are, how they are calculated and how and when they are measured. The Board also directs EPC, in its next GTA, to include yearly forecast amounts for these network reliability indexes as well as actual results for 2005 and 2006. If other electric distribution utilities have already developed these reliability indices, the Board considers that EPC should adopt these as placeholders. If EPC



discovers that there are no such indices in use by other distribution utilities, then EPC should develop these indices internally. 6.4 Wholesale Services The forecast capital expenditures for the Wholesale Services program for 2005 and 2006 are approximately $20.6 million in 2005 and approximately $5.2 million in 2006. Included in the 2005 forecast are expenditures for the following projects:

(1) Distribution Tariff Billing (2) Interval Meter Phone Line Replacement, and (3) Annual Meter Procurement.

In its argument, the CG expressed concerns regarding the contingency amount of $1.096 million included in the Distribution Tariff Billing System capital addition. The CG indicated that the contingency amount was applied to all of the project costs, including those not at risk. The CG also pointed out that during cross-examination, EPC indicated that the at-risk components of the Distribution Tariff Billing System project were the components related to design and implementation. The CG submitted that the contingency amount should be applied to at risk items only. In its reply, EPC stated that if only at risk components are included in the contingency amount, the contingency percentage would have to be increased to reflect the increased risk. EPC also indicated that the impact of the CG recommendation would be approximately $10,548. The Board notes that the issue of the contingency amount for the Distribution Tariff Billing System project was thoroughly examined during the oral part of the proceeding. During examination, EPC indicated that the reason for the contingency was to cover any additional requirements that may be put into the Tariff Billing Code. EPC also stated that the two areas of design and implementation would be the areas impacted by any version changes and that the licensing would be not be impacted as it was a fixed cost. The Board agrees with the CG that the contingency should be applied to at risk items only. The Board notes that it is clear from the testimony of EPC’s witness that the two at risk items with respect to this project are the design and implementation portions. The Board has reviewed the calculation included by the CG in its argument and agrees that the contingency amount should be $0.829 million. Therefore, the Board directs EPC, in its refiling, to reduce the 2006 capital additions with respect to the Distribution Tariff Billing System project by $0.267 million (i.e. $1.096 million - $0.829 million), and to flow through the impact of this reduction to all other applicable areas of the Application (e.g. return on rate base, depreciation and GST working capital). 6.5 Information Technology, General Plant and Other The forecast capital expenditures for the Information Technology, General Plant and Other program for 2005 and 2006 are approximately $7.9 million in 2005 and approximately $4.3 million in 2006. Spending in this area is comprised of a number of different categories, including software and hardware components, office furniture and equipment, buildings and leasehold improvements. 42 • EUB Decision 2006-002 (January 13, 2006)


The CG had no specific objections to the forecast provided for the Information Technology, General Plant and Other program capital expenditures. The Board is satisfied with the forecast EPC provided for Information Technology, General Plant and Other and approves the forecast as filed, subject to the comments that are applicable to the entire capital expenditures area. 6.6 Necessary Working Capital EPC has forecast a necessary working capital requirement of ($2.0) million for 2005 and ($0.4) million for 2006. Included in EPC’s Application was Schedule 6.6.1, which provided the backup for the calculation of the necessary working capital requirements. Schedule 6.6.1 is comprised of three areas:

(1) Expense Items, which consist of expense amounts and net lead/lag days, (2) Adjustments, which also consist of expense amounts and net lead/lag days, and (3) Various mid year balance sheet working capital items including inventory, the hearing

cost reserve and GST. The net lead/lag days were presented on Schedule 6.6.2 with further details included on Schedule 6.6.4 (Revenue Lag) and Schedule 6.6.5 (Operations, Maintenance and Administration Lag). Schedule 6.6.3 was also included in the Application. This schedule provided the backup for the GST Working Capital amounts that were shown on Schedule 6.6.1. Schedule 6.6.3 is comprised of various receipts and disbursements amounts in addition to the lag days for each particular area. The CG had no comment on any aspect of necessary working capital, including the lead/lag Sections. 6.6.1 Lead/Lags

Revenue – Lead Lag EPC presented details, in conjunction with Schedule 6.6.4, of the study undertaken by EPC to calculate the revenue lag days that were used in the Application. The result of the study indicated a revenue lag of 47.98 days. The Board is satisfied with the forecast for the revenue lag days that EPC provided and approves the forecast amounts as filed. System Access Service Charges – Lead Lag EPC presented details that resulted in the expense lag days that were used in the Application for system access service charges. The result of the work indicated an expense lag of 44.94 days.



The Board is satisfied with the forecast for the system access service charges lag days that EPC provided and approves the forecast amounts as filed. Operations, Maintenance, and Administration – Lead Lag EPC presented details, in conjunction with Schedule 6.6.5, of the study undertaken by EPC to calculate the OM&A lag days that were used in the Application. The result of the study indicated an expense lag of 46.97 days. The Board is satisfied with the forecast for the OM&A lag days that EPC provided and approves the forecast amounts as filed. Interest on Long-term Debt – Lead Lag EPC presented details of the work undertaken by EPC to calculate the expense lag days that were used in the Application for long-term debt interest charges. The result of the work indicated an expense lag of 130.87 days. The Board is satisfied with the forecast for the long-term debt interest lag days that EPC provided and approves the forecast amounts as filed. Depreciation – Lead Lag EPC indicated that the payment lag for depreciation is zero. The Board is satisfied with the forecast for the depreciation lag days that EPC provided and approves the forecast amounts as filed. Common Return – Lead Lag EPC presented details of the work undertaken by EPC to calculate the expense lag days that were used in the Application for the dividend component and the retained earnings component of the return on common equity. The result of the work indicated an expense lag of 45.63 days for dividends and an expense lag of zero for retained earnings. The Board is satisfied with the forecast for the dividend and retained earnings lag days that EPC provided and approves the forecast amounts as filed. Summary Board Findings – Lead Lag The Board is satisfied with the forecast net lead/lag days EPC provided and approves these days as filed. The Board notes that as a result of directions from other parts of this Decision, some of the Lead Lag related figures under the “Expense” column of Schedule 6.6.1 for 2005 and 2006 and the “Amount” column of Schedule 6.6.3 for 2005 and 2006 will change. The Board directs EPC, as part of its Refiling, to ensure that the amounts included under the “Expense” column of Schedule 6.6.1 for 2005 and 2006 and the “Amount” column of Schedule 6.6.3 for 2005 and 2006 are updated where necessary to reflect the refiled amounts.



6.6.2 Materials and Supplies Inventory The forecast of $0.1 million for 2005 and $0.1 million for 2006 represents the portion of the mid-year balance of materials and supplies inventory that supports EPC’s operation and maintenance activities. The Board is satisfied with the forecast for materials and supplies inventory that EPC provided and approves the forecast amounts as filed. 6.6.3 Customer Deposits The amounts of ($2.1) million for 2005 and ($2.1) million for 2006 represent the forecast security deposits from retailers. The Board is satisfied with the forecast for customer deposits that EPC provided and approves the forecast amounts as filed. 6.6.4 SAS Deferral Account The amounts of ($1.0) million for 2005 and nil for 2006 represent the forecast mid year balances of the SAS charges deferral account. The Board is satisfied with the forecast for the SAS deferral account that EPC provided and approves the forecast amounts as filed. 6.6.5 Hearing Cost Reserve Account The amounts of ($0.5) million for 2005 and ($0.1) million for 2006 represent the forecast mid year balances of the HCR account. The Board, in Section 5.3 of this Decision, has addressed the issue of the level of funding for the HCR and found as follows:

The 2005 forecast opening balance was revised to ($1.1) million; the funding amount for 2005 was reduced to $0 and the funding amount for 2006 was reduced to $1.0 million; the miscellaneous order amounts were reduced to $0 for both 2005 and 2006; and the 2005 and 2006 forecast cost orders for the 2005-2006 DT were reduced to $0.65 million.

The Board expects that after the impact of these reductions, the forecast mid year balances for the HCR account will change. The Board directs EPC, in its refiling, to reflect these updated balances in the necessary working capital calculations. 6.6.6 AESO Deferral Account The amounts of $0.1 million for 2005 and $0.1 million for 2006 represent the forecast mid year balances of the AESO capital charges deferral account. The Board is satisfied with the forecast for the AESO capital charges deferral account that EPC provided and approves the forecast amounts as filed.



6.6.7 Goods and Services Tax (GST) EPC provided details of the GST Working Capital amounts comprised of various receipts and disbursements amounts in addition to the lag days for each particular area. The Board is satisfied with the forecast for the GST subject to changes to any of the expense amounts that result from directions in other parts of this Decision. 7 DEPRECIATION

7.1 Depreciation Overview The Board, in Decision 2004-066, provided EPC with the opportunity to implement a more simplified method of depreciation in this GTA. The Board notes that prior to Board regulation, EPC had introduced a complex system of tracking retirements by vintage. Accordingly, the Board considers that the front-end costs of implementing EPC’s system of tracking retirements by vintage should be viewed as a management asset control requirement rather than a necessary Board regulatory requirement for depreciation studies. EPC has chosen to stay with the Equal Life Group (ELG) method and now attempts to forecast retirement dispersions for all Distribution and Network accounts using historical vintage retirement data tempered with future expectations. The Board considers this to be a management decision with the extra complexity not necessary from a regulatory perspective. The Board notes EPC’s evidence that the extra costs of preparing a depreciation study using the ELG method are minimal compared to the preparation costs of a simplified depreciation study. The Board accepts these minimal additional costs for the purposes of this Decision. However, the Board will monitor the costs of future depreciation studies using the ELG system and if these costs become significant the Board may deem these costs to be unnecessary for the purpose of regulatory depreciation studies. Notwithstanding the above, the Board considers that the depreciation method, whether complex or simplified, should make use of the retirement vintage data which is already available for management asset control purposes. The Board considers that it is still open to EPC to implement more simplified depreciation methods should management consider the costs of tracking retirements by vintage to no longer be a requirement for asset control purposes. The Board continues to be of the view that there are merits in moving to a simplified depreciation methodology and as such the Board directs EPC to continue to assess and report on the need to maintain the more complex system used for asset control purposes at its next GTA. 7.2 ELG Method

7.2.1 Synchronization of Annual Accruals with Accumulated Accruals The Board has reviewed the ELG calculation method used by Gannett Fleming (the GF ELG Method) to calculate the ELG annual depreciation and the ELG accrued depreciation as set out in Exhibits 98, 326-4 and 328-1. In particular, the Board has examined the issue of the synchronization of annual accruals with accumulated accruals. 46 • EUB Decision 2006-002 (January 13, 2006)



The Board notes that EPC did not address the synchronization issue in argument even though suggested by the Board in the Board’s argument outline.88 The CG submitted, in reply, that any reply from EPC on this matter should be limited to the issues raised in the arguments of others and should not be argument in chief. The Board agrees with the CG and will only place weight on the portion of EPC’s reply that responds to the issues raised in the arguments of other parties. The CG noted in argument that EPC collects a full-year of depreciation for new vintages despite the new vintages only being in rate base for half a year. However, the CG stated that any differences can be adjusted for in future depreciation studies or technical updates. EPC, in reply at page 39, provided an example (the Reply Example) of the appropriate method of depreciating a single asset with a service life of 10 years over a period of 11 test years (i.e. additions assumed to occur mid-year in the first year and retirements assumed to occur mid-year in the last year). EPC submitted that, although the Reply Example provided was based on a single asset, the evidence on the record demonstrates that the same theory applies when the ELG procedure is used respecting the calculation of annual depreciation accrual and accumulated depreciation for each of the equal life groups. The Board agrees with the Reply Example and considers this to be the appropriate standard to follow when calculating annual depreciation accrual and accumulated depreciation for each of the equal life groups. The Board has carefully examined the GF ELG Method (as illustrated in Exhibit DT 326-5) and concludes that the GF ELG Method does not agree with the Reply Example. The Board has made the following three findings respecting the GF ELG method:

• Finding #1: The GF ELG method collects a full year depreciation expense for new vintages despite the new vintages being in rate base for only one-half of one year.

• Finding #2: The GF ELG method ignores the retirements predicted to occur in the study

year when calculating the accumulated accrued depreciation at year-end for the study year.

• Finding #3: The GF ELG method introduces a mismatch by calculating mid-year rates

for each vintage and then applying these mid-year vintage rates to year-end vintage balances in order to arrive at the composite account depreciation rate.

The Board will provide reasons for each of the above three findings in the following paragraphs. With respect to Finding #1, the Board notes that EPC stated the following:

For purposes of the calculation, each vintage is divided into equal life groups arranged so that the midpoint of each one-year age interval coincides with the calculation date, e.g., December 31 in this case. This enables the calculation of annual accruals for a twelve-month period centered on the date of calculation. (Exhibit 98 Pg II-11) (emphasis added)

88 Board Letter dated September 15, 2005



The summation of annual accruals (column 7) for installations during 2003 is calculated on the basis of an in-service date at the midpoint of the year, i.e., June 30. Inasmuch as the overall calculation is centered on December 31, 2003, the first figure in column 7, for vintage 2003, equals all of the group annual accrual for the first equal life group plus the accruals for all of the subsequent equal life groups. (Exhibit 98 Pg II-13)

The Board agrees with the CG that EPC collects a full-year of depreciation for new vintages despite the fact that new vintages are only in rate base for one-half of a year as of the study date. This is demonstrated on Exhibit DT 326-5 wherein it can be observed that the GF ELG Method assumes that the entire 2003 vintage is installed on July 1, 2003 but a full year’s depreciation expense is taken on all 2003 vintage equal life groups so that the depreciation expense for the 2003 vintage extends a full year to June 30, 2004. The GF ELG Method has therefore loaded a full-year’s depreciation accrual (i.e. July 1, 2003 to June 30, 2004) on the 2003 vintage as of December 31, 2003. The one-half year mid-year convention is only employed at the time of retirement of each equal life group. The main difficulty with the GF ELG Method is the assumption that each vintage and its associated equal life groups are installed on July 1 with a full year of annual accrual taken in the installation year and one-half of an annual accrual in the retirement year whereas the Reply Example assumes an installation of July 1 (with only one-half of an annual accrual in the installation year) and a retirement on June 30 (with one-half of an annual accrual in the retirement year). With respect to Finding #2, the Board concludes that notwithstanding that the GF ELG Method has loaded a full-year’s depreciation accrual on the 2003 vintage as of December 31, 2003, the GF ELG Method has properly credited the accumulated depreciation with only one-half of the 2003 vintage accruals. However, the Board has observed a second order problem in that the GF ELG Method determines for each vintage the vintage theoretical accumulated depreciation factor as of December 31, 2003 by multiplying each vintage accrual rate by the age of that vintage as of December 31, 2003. The Board notes that these vintage accrual factors are applied to actual December 31, 2003 account plant balances to arrive at the composite year-end theoretical accumulated factor for each account. The Board considers that this method ignores the retirements that were predicted to occur for each ELG within the study year. For example the accumulated accrued factor for the 2003 vintage as of December 31, 2003 should be the 2003 vintage rate times the age less the first equal life group which is predicted to be retired as of December 31, 2003. This would result in an accumulated accrual factor of 0 for the first equal life group of 13.2% assumed to retire on December 31, 2003. The Board is satisfied that the GF ELG Method does not appear to introduce any material errors respecting this finding. However, the Board directs EPC to correct these minor distortions in the next Depreciation Study. With respect to Finding #3, the Board notes that the mid-year rate for each vintage is applied to the study year-end vintage balances in order to arrive at the composite account depreciation rate which tends to overstate the composite account depreciation rate. The Board considers that the mid-year rate for each vintage should be applied to the study year mid-year vintage balances in order to arrive at the composite mid-year account depreciation rate. The Board considers that an account depreciation rate calculated in this manner would then be consistent with the application of a mid-year composite account depreciation rate to the test mid-year account plant balances used to calculate the 2005 and 2006 depreciation expense shown on Schedule 7.1.2. The Board notes that the study year composite account depreciation rate and a composite account depreciation rate determined using forecast test year vintage data could also be different due to the changing weighting of vintage plant balances. However, the Board accepts this normal 48 • EUB Decision 2006-002 (January 13, 2006)


regulatory convention rather than attempting to update the composite account depreciation rate by employing the complexities of forecast vintage retirements using the assumed dispersion or other forecast vintage data. To overcome these concerns and to be consistent with the Reply Example, the Board considers that a better assumption would be to assume each vintage is divided into equal life groups arranged so that each one-year age interval coincides with a mid-year installation and a mid-year retirement date. This recognizes the mid-year convention by assuming that the installation year plant is installed over a one year period with an assumed July 1 installation date. Similarly, retirement year plant is retired over a one year period with an assumed June 30 retirement date. To recognize the possibility that there may be some plant installed in the installation year and retired in the same year, the first ELG is assumed to be installed on July 1, (mid-year) and then retired on December 31 of the same year (in this case 2003). All other equal life groups are assumed to be installed mid-year and retired on a mid-year basis as per the Reply example. The Board has done this and recast Exhibit DT 326-5 in Appendix 8 Worksheet 1 (the Board ELG method) and notes that the 10th ELG in the example 15R3 curve corresponds precisely with the EPC Reply example. The Board considers that a comparison of the Board ELG method (15R3) with the GF ELG method (15R3) clearly illustrates that the GF 2003 vintage accrual rate is overstated by a factor of approximately two although it is noted that subsequent vintage annual accrual rates are slightly understated. The Board notes that using the Board ELG method, the CG’s concern that “the theoretical accumulated accruals for the newest vintage, when compared to the theoretical depreciation expense, will result in an immediate mismatch in the first year” completely disappears. Instead, using the Board ELG method, there is synchronization between the annual accruals for the most recent vintage and the accumulated accruals for that same recent vintage. The Board considers that a comparison of the Board ELG method (15R3) with the GF ELG method (15R3) demonstrates that there is not a material problem when comparing the theoretical accrual factors by vintage. The Board, in Appendix 8, has also confirmed the above conclusions by correcting the GF 15R3 example (Exhibit 326-005) by moving the half year accrual from the end of the life of each ELG to the beginning to conform to a July 1 installation and a December 31, retirement basic assumption. This correction also confirms the Board’s earlier Finding #1 that the GF 2003 vintage accrual rate is overstated by a factor of approximately two. Accordingly, in Appendix 9 the Board has recalculated the ELG composite rate for the following accounts by dividing the 2003 vintage rate by two.

473.1 Wood Poles 474.1 Primary Conductor – Overhead 474.2 Secondary Conductor – Overhead 474.6 Switches – Overhead 476.1 Primary Cable – Underground 476.2 Secondary Cable – Underground 476.6 Switches – Underground 477.1 Transformers – Overhead



477.3 Transformers – Padmount

It was not necessary to recalculate Account 474.3 Fault Indicators – Overhead since this account did not have a 2003 vintage. The Board considers that this ELG correction provides a good approximation of the results that would be obtained by applying the Board ELG method to all vintages within the account. For the purposes of this Decision, the Board will not make any reductions for the minor distortions resulting from Findings #2 and # 3 above since the use of a correction factor of two for Finding #1 may slightly overstate the required reduction. The Board was not provided any of the back-up data for the calculation of the depreciation expense for General Accounts and is therefore unable to determine if the half year convention has been violated. The Board will, for the purposes of this Decision, accept EPC’s calculation of the General Accounts for 2005 and 2006. However, the Board directs EPC to implement the one-half year convention for the most recent vintage at the time of the next GTA. 7.2.2 ELG Data Requirements EPC stated that it had developed the costs for retirement transactions on an original cost basis for many decades, and had a complete database of reliable retirement transactions which proved to be accurate in the Gannett Fleming asset verification study.89

The CG noted that the data requirements for the ELG procedure are similar to those required for other depreciation procedures (e.g. average life group procedure). However, the CG also pointed out that the ELG procedure is more sensitive to data problems and the result on the depreciation rate may be magnified because of data problems. The CG considered that, at this point, there are no obvious data problems evident for EPC. The Board agrees with parties that EPC’s data is satisfactory for carrying out both ELG and other simplified methods of depreciation. 7.3 Simplified Life Estimation Methods

7.3.1 General EPC’s Depreciation witness, Mr. Kennedy, testified that conversion to simplistic methods, such as amortization accounting, will lead to significant future revenue requirement and inter-generational equity concerns. Mr. Kennedy stated that the mass property characteristics of electric distribution plant do not have the service life attributes conducive to amortization accounting. Furthermore, Mr. Kennedy pointed out that the use of amortization accounting for all electric distribution plant will strand the recovery of investment capital related to plant that retires early in its life until the expiration of the amortization period at the burden of those ratepayers using the system in periods following the expiration of the amortization period. In turn, this will significantly increase the business risk of EPC. The Board notes that Mr. Kennedy, at the Board’s request, provided his view on the appropriateness of the use of a simplified method for each of EPC’s accounts. The Board generally agrees with the following criteria provided by Mr. Kennedy:

89 The Asset Verification Project (AVP) performed in mid-2003 by Gannett Fleming validated the 2003 opening plant balances with an accuracy of 99%.



So you have a huge volume of small- dollar assets with very tight retirement dispersion, and often with a relatively shorter life, which is causing the tightness of the retirement dispersion, amortization makes a lot of sense. And I totally agree with amortization in the circumstance of those types of accounts. Where I disagree with amortization is in the circumstance where you have, perhaps, a low-mode curve and a life of, say, 60 years, when you can have retirements in that low-mode curve of, in the first 5 and 10 percent of the average service life, and retirements as late as, perhaps, 200 or 250 percent of the average service life. In other words, you have a very wide dispersion. In those circumstances are where I become concerned with the generation of equity of moving to a square curve. If you where sic (were) to say to me we should use amortization accounting in certain mass property accounts that have the characteristics of a very tight retirement dispersion and, you know, a large volume of small dollar –dollar assets, then I could be convinced there is some accounts, and not only convinced, I think there is some accounts that could be subject to that type of accounting treatment. I’m just not convinced that it’s the right treatment for all electric assets or gas assets for that matter.90

However, the Board would also add that the simplified method can be applied for accounts that have not demonstrated any material retirement dispersion. The Board is not persuaded that a more complex ELG method provides any additional accuracy for many of EPC’s asset accounts due to the near impossible chore of selecting a retirement dispersion that accurately predicts future retirements when there is a lack of company specific historical data that would verify such a selection. The Board considers that equal inter-generational concerns can also result with the use of speculative retirement dispersion curves not supported by historical data and notes that in many cases the use of an unsupported retirement dispersion can result in the premature recovery of investment capital related to plant that in actual fact does not retire early in its life placing an extra burden on those ratepayers using the system in periods prior to the amortization period. For the same reason the Board rejects Mr. Kennedy’s assertion that a simplified depreciation system would necessarily increase the business risk of EPC. In fact, it could reduce the business risk if there is a premature recovery of investment. 7.3.2 Distribution Accounts The Board has reviewed the appropriateness of applying a simplified method to EPC’s Distribution Accounts. Mr. Kennedy, in responding to which accounts may be suitable for a more simplified method, classified his response,91 as “good candidates”, “less appropriate” and “not appropriate” as shown in Column A of the following table.

90 Exhibit 305 91 Exhibit 305



Table 4. Appropriateness of a Simplified Depreciation Method

Asset Account

Column A Appropriateness of Simplified Method

Per View of Gannett Fleming

Column B Appropriateness of Simplified Method

Per View of The Board

EPC Distribution 471.1 Land Rights Good Candidate Good Candidate 472.1 Buildings Less Appropriate Fine for Now 472.2 Site Development Good Candidate Good Candidate 473.1 Wood Poles Not Appropriate Not Appropriate 473.2 Overhead Transformers Good Candidate Good Candidate 473.9 Insulators Not Appropriate Fine for Now 474.1 Primary Conductor – Overhead Not Appropriate Not Appropriate 474.2 Secondary Conductor – Overhead Not Appropriate Not Appropriate 474.3 Fault Indicators – Overhead Not Appropriate Not Appropriate 474.6 Switches – Overhead Not Appropriate Not Appropriate 475.1 Underground Conduit Not Appropriate Fine for Now 475.2 Transformer Pads Not Appropriate Fine for Now 475.3 Pull Boxes Good Candidate Good Candidate 475.5 Manholes Good Candidate Good Candidate 476.1 Primary Cable – Underground Not Appropriate Not Appropriate 476.2 Secondary Cable – Underground Less Appropriate Not Appropriate 476.6 Switches – Underground Not Appropriate Not Appropriate 477.1 Transformers – Overhead Not Appropriate Not Appropriate 477.3 Transformers – Padmount Not Appropriate Not Appropriate 477.4 Transformers – Minipad Not Appropriate Fine for Now 477.5 Transformers – Substations Not Appropriate Fine for Now 477.6 Switchgear Not Appropriate Fine for Now 477.7 Structures Not Appropriate Fine for Now 477.8 Protection Not Appropriate Fine for Now 478.1 Telecontrol Less Appropriate Fine for Now 478.2 Supervisory Equipment Good Candidate Good Candidate 479 Meters Good Candidate Good Candidate

The Board has reviewed Mr. Kennedy’s life table analysis for each of the Distribution Accounts and considers that the simplified method should be applied for accounts that have not demonstrated any material retirement dispersion. The Board considers that retirement dispersion should only be introduced when there is extensive and meaningful retirement activity supporting the dispersion model. The Board’s assessment of the appropriateness of the simplified method for the Distribution Accounts is shown in Column B of the above table. The Board considers that the simplified method is not appropriate for the 10 highlighted Distribution Accounts in the above table. 52 • EUB Decision 2006-002 (January 13, 2006)


Accordingly, the Board will accept the ELG method of analysis for the following 10 Distribution Accounts: Table 5. Accounts Accepted for ELG Analysis Method

Asset Account

Column A Appropriateness of Simplified Method

Per View of Gannet Fleming

Column B Appropriateness of Simplified Method

Per View of The Board

473.1 Wood Poles Not Appropriate Not Appropriate 474.1 Primary Conductor – Overhead Not Appropriate Not Appropriate 474.2 Secondary Conductor – Overhead Not Appropriate Not Appropriate 474.3 Fault Indicators – Overhead Not Appropriate Not Appropriate 474.6 Switches – Overhead Not Appropriate Not Appropriate 476.1 Primary Cable – Underground Not Appropriate Not Appropriate 476.2 Secondary Cable – Underground Less Appropriate Not Appropriate 476.6 Switches – Underground Not Appropriate Not Appropriate 477.1 Transformers – Overhead Not Appropriate Not Appropriate 477.3 Transformers – Padmount Not Appropriate Not Appropriate

For all other Distribution Accounts the Board considers it appropriate to introduce a more simplified system of depreciation. 7.3.3 Network Accounts The Board has reviewed the appropriateness of applying a simplified method to EPC’s Network Accounts. With respect to the Network Accounts, EPC stated:

The survivor curve estimates for ENMAX’s electric network asset accounts were based primarily on the judgment of Gannett Fleming based on the operational staff interviews and the extensive knowledge of these assets gained from an Asset Verification Project completed in 2003. Sufficient retirement experience did not exist in these accounts to conduct a meaningful asset mortality study. The network asset system of ENMAX is unique and is not comparable to any other network system within Alberta. As such, extensive interviews were conducted with operational staff. Gannett Fleming also became familiar with these assets in 2003 as part of the Asset Verification Project. During the Asset Verification Project, the history of all installations was reviewed with operational, drafting and accounting staff. Additionally, the average service life indications from similar assets in the electric distribution accounts were also considered by Gannett Fleming.92

Again, the Board considers that a retirement dispersion should only be introduced when there is clear extensive and meaningful retirement activity. In these circumstances, the Board considers the simplified method to be appropriate for the present time for all network accounts.

92 Exhibit 098 – Depreciation Study, pp. 11-8



The Board, in Appendix 9, has calculated the approved 2005-2006 depreciation rates for all accounts for which the simplified method is appropriate. 7.3.4 General Accounts EPC noted that the depreciation rates applied to General Accounts were established in the study undertaken by Gannett Fleming in 2002 for EPC’s transmission filing with the DOE.93

EPC submitted that it had received a depreciation study for General Plant that indicates a higher depreciation rate than that which is included in the Application. However, EPC proposed to delay implementation of higher depreciation rates for both transmission and distribution until 2007, as the General Accounts assets are not divisible between transmission and distribution. The Board notes that Exhibit 99 demonstrates that a simplified method was used for all General Accounts except the South Service Center (Account 482.1) and Vehicles (Account 484). These latter two accounts make up less than 10% of the General Accounts depreciation. Accordingly, the Board will accept the EPC depreciation calculations for General Accounts for the purposes of this Decision for 2005 and 2006. The Board will review the appropriateness of applying the ELG method to the South Service Center (Account 482.1) and Vehicles (Account 484) at the time of review of the most recent General Plant depreciation study. For all of the above reasons, the Board directs EPC to use the Board approved depreciation rates, as set out in Appendix 9, in EPC’s refiling. 7.4 Treatment of Net Salvage

7.4.1 General Mr. Kennedy submitted that the recording of retirement costs to the replacement costs of the replacement asset is not appropriate, does not conform to generally accepted accounting principles (GAAP)94 and will result in no significant cost savings. Mr. Kennedy recommended that EPC not implement any change from the long-standing and widely accepted practice of charging costs of retirement to the accumulated depreciation account.95 Mr. Kennedy further submitted that depreciation studies will still be required for GAAP.96 The Board notes EPC’s long-standing and widely accepted practice of charging costs of retirement to accumulated depreciation.97 The Board accepts EPC’s view that the recording of retirement costs to the replacement costs of the replacement asset may not conform to GAAP98 although the Board notes that EPCOR follows this practice.99 The Board does not consider the practice of charging costs of retirement to accumulated depreciation to be a regulatory requirement and again considers that it is still open to EPC to implement the practice of recording retirement costs to the replacement costs of the replacement

93 See Exhibit 99 94 Exhibit 162, response to BR.EPC-32 95 Exhibit 100, pp. 13-14 96 Exhibit 100, p. 4; exhibit 162, responses to BR.EPC-32(b) 97 Exhibit 100, pp. 13-14 98 Exhibit 162, response to BR.EPC-32

99 EPC DT Decision 2004-066



asset should management consider the costs of tracking salvage by vintage no longer a requirement for asset control purposes. 7.4.2 Salvage Data Requirements The Board considers that EPC’s decision not to roll over cost of removal places an additional burden on separating and recording the cost of removal by vintage. The Board directs EPC to track the additional costs incurred in data requirements to track the net salvage by vintage within each account. Under the EPC approach, all forecasting errors respecting net salvage are rolled in to the accrued depreciation and therefore affect the accrued depreciation true up amount. The Board considers that this raises the question of whether salvage should be separated in terms of reserve and accruals because of the different natures of the estimates. (i.e. life versus salvage estimates) in order to avoid the potential for distortion to depreciation calculations. Accordingly, the Board directs EPC to study the feasibility of separating the salvage from annual accruals and the accrued depreciation in order to assist in the accurate monitoring of the accumulated depreciation by account and report on EPC’s investigation at the time of the next GTA. For further clarity, the Board notes that the sum of the “salvage” reserve and the “service life” reserve would be equal to the traditional accumulated depreciation reserve. 8 RETURN ON RATE BASE

8.1 Overview EPC forecast its total return on Rate Base for Distribution to be $35.3 million for 2005 and $37.9 million for 2006. EPC stated that in preparing this forecast EPC has complied with EUB Order U2004-423100 and EUB Decision 2004-066 with respect to return on rate base and EUB Decision 2004-052101 with respect to capital structure. The CG stated that issues related to return and capital structure have been addressed as part of the Generic Cost of Capital proceeding, and as such had no comment on this issue. 8.2 Construction Funds Collected From Customers (CFCFC) EPC noted that on November 8, 2004, using the authority granted to it under section 138(3) of the EUA, the City of Calgary (Calgary) imposed an amount of $0.00171/kWh in respect of EPC’s electric distribution system effective November 1, 2004, and an amount of $0.00229/kWh effective January 1, 2005 (Equity Rider or CFCFC).102 EPC submitted that the manner in which EPC obtains equity is no different from the manner in which other companies obtain equity. In the event that EPC requires an infusion of equity, it would make a request to its shareholder, ENMAX. Since the Equity Rider was implemented, 100 Order U2004-423 – Board Initiated Proceeding - 2005 Return on Equity, dated November 30, 2004 101 Decision 2005-052 – Generic Cost of Capital AltaGas Utilities Inc. AltaLink Management Ltd ATCO Electric

Ltd. (Distribution) ATCO Electric Ltd. (Transmission) ATCO Gas ATCO Pipelines ENMAX Power Corporation (Distribution) EPCOR Distribution Inc. EPCOR Transmission Inc. FortisAlberta (formerly Aquila Networks) NOVA Gas Transmission Ltd., dated July 2, 2004

102 Exhibit 164, response to D410G.EPC-4(b) EUB Decision 2006-002 (January 13, 2006) • 55

http://www.eub.gov.ab.ca/bbs/documents/orders/utilities/2004/u2004-423.pdf




EPC has not requested any additional equity from ENMAX,103 and EPC has therefore not received any funds that have been sourced, directly or indirectly, from the Equity Rider. However, even if it had, EPC submitted that this fact would be irrelevant from a regulatory perspective. The relevant fact, from a regulatory perspective, would be that EPC received an injection of equity from its shareholder, ENMAX. AE submitted that while the Board may not approve the amounts collected via municipal surcharge, it is entirely appropriate for the Board to consider the impact of the availability of, and reliance by EPC on, this type of vehicle to raise funds. This is particularly the case given the objectives of the EUA, including prevention of unfair advantage of government-owned participants (section 5(c)). AE submitted that the manner in which funding through this mechanism impacts the applied-for revenue requirement falls within the Board's jurisdiction. The Calgary Industrial Group (CIG) argued that EPC should not be allowed to earn rates of return on ratepayer funded equity that are unjustified in light of the financial circumstances and business risk of the regulated business it carries out, and which are in excess of the rate of return that is suggested by the formula set in the Generic Cost of Capital Decision (GCOC). In support of this, CIG submitted that customer funded equity is no cost capital to EPC. In addition, capital attraction signals that flow from the three principles of financial integrity, capital attraction and comparable investment that underlie the GCOC Decision no longer apply to EPC because EPC does not need to attract capital in public markets. EPC submitted that it is not appropriate to deal with the CIG’s recommendations in this proceeding. If any party wishes to request an amendment or alteration of the common return on equity or capital structure established in Decision 2004-052 a formal application should be made. Calgary submitted that while the stated purpose of the collected amounts may be for equity investment in the electric distribution system, the amounts, at the time they are collected, are not equity of EPC. The Board will present its findings respecting CFCFC under the following headings:

1) What is the purpose of the funds collected by way of the Equity Riders? 2) Given the purpose of the CFCFC, does the Board have the jurisdiction to determine the

impact that the CFCFC has on the EPC Revenue Requirement? 3) What process is followed to move the CFCFC from electric customers to financing a

portion of the capital expenditures for EPC Distribution? 4) Is the question of the amount of CFCFC collected from customers at issue? 5) What is the proper regulatory treatment of CFCFC? 6) Summary of the Results of Board Findings.

1) What is the purpose of the funds collected by way of the Equity Rider? The Board considers it relevant to determine the purpose of the funds collected from electric customers by Calgary by way of the municipal Equity Rider in order to determine the proper treatment of these funds and what effect, if any, these funds have on the EPC revenue requirement. The Board notes the following evidence that deals with purpose:

103 Transcript Volume 3, p. 477, line 8 to p.-478, line:6



a) Minutes of a Meeting of Calgary City Council

City Council approval is required for ENMAX to bill its customers in the form of a municipal tariff relating to equity funding for its capital requirements. To comply with a recent EUB ruling that equity funding can no longer be collected within its customers’ rates, ENMAX is proposing to collect the amount allowed by the EUB through a separate line item on the bill. (emphasis added) Gas, Power and Telecommunications Committee recommends that Council: 1. Approves creating a municipal tariff equivalent to the amount by which ENMAX’s rates were reduced by the EUB, to be collected as a line item on the utility bill, for ENMAX’s equity funding requirements for 2004. The tariff applied will be 0.171 cents/kWh applied to energy delivered through ENMAX “DT” tariff, for a 12 month period starting in November 2004 and would generate $14.2 million of equity funding. 2. Approves creating a municipal tariff equivalent to the amount by which ENMAX’s rates were reduced by the EUB, to be collected as a line item on the utility bill, to collect ENMAX’s equity funding requirements for 2005. The tariff applied will be 0.229 cents/kWh applied to energy delivered through ENMAX “DT” tariff, for the period 2005 January 1 through 2005 December 31 and would generate $19 million of equity funding.104 (emphasis added)

b) Regulated Utility Capital Investments Reserve105

Purpose: To collect and accumulate funds for future Regulated Utility Capital Investments. Funds are collected under a Municipal Funding Rider from utility customers and remitted to The City of Calgary. Funds are used to finance future regulated utility capital investments. (emphasis added)

c) The disclosure to each electric customer on each customer invoice respecting the

Equity Rider which states “This surcharge pays for Electricity Infrastructure”. (emphasis added)106

From the above, the Board finds that the record is clear that the stated purpose of the amounts collected from customers is for investment in EPC’s electric distribution system. 2) Given the purpose of the CFCFC, does the Board have the jurisdiction to assess the

impact that the CFCFC has on the EPC Revenue Requirement? The Board will consider the following submissions from parties that deal with jurisdiction and whether the Board should determine the impact of the CFCFC funds on the EPC Revenue Requirement:

• EPC considers that the Board should regard these funds as part of the owner’s equity invested in EPC and should therefore attract the full equity return as allowed by the GCOC. EPC also allows that the benefit of the timing of the collection of funds by EPC

104 Exhibit DT 164 D410G.EPC-4 105 Attachment to Exhibit 287, an undertaking response to the Chairman’s request for information on the municipal

surcharge and how EPC requests additional equity 106 ENMAX letter dated November 22, 2004



and the remittance to the City of Calgary should be considered by the Board in the determination of EPC’s necessary working capital.107

• AE submitted, in argument, that it is entirely appropriate for the Board to consider the

impact of the availability of, and reliance by EPC on, this type of vehicle to raise funds.

• CIG submitted, in reply argument, that the Board’s jurisdiction over rate of return issues is not in doubt and that section 122 of the EUA provides for the owner of an electric utility to recover its costs and expenses associated with capital related to the owner’s investment in the electric utility. The CIG submitted that EPC’s owner raises no-cost equity from customers regardless of whether ENMAX Corporation or Calgary is the “owner”.

• Calgary, in reply argument, submitted that no equity of EPC is collected from ratepayers.

EPC is collecting the Equity Rider which is an amount imposed by Calgary. Calgary noted that, while the stated purpose of the collected amounts may be for equity investment in the electric distribution system, the amounts at the time they are collected are not equity of EPC.

EPC, CIG and AE all recognize the ability of the Board to assess what impact the CFCFC may have on EPC’s revenue requirement. The Board does not find merit in Calgary’s position. The Board has found above that the intention is that all funds collected by the Equity Rider will find its way back to financing the EPC Distribution Capital Expenditure Program. Therefore, the Board dismisses Calgary’s argument that the Board should not have regard to the collected amounts until such time as the funds are received by EPC from Calgary via ENMAX. The Board finds that there is no evidence to suggest that the collections will not be used for funding electric infrastructure. The Board is of the view that the important issue is the timing of the collection of CFCFC funds, not the timing of when those funds are received by EPC from Calgary via ENMAX. This is consistent with how customer contributions in aid of construction are typically treated by the Board, in that the customer contributions are incorporated in the revenue requirement on a forecast basis, not when the funds are actually received by the utility. As found above, the Board considers that the CFCFC will ultimately be used to finance a portion of EPC’s rate base. The Equity Rider collects (under sec 138(3) of the EUA) funds for future regulated utility capital investments, unlike, for example, the Local Access Fee imposed by the City of Calgary (under sec 138(3)) to collect franchise fees which are not regulated by the Board and have no impact on EPC's revenue requirement. The Board considers that it has no jurisdiction respecting the level of funds collected pursuant to section 138(3); however, section 122 of the EUA requires the Board to have regard to the costs and expenses associated with the owner’s investment in the electric utility. Given that Equity Rider funds will be used to finance a portion of EPC’s rate base and that EPC seeks to earn a return on these funds (hence forming part of EPC’s costs and expenses), the Board concludes that it does possess the jurisdiction to assess the impact of these funds on EPC’s revenue requirement.

107 Exhibit 287, Undertaking Response from EPC (Mr. Thompson) regarding Funding Rider and Calgary’s Regulated Utility Capital Funding Reserve



3) What process is followed to move the CFCFC from electric customers to financing a portion of the capital expenditures for EPC Distribution?

Having determined that the purpose of the amounts collected from customers is for investment in EPC’s electric distribution system, and that it is within the Board’s jurisdiction to assess the impact of the CFCFC on EPC’s revenue requirement, the Board will now examine how EPC obtains the funds to finance capital expenditures. The Board accepts that EPC invoices retailers for the Equity Rider, and the retailers then bill end use customers. EPC remits the amount collected from retailers to Calgary on the 15th day of the month following the month in which the invoice was issued to retailers.108 Calgary deposits the funds in its Regulated Utility Capital Investments Reserve.109 The process used to move the funds from the Regulated Utility Capital Investments Reserve to EPC was described by EPC in the attachment to Exhibit 287:110

Conditions: Funds will be disbursed once a year in conjunction with The City of Calgary annual capital budget review process as supported by a business case outlining details for the specific use of funds requested. Evaluation of funding sources other than equity sources will need to be considered before approval. Restrictions: Disbursements from the fund to ENMAX will require approval by the ENMAX Board of Directors, endorsement by the ENMAX Shareholder and approval by City Council. Any other disbursements require City Council approval. The amount disbursed from the reserve will not exceed the balance less any amount receivable at December 31 of the previous year, except for the first year where the initial amount disbursed would not exceed the amount accumulated in the reserve at 2005 June 30 less any amount receivable. Only funds accumulated in the reserve will eventually be accessible for regulated utility capital investments.

The Board also considers the following excerpt from the transcript of the proceedings to be instructive:

Q Okay. Are you suggesting, then, some possibility that ENMAX Power Corporation will not receive the funds that are collected under the municipal surcharge in respect of equity funding? A MR. THOMPSON: Not at all, sir. In fact, all I'm suggesting is that the process required is that we need to identify a need and to make the request. We're still working on the evaluation of whether there's a need at this point. That, to me, is completely distinct from whether we'll get the money -- that's a decision that City council will need to make, sir. But I have no reason to believe that we will not have the funds returned to us for the infrastructure that we're building in the city of Calgary.111 (emphasis added)

The Board accepts EPC’s evidence that there is no reason to believe that EPC Distribution will not have all funds collected by way of the Equity Rider returned to EPC to finance a portion of the construction program.

108 EPC Argument, p. 54 109 Exhibit 287, Undertaking Response from EPC (Mr. Thompson) regarding Funding Rider and Calgary’s

Regulated Utility Capital Funding Reserve 110 Exhibit 287, Undertaking Response from EPC (Mr. Thompson) regarding Funding Rider and Calgary’s

Regulated Utility Capital Funding Reserve 111 Transcript Volume 2, pp. 415 to 416



The Board also considers that the clear disclosure to customers of the purpose of the collections provides reasonable assurance that the funds will not be used for some purpose other than the stated purpose of funding a portion of the EPC distribution construction program. In fulfilling its jurisdictional responsibilities, the Board must be guided by the evidence. EPC’s evidence, on the one hand, is that these Equity Rider amounts are “funds collected from customers to finance construction.”112 On the other hand, EPC claims that flowing these funds through the Calgary treasury transforms them into “equity funds supplied by the owner”113. The Board finds these positions to be incompatible and does not find EPC’s claim to be acceptable. Specifically, the Board cannot accept that “funds collected from customers to finance construction” transform to, or recharacterize as, “equity funds supplied by the owner” simply by the process of flowing through Calgary’s Regulated Utility Capital Investments Reserve. The Board finds no merit in EPC’s position from a revenue requirement perspective since the re-characterization of “funds collected from customers to finance construction” as “equity funds supplied by the owner” results in the customer having to pay a return on his/her own money as well as providing for a double recovery of these amounts, .i.e. the initial contribution and the ongoing depreciation of the portion of the capital program financed by these funds. 4) Is the question of the amount of CFCFC collected from customers a issue? t

The Board considers that the record is clear that $14.2 million is forecast to be collected by the 2004 Rider and $19.0 million is forecast to be collected by the 2005 Rider.114 The Board has verified these amounts using the $0.00171/kWh 2004 Rider and the $0.00229/kWh 2005 Rider applied against the forecast energy delivered as approved by the Board in this Decision.115 The Board accepts the above amounts as reasonable forecasts of CFCFC to be collected from customers over the period November 2004 to December 2005. The Board notes that the total of amounts collected are forecast to be used solely by EPC Distribution and that no amounts have been collected respecting EPC Transmission.116

5) What is the proper regulatory treatment of CFCFC? EPC’s position is that notwithstanding the fact that the funds collected by the Equity Rider were provided by electric customers, these funds should be regarded as deemed equity provided by the owner of the EPC Distribution system (i.e. Calgary via ENMAX) to finance a portion of the EPC Distribution Capital Expenditure Program. Clearly, EPC’s position and interpretation is not shared by CIG who urges the Board to treat their “funds collected from customers to finance construction” as no-cost capital rather than “equity funds supplied by the owner”.117

112 Attachment to Exhibit 287; purpose of Regulated Utility Capital Investments Reserve 113 EPC Argument p 54 114 Exhibit 164 D410G.EPC-4 115 Board approved 2005 energy forecast of 8286 GWh * $0.00171/kW.h = $14.2 million for 2004 (The Board has

assumed that energy forecast for the period Nov 1, 2004 to October 31, 2005 is approximately equal to the 2005 energy forecast of 8286 GWh) and 8286 GWh * $0.00229/kWh = $19.0 million for 2005.

116 Transcript Volume 6, pp. 1359 to 1366

117 CIG Argument, pp. 5-10



With respect to proper regulatory treatment of these funds, the Board is governed by section 122 of the EUA :

122(1) When considering a tariff application, the Board must have regard for the principle that a tariff approved by it must provide the owner of an electric utility with a reasonable opportunity to recover (a) the costs and expenses associated with capital related to the owner’s investment in the electric utility, including …..

(iv) a fair return on the equity of shareholders of the electric utility as it relates to the investment, and (v) taxes associated with the investment,

if the costs and expenses are prudent and if, in the Board’s opinion, they provide an appropriate composition of debt and equity for the investment

The Board agrees with EPC that the equity return approach approved by the Board in the GCOC Decision 2004-052 as applied to rate base should not be disturbed respecting the “owner’s investment in the electric utility”. In other words, the GCOC should be applied to EPC’s rate base. This is consistent with the Board’s findings in Decision 2004-066 wherein the Board suggested a regulatory method of mitigating concerns respecting double recovery of investment and unfair return on investment:

Treating the equity funding provided by customers as “no-cost capital” could mitigate the Board’s concerns about double recovery of investment and unfair return on investment. Instead of being considered as “equity funding”, in these circumstances the funds would be considered as a customer contribution to the owner’s capital investment program. However, in light of the Board’s earlier conclusions respecting its jurisdiction under section 122 of the EUA and the other reasons for rejecting the proposal as unreasonable, it is unnecessary for the Board to make a determination about how to appropriately treat equity funding in the circumstances.118 (emphasis added)

As the Board found above, the amounts collected from customers by way of the Equity Rider do not form part of the “owner’s investment in the electric utility”. Rather, the Board found that these amounts are collected from customers for purposes of financing EPC’s capital investment program and that, based on the un-contradicted evidence in the proceeding, all funds collected from customers would ultimately be received by EPC for this purpose. The conventional regulatory treatment for funds provided by customers (and not by owners) is to reduce the rate base by the amount of the contribution to construction and to amortize the contributed funds at the same depreciation rate as the capital. This regulatory treatment ensures that the owner is only compensated for the reduced rate base which equates to the investment made by the owner. Further, this approach is consistent with the mitigation suggested by the Board in Decision 2004-066.

118 Decision 2004-066, p. 241







Calgary noted the Board stated in the GCOC Decision that “In the Board's view, having established a fair return, the Board need not concern itself with the particular internal policies to which a utility may be subject regarding distributions of dividends or acquisition of equity”.119

In the GCOC Decision, the Board also stated that it “does not agree with ENMAX that its fixed dividend or lack of access to public equity markets raises its risks in the circumstances.”120 While the Board accepts that it need not concern itself with particular internal policies regarding the methods of acquiring equity, the Board’s view is that it must be satisfied that the established fair return properly reflects the costs of equity instruments actually acquired. If the CFCFC were to be treated as owner’s equity there may be cause for a review of the GCOC Decision as it applies to EPC in the context of the determination of a fair return. The Board agrees with AE that such a review may raise issues respecting the objectives of section 5(c) of the EUA. The Board also agrees with EPC that any proposal to amend or alter the common return on equity or capital structure established in Decision 2004-052 should take the form of a formal application. The Board considers that the CFCFC should be treated in the same manner as other forms of contributions made by customers towards capital expenditures (e.g. contributions in aid of construction). In the Board’s view, this method provides the owner with a reasonable opportunity to recover “the costs and expenses associated with capital related to the owner’s investment” and a “fair return on the equity” (equal to the GCOC) for shareholders of the electric utility as it relates to the investment. 6) Summary of the Results of Board Findings The Board, in Appendix 10, has set out the impact on the EPC Revenue Requirement of treating the funds collected from customers pursuant to the Equity Rider as a contribution to construction including the amortization of the contributed funds at the estimated composite EPC depreciation rate (See Appendix 9). The Board has followed the mid-year rule (since the CFCFC will have been collected over the period November 2004 to December 2005) and only included one-half of the $14.2 million (i.e. $7.1 million) CFCFC collected in respect of 2004 and one half of the $19.0 million ($9.5 million) CFCFC collected in respect of 2005 in the determination of return and amortization for 2005. The Board has used the full CFCFC amount of $33.2 for 2006, since this amount is forecast to be collected by January 1, 2006. For all of the above reasons, the Board directs EPC to treat CFCFC as a reduction to rate base and amortize the CFCFC at the composite EPC depreciation rate (using the format of Appendix 10) in its refiling. The Board directs EPC to follow the mid-year rule and only include one-half of the $14.2 million (i.e. $7.1 million) CFCFC (collected in respect of 2004) and one half of the $19.0 million ($9.5 million) CFCFC (collected in respect of 2005) for the test year 2005 and the full CFCFC amount of $33.2 for the test year 2006 in determining the CFCFC reduction to rate base. The Board further directs EPC to use the capital structure, cost of debt and cost of equity for 2005 and 2006 approved in the following sections of this Decision for the remaining rate base after the CFCFC reduction. The Board further directs EPC to use the refiled composite depreciation rate for 2005 and 2006 to determine the amortization of the CFCFC.

119 Decision 2004-052, p. 52

120 Decision 2004-052, p. 52




The Board considers it open to EPC, in its refiling, to request approval to revise the debt financing requirements shown on Schedule 8 to the extent necessary to be consistent with the GCOC deemed 61% debt and 39% equity GCOC capital structure as result of the Board’s findings respecting CFCFC. The Board does not have any evidence respecting whether a 2006 equity funding rider will be implemented by Calgary in the 2006 test year. Should Calgary require EPC to collect a 2006 equity funding rider in 2006, the Board directs that one-half of the 2006 actual amount actually collected through the 2006 equity funding rider be multiplied by the sum of the Board approved 2006 composite return of 6.743% and the refiled Board approved 2006 composite depreciation rate and returned to customers by way of a temporary rate reduction rider in 2007. 8.3 Capital Structure EPC stated that its business includes both regulated transmission assets and regulated distribution assets, and that the Board has established the deemed capital structure for EPC’s distribution business at 61% debt and 39% equity through EUB Decision 2004-052. The Board agrees with EPC that its deemed capital structure as determined in Decision 2004-052 continues to apply. The Board therefore approves EPC’s capital structure as applied for. 8.4 Cost of Debt EPC stated that it has forecast its average cost of long-term debt to be 5.609% for 2005 and 5.344% for 2006, and that these forecasts reflect the average cost of all existing EPC long-term debt issued to the date of the Application, and new debt issued in 2005 and forecast to be issued during 2006. EPC stated that all debt issued by EPC to December 2004 has been financed indirectly through the ACFA under legislated arrangements it has with Calgary, and that cash proceeds from these ACFA debt issues flow from Calgary to ENMAX in accordance with contractual arrangements between Calgary and ENMAX, and further flow to EPC in accordance with contractual arrangements between ENMAX and EPC. EPC noted that ACFA debt issues are guaranteed by the Province of Alberta and are rated AAA by the Dominion Bond Rating Service (DBRS), and thus ACFA is able to borrow funds at attractive interest rates in the debt capital markets. EPC stated that Calgary adds a 0.25% loan guarantee and administration charge to the interest rate when it lends these funds to ENMAX, and that ENMAX in turn lends these funds to EPC with no additional charges. EPC stated that the forecast interest rate for 2005 and 2006 debt issues is based on the ten year Government of Canada (GOC) bond rate of 5.05%, as reported by the EUB in U2004-423, adjusted for the historical spread between the benchmark GOC rate and ACFA’s lending rate, and Calgary’s loan guarantee and administration fee. For 2005 and 2006, EPC forecast a rate of 5.550% for new long-term debt instruments for 2005 and 2006.121

121 Exhibit 003, Section 8.4, p. 77 of 80





The CG noted that although EPC indicates it plans to issue new LTD on September 1, 2005, at a rate of 4.186%,122 which would result in reductions to the 2005 and 2006 revenue requirements of $0.5 million and $0.9 million, respectively, it does not plan to update its 2006 cost of debt. EPC cites two reasons for not changing the 2006 rate for new debt as being, first of all, that EPC stated it does not have any better information for 2006 as “it’s equally as probable that the rate is going to go up as it's going to go down. So for me the 5.55 is a reasonable number.”,123 and secondly, it is EPC’s understanding that the Board has “requested that utilities use the actual embedded cost of debt as the debt is issued.”124 The CG does not share EPC’s view the Board has requested utilities to use the actual embedded cost of debt as it is issued, as this approach would entail the use of a deferral account for new debt issues and the Board has not approved the use of deferral accounts to true up forecast to actual costs of new debt issues. The CG submitted that where actual information is available at the time of the hearing, and makes a significant impact on the cost forecast, it should be taken into account by the Board in determining the Revenue Requirement. The CG stated that using the best evidence available at the time of the hearing,125 it would appear reasonable to find the long-term debt rate has decreased since the time the Application was filed, and that since EPC has revised its Application to reflect the new lower rate for the 2005 issue, and considering the evidence rates could go either up or down for 2006, the CG submitted the rate for forecast 2006 debt instrument should also be set at 4.186%. The Board notes that EPC has modified its 2005 and 2006 revenue requirements to reflect the new lower rate for the 2005 issue. With respect to the 2006 issue, the Board is in agreement with EPC that the rate for the 2006 issue could be higher or lower than the original forecast. The Board does not consider it appropriate for the 2006 issue to be revised lower as suggested by the CG because of this equal probability of the 2006 rate being higher or lower. The Board therefore approves EPC’s 2005 embedded cost of debt as revised126 by the lower rate for the 2005 issue, and EPC’s 2006 embedded cost of debt as revised127 by the lower rate for the 2005 issue. Further, the Board notes that CG originally questioned EPC’s use of short term debt, but withdrew its objection as more information on EPC’s approach was put forth during the proceeding that EPC was only using short term debt as a bridging mechanism. The Board is in agreement with the CG that short term debt need not be included in the cost of debt calculation. 8.5 Cost of Equity EPC stated that it has incorporated EUB Order U2004-423 to use a rate of return on common equity of 9.50% in this application for 2005 and 2006.

122 Transcript Volume 2, p. 394 - Updates to its Application were filed in Exhibits 232, 233 and 235 reflecting this

revised rate and reducing the 2005 embedded cost of debt from 5.777% to 5.609%, down 168 basis points; Exhibit 67, Sch. 8.2.3.

123 Transcript Volume 2, p. 399 124 Transcript Volume 2, p. 399 125 CG Argument, p. 105 126 Exhibit 246 Revised August 29, 2005

127 Exhibit 246 Revised August 29, 2005




The Board agrees with EPC that its rate of return on common equity for 2005 is 9.50%, per EUB Order U2004-423. The Board therefore approves EPC’s 2005 rate of return on common equity as applied for. The Board does not consider that Order U2004-423 applies to the 2006 rate of return on common equity, since that order was only with respect to 2005. While at the time EPC filed its application, Order 2004-423 would have been the best information on which to base its forecast, following the hearing, Order U2005-410,128 dated November 22, 2005 was issued which approved a generic rate of return of 8.93% for 2006. The Board considers it appropriate to apply this rate established in this order, and therefore, approves a rate of return on common equity of 8.93% for EPC for 2006. The Board directs EPC to incorporate this revised 2006 rate of return in its refiling application resulting from this Decision. 9 RENT PAID BY EPC FOR ENMAX PLACE

EPC stated that in response to a directive from the Board,129 EPC had retained the Altus Group Calgary Real Estate Advisory Services Inc. (Altus) to prepare a comprehensive study on the total rent paid by EPC to ENMAX for ENMAX Place, and that the Altus Rental Opinion —ENMAX Place, Calgary, Alberta (Altus Report), dated December 21, 2004 was filed with the Application.130 EPC stated that Altus had completed a detailed inspection of ENMAX Place, and carried out a full market analysis and valuation of the premises that EPC leases from ENMAX. Altus had concluded that the market rent range for such leased space, effective December 2004, was between $23.43 and $26.17 per square foot.131 EPC noted that for 2005, its lease costs are $22.47 per square foot.132 EPC stated that the conclusions set out in the Altus Report, demonstrating that the total rent paid by EPC for ENMAX Place are slightly below market, are well supported, and stand uncontested on the record. EPC further submitted that the rent paid by EPC for ENMAX Place is also significantly lower than the estimated cost of EPC constructing its own building.133 As such, EPC submitted that its rental costs should be allowed as applied for. The CG questioned EPC’s witnesses during the hearing but did not comment on this portion of EPC’s Application in argument or reply. Board panel and staff also questioned EPC on the composition and amount of rent paid by EPC to ENMAX during the hearing, and the Board is satisfied by EPC’s responses, in addition to analysis of the Altus Report, that EPC is paying a fair market rent to ENMAX for the use of ENMAX Place.

128 Order U2005-410 – Board Initiated Proceeding 2006 Generic Return on Equity Formula Result,

dated November 22, 2005 129 Decision 2004-066, p. 48 130 Exhibit 093 131 Exhibit 092, Altus letter, p. 2 132 Exhibit 093, p. 3 133 Exhibit 326-029




The Board therefore approves EPC’s rental costs as applied for. 10 REFILING PROCESS

The Board directs EPC to revise its forecast 2005 revenue requirement, proposed rates, proposed fees and proposed Terms and Conditions in accordance with the directions set out in this Decision; and to refile these items with the Board no later than February 10, 2006. The refiling directions are summarized in Appendix 2 for the convenience of all parties. The Board directs EPC, in its refiling, to calculate the difference between the revenue collected on existing 2005 rates and the revenue that would have been collected on final rates for the period January 1, 2005 to December 31, 2005. The Board directs EPC to propose a method of collecting or refunding this difference from customers, on a rate class instead of individual customer basis. The Board is of the view that a rate class rider consistent with the method approved in the 2004 EPC refiling is a more practical and appropriate form to use. The Board further directs EPC, in its refiling, to file a summary of typical DT billings (broken down by DAS and SAS) to retailers comparing the existing 2005 DT rates with the 2005 refiled DT rates using the Board’s standard rate comparisons by low, average and high use customers in each rate class. The Board also directs EPC, in its refiling, to collaborate with EEC and file a summary of typical residential and commercial billings comparing the existing 2005 EEC RRT rates (including the existing 2005 EPC DT rates) with the 2005 refiled EEC RRT rates (including the 2005 refiled EPC DT rates) using the Board’s standard rate comparisons by low, average and high use customers in each rate class. The Board finds that it would be appropriate to provide for a short written process to ensure that EPC’s refiling complies in all respects with the Board’s directions. Accordingly, the Board sets down the following refiling schedule:

Event Date EPC Refiling February 10, 2006 Comments from Interested Parties, if any February 17, 2006 Reply from EPC (including second refiling, if necessary, to correct any errors or omissions) March 1, 2006 Board Final Distribution Tariff Decision March 14, 2006 EPC Implementation of Rates April 1, 2006

The Board emphasizes that comments from interested parties are restricted to comments that will assist the Board in determining if the EPC refiling complies in all respects to the Board’s refiling directions.



11 ORDER

(1) ENMAX Power Corporation shall comply with all Board directions in this Decision. (2) ENMAX Power Corporation shall refile its 2005-2006 DT Application as required by this

Decision, on or before February 10, 2006 incorporating the findings and directions in this Decision.

Dated in Calgary, Alberta on January 13, 2006. ALBERTA ENERGY AND UTILITIES BOARD (original signed by) N. W. MacDonald, P.Eng. Presiding Member (original signed by) J. I. Douglas, FCA Member (original signed by) R. G. Lock, P.Eng. Member



APPENDIX 1 – HEARING PARTICIPANTS

Name of Organization (Abbreviation) Counsel or Representative (APPLICANTS) Witnesses

ENMAX Power Corporation (EPC) ENMAX Energy Corporation (EEC) L. A. Cusano D. M. Wood

S. Stoness R. Nesbitt B. Thompson W. Kadonaga J. Li H. Johansen C. Oseen R. Baldauf L. Kennedy S. Navrady G. Basford S. Munn

On her own behalf G. Wilkinson

Consumers Group, consisting of the following groups (CG): Public Institutional Consumers of Alberta (PICA) N. J. McKenzie R. Retnanandan Utilities Consumer Advocate (UCA) C. R. McCreary R. Henderson T. A. Shipley Consumers' Coalition of Alberta (CCA) J. A. Wachowich

Calgary Industrial Group (CIG), Building Owners Coalition L. L. Manning

Tsuu T'ina First Nations A. O. Ackroyd, Q.C.

ATCO Electric Ltd. (AE) K. Illsey

City of Calgary (Calgary) D. I. Evanchuk, Esq.



Name of Organization (Abbreviation) Counsel or Representative (APPLICANTS) Witnesses

Lehigh Inland Cement R. K. M. Bellows

Independent Power Consumers Association of Alberta (IPCAA) D. B. Macnamara

Alberta Energy and Utilities Board Board Panel N. W. MacDonald, P.Eng, Presiding Member J. I. Douglas, FCA, Member R. G. Lock, P.Eng., Member Board Staff

R. Marx (Board Counsel) D. Ploof D. Mitchell K. VanKosh R. Litt



APPENDIX 2 – SUMMARY OF BOARD DIRECTIONS

This section is provided for the convenience of readers. In the event of any difference between the Directions in this section and those in the main body of the Decision, the wording in the main body of the Decision shall prevail.

1. The Board is of the view that these options should be examined. Therefore, the Board directs EPC to examine the above possible improvements for Commercial load forecasting and implement those that provide benefits that outweigh costs at the time of the next GTA. The Board expects EPC to carry out its commitment to continue to update its site count history and forecasting methodology in future proceedings. ................................................................ 7

2. The attached Appendix 4 contains the Board’s calculation of the vacant position allowance amounts for 2005 and 2006 which result in an operating expense reduction of $0.813 million in 2005 and $0.346 million in 2006. The composite vacancy rate determined by the Board is 4.6% for 2005 and 3.9% for 2006. The Board directs EPC, in its refiling, to include the amounts shown in Appendix 4 as its allowance for vacant positions..................................... 10

3. The Board directs EPC, in its next GTA, to include a forecast vacancy rate for each of the functions shown on Exhibit 268 and the Board further expects that EPC will provide reasons for the assumptions behind the forecast vacancy rates. The Board acknowledges that the use of historical information is one method of arriving at the forecast vacancy rates for the test years. ....................................................................................................................................... 11

4. With respect to the CG submission regarding the study of network OM&A costs, the Board notes that EPC did not reply to this issue. The Board agrees with the CG that since different classes of customers contribute to the costs of the primary and secondary Network system, it would be desirable for EPC to split its network OM&A costs between the two systems. Consequently, the Board directs EPC, as part of its next GTA, to undertake such a study and file its network OM&A costs between primary and secondary systems. ............................... 13

5. Given that the Board has found that it is difficult to forecast how many meters each year will have to be recertified, the Board considers that this number has an even chance of being higher or lower than the 2004 actual amount. Consequently, the Board will approve the level of expenditures at $1.84 million as calculated by the Board above. The Board therefore directs EPC, in its refiling, to reduce the forecasted operating expenses for the Wholesale Services by $160,000 in 2005 and $160,000 in 2006. ............................................................ 15

6. The Board agrees with the CG that a key element in interpreting the benchmarking study would have been an understanding of how the Cap Gemini consultant dealt with the fact that EPCOR and EPC have different overhead capitalization rates. The Board considers that this understanding was not obtained from the study performed by Cap Gemini partially due to the fact that the Cap Gemini consultant was not available for cross examination. As a result, the Board directs EPC to collaborate with EPCOR and, as part of EPC’s next GTA, complete another O&M benchmarking study that compares the EPC and EPCOR distribution systems. The Board also directs that this study include details on how the effect of the different overhead capitalization rates was taken into account including a comparison of the administrative accounts considered to be eligible for overhead capitalization....................... 16



7. Accordingly, the Board directs EPC to provide a detailed explanation of all material variances over 10% in its next GTA application. The Board directs that this explanation be provided at the level of detail shown on Schedule 4.2.5 for Executive and Administration, Schedule 4.2.6 for Human Resources, Schedule 4.2.7 for Information Services, Schedule 4.2.8 for Finance and Supply, and Schedule 4.2.9 for Regulatory. ........................................ 19

8. Accordingly, the Board directs EPC to remove the 2005 forecast of $280,000 for CEO/CFO Certification from the DT revenue requirement. .................................................................... 21

9. Accordingly, the Board directs EPC to reduce the “other category” of Finance and Supply Chain Management by $0.6 million for 2005 and 2006 in its refiling. .................................. 21

10. The Board notes that the target for OM&A is $50.9 million while the revenue requirement for Operating Expenses is $45.2 million. The Board directs EPC, in its refiling, to explain why this KPI is higher than the requested revenue requirement and the effect this may have on the benefits normally available when targets are achieved................................................ 25

11. The Board therefore directs EPC, in its refiling, to reduce the amount of 2005 short term incentive compensation as follows: 50% of OM&A, 100% of Revenue from New Sources, 50% of Return on Equity, 50% of cash Flow from Operations, and 50% of Risk Adjusted Return on Portfolio. ................................................................................................................ 25

12. As a result, the 2005 short-term incentives approved by the Board amount to approximately $2.96 million. The Board will allow short-term incentives in the amount of $3.08 million for 2006 which provides for a 4% inflation factor over the 2005 Board approved amount. The Board further directs EPC, in its refiling, to structure the 2006 short term incentive such that it corresponds to the methodology approved for 2005 and does not exceed the approved $3.08 million in total for 2006. ............................................................................................... 25

13. If the short-term incentives paid out are less than the Board approved amounts of $2.96 million for 2005 and $3.08 million for 2006, the Board directs EPC to provide a one-time credit to customers with the difference between the payout and the Board allowed amounts at the time of the next GTA. ....................................................................................................... 25

14. For the above reasons, the Board directs EPC, in its refiling, to remove the long term incentive amounts from its forecasted operating costs. .......................................................... 26

15. While EPC has a review process in place for the capitalization overhead rate, the Board is surprised that the significant variation in the 2004 actual capital expenditures did not result in a change in the rate itself. EPC’s evidence was that there is no formal document that is signed to indicate that a change has been approved. The Board considers that the review process itself should be documented more clearly to assist the Board and interested parties in understanding what materials are actually reviewed and how decisions that affect the rate are made. Therefore, the Board directs EPC to keep written evidence of any and all capital overhead review meetings that occur (e.g. agendas, materials presented for discussion, minutes, etc.) and have these available for review at the next GTA if so requested. ............. 26

16. The Board notes that if EPC’s actual capital spending, before the application of the capitalized overhead, in 2005 for example, was to be $10 million higher than the approved amount, EPC’s rate base will be increased by $1.9 million. In addition to this, EPC’s OM&A expenses will be decreased by $1.9 million which would accordingly increase EPC’s earnings. Due to the fact that EPC’s 2004 actual capital expenditures were significantly higher than its forecast, the Board is concerned that this situation may occur again in 2005. To guard against the possibility of this over-recovering of the capitalized overhead, the Board



directs that the maximum amounts of capitalized overhead that EPC can apply to capital expenditures are as follows: $14.8 million in 2005 and $12.1 million in 2006. These are the capitalized overhead amounts as forecasted by EPC. In the event that EPC’s actual capital expenditures in either or both of these years is less than the forecasted amount, the Board directs that the amount of overhead capitalized be in accordance with the 19% rate. ........... 27

17. The Board has calculated the reduction amounts for 2005 and 2006 that are attributable to the disallowance of 1% for Management/Professional compensation and for simplicity, directs EPC to include these disallowances as reductions to O&M. Please see Appendix 6 for the details of the Board’s calculations. ......................................................................................... 28

18. Therefore, the Board directs that, in its refiling, EPC provide details that allocate the costs of the Mercer study to all areas of ENMAX. The cost allocation methodology should be based on the actual 2004 FTEs. In its refiling, EPC should remove from the hearing cost reserve account the sum of the amounts allocated to the other areas of ENMAX.............................. 28

19. Consequently, the Board has determined the level of executive compensation for the DT as outlined in Appendix 7. The Board directs that in its refiling, EPC reduce its operating expense forecasts for executive compensation by the amount outlined in Appendix 7. The Board also directs EPC to include in its next GTA, testable evidence that it has performed a position by position review of its executive compensation to determine its market competitiveness. The Board considers that it is up to EPC whether or not it wishes to do this internally or externally. However, the Board directs EPC to make the results available for examination at the next GTA.................................................................................................. 29

20. However, with respect to the form of rider used to recover EPC’s 2006 TAC deferral account, the Board notes that in Decisions 2005-096, 2005-131, and 2005-132, the 2006 AESO tariff underwent a significant price increase and change in cost recovery methodology. As such, in this instance, the Board sees merit in the CG’s request that EPC examine cost causation issues of any amount contained in its 2006 TAC deferral account and that EPC should propose an appropriate allocation of the TAC deferral costs by rate class and the form of rider(s) for recovery of its 2006 TAC deferral account at the time EPC applies for its 2006 TAC deferral rider. The Board will therefore refrain from approving a form of the 2006 TAC deferral account rider at this point in time and directs EPC to examine and report on this matter to the Board at the time of its 2006 TAC deferral rider application............................ 31

21. For the above reasons, the Board directs EPC to reduce its updated 2005 hearing cost reserve request of $0.3 million by $0.3 million, and similarly to reduce its updated 2006 hearing cost reserve request of $1.2 million by $0.2 million. ..................................................................... 33

22. In summary, the Board directs EPC to modify Schedule 5.3 (Regulatory Hearing Cost Reserve Account) as noted in Table 3. ................................................................................... 33

23. The Board, for the purpose of this Decision, will accept the BearingPoint study allocation. However, the Board directs EPC to further study and show cause as to why some portion of wholesale computer hardware, enterprise software costs and administration should not be allocated to Calgary water and other Municipalities in a fully allocated cost study and submit the results of this further study at EPC’s next GTA. .............................................................. 34

24. For clarity, the Board considers that this approval is simply for the establishment of the deferral account, and that no costs have been approved for collection. The Board agrees with the CG that interveners and the Board should have the ability to examine these costs in future proceedings. To that end, the Board directs EPC, in its refiling, to include a proposal for a



review process for any amounts recorded in the Uniform System of Accounts deferral accounts................................................................................................................................... 37

25. However, the Board directs EPC, in its next GTA, to provide greater detail on the calculation of the capitalized overhead rate. The Board considers that information similar to that presented in Exhibits 174, 278 and 314 of this proceeding would be beneficial to parties in understanding how the capitalized amounts are derived. The Board further directs EPC to clearly set out the components of shared services and other OM&A expenses that are considered to be subject to administrative overhead capitalization including reasons why the capital component of these accounts cannot be determined by direct assignment. ................ 38

26. Consequently, the Board directs EPC, in its next GTA, to include business cases for any actual capital project additions to rate base in 2005 and 2006 that are greater than $500,000 and that were not included in the capital forecast in this Application. To assist in this matter, the Board and interested parties need to know exactly what capital projects are included in this Application. As a result, the Board directs EPC, in its refiling, to expand Schedules 6.3.1.3 and 6.3.1.4 to include the project number, description and forecast amounts that comprise the various capital programs. .................................................................................. 38

27. Further, the Board directs EPC to include information respecting each forecast project, including project number, description and forecast amounts that comprise the various capital programs for the forecast years of its next GTA. The Board also directs EPC to include corresponding schedules that contain actual results for 2005 and either actual 2006 results or an updated forecast for 2006 at the time of its next GTA. This information will enable the Board and interested parties to compare the 2005 and 2006 results to the approved forecasts for those years and verify that business cases have been filed where necessary. ................... 39

28. Accordingly, the Board directs EPC, in its next GTA, to show the capital expenditures for the residential and non-residential development area of the Network capital program separately. The Board also directs EPC, in its next GTA, to file separate business cases for the residential and non-residential development areas in accordance with the threshold amount of $500,000.................................................................................................................................. 40

29. Consequently, the Board directs EPC, in its next GTA, to provide details of comparisons between the reliability of its network system with the network systems of other distribution utilities. The details provided should be comprehensive enough to permit the Board and interested parties to understand, among other things, what the reliability measures are, how they are calculated and how and when they are measured. The Board also directs EPC, in its next GTA, to include yearly forecast amounts for these network reliability indexes as well as actual results for 2005 and 2006. If other electric distribution utilities have already developed these reliability indices, the Board considers that EPC should adopt these as placeholders. If EPC discovers that there are no such indices in use by other distribution utilities, then EPC should develop these indices internally. ................................................................................. 41

30. Therefore, the Board directs EPC, in its refiling, to reduce the 2006 capital additions with respect to the Distribution Tariff Billing System project by $0.267 million (i.e. $1.096 million - $0.829 million), and to flow through the impact of this reduction to all other applicable areas of the Application (e.g. return on rate base, depreciation and GST working capital)..................................................................................................................................... 42

31. The Board notes that as a result of directions from other parts of this Decision, some of the Lead Lag related figures under the “Expense” column of Schedule 6.6.1 for 2005 and 2006 and the “Amount” column of Schedule 6.6.3 for 2005 and 2006 will change. The Board



directs EPC, as part of its Refiling, to ensure that the amounts included under the “Expense” column of Schedule 6.6.1 for 2005 and 2006 and the “Amount” column of Schedule 6.6.3 for 2005 and 2006 are updated where necessary to reflect the refiled amounts........................... 44

32. The Board expects that after the impact of these reductions, the forecast mid year balances for the HCR account will change. The Board directs EPC, in its refiling, to reflect these updated balances in the necessary working capital calculations. ........................................... 45

33. The Board considers that it is still open to EPC to implement more simplified depreciation methods should management consider the costs of tracking retirements by vintage to no longer be a requirement for asset control purposes. The Board continues to be of the view that there are merits in moving to a simplified depreciation methodology and as such the Board directs EPC to continue to assess and report on the need to maintain the more complex system used for asset control purposes at its next GTA. ........................................................ 46

34. With respect to Finding #2, the Board concludes that notwithstanding that the GF ELG Method has loaded a full-year’s depreciation accrual on the 2003 vintage as of December 31, 2003, the GF ELG Method has properly credited the accumulated depreciation with only one-half of the 2003 vintage accruals. However, the Board has observed a second order problem in that the GF ELG Method determines for each vintage the vintage theoretical accumulated depreciation factor as of December 31, 2003 by multiplying each vintage accrual rate by the age of that vintage as of December 31, 2003. The Board notes that these vintage accrual factors are applied to actual December 31, 2003 account plant balances to arrive at the composite year-end theoretical accumulated factor for each account. The Board considers that this method ignores the retirements that were predicted to occur for each ELG within the study year. For example the accumulated accrued factor for the 2003 vintage as of December 31, 2003 should be the 2003 vintage rate times the age less the first equal life group which is predicted to be retired as of December 31, 2003. This would result in an accumulated accrual factor of 0 for the first equal life group of 13.2% assumed to retire on December 31, 2003. The Board is satisfied that the GF ELG Method does not appear to introduce any material errors respecting this finding. However, the Board directs EPC to correct these minor distortions in the next Depreciation Study.............................................. 48

35. The Board was not provided any of the back-up data for the calculation of the depreciation expense for General Accounts and is therefore unable to determine if the half year convention has been violated. The Board will, for the purposes of this Decision, accept EPC’s calculation of the General Accounts for 2005 and 2006. However, the Board directs EPC to implement the one-half year convention for the most recent vintage at the time of the next GTA. ............................................................................................................................... 50

36. For all of the above reasons, the Board directs EPC to use the Board approved depreciation rates, as set out in Appendix 9, in EPC’s refiling. .................................................................. 54

37. The Board considers that EPC’s decision not to roll over cost of removal places an additional burden on separating and recording the cost of removal by vintage. The Board directs EPC to track the additional costs incurred in data requirements to track the net salvage by vintage within each account................................................................................................................. 55

38. Accordingly, the Board directs EPC to study the feasibility of separating the salvage from annual accruals and the accrued depreciation in order to assist in the accurate monitoring of the accumulated depreciation by account and report on EPC’s investigation at the time of the next GTA. For further clarity, the Board notes that the sum of the “salvage” reserve and the “service life” reserve would be equal to the traditional accumulated depreciation reserve. .. 55



39. For all of the above reasons, the Board directs EPC to treat CFCFC as a reduction to rate base and amortize the CFCFC at the composite EPC depreciation rate (using the format of Appendix 10) in its refiling. The Board directs EPC to follow the mid-year rule and only include one-half of the $14.2 million (i.e. $7.1 million) CFCFC (collected in respect of 2004) and one half of the $19.0 million ($9.5 million) CFCFC (collected in respect of 2005) for the test year 2005 and the full CFCFC amount of $33.2 for the test year 2006 in determining the CFCFC reduction to rate base. The Board further directs EPC to use the capital structure, cost of debt and cost of equity for 2005 and 2006 approved in the following sections of this Decision for the remaining rate base after the CFCFC reduction. The Board further directs EPC to use the refiled composite depreciation rate for 2005 and 2006 to determine the amortization of the CFCFC..................................................................................................... 62

40. The Board does not have any evidence respecting whether a 2006 equity funding rider will be implemented by Calgary in the 2006 test year. Should Calgary require EPC to collect a 2006 equity funding rider in 2006, the Board directs that one-half of the 2006 actual amount actually collected through the 2006 equity funding rider be multiplied by the sum of the Board approved 2006 composite return of 6.743% and the refiled Board approved 2006 composite depreciation rate and returned to customers by way of a temporary rate reduction rider in 2007............................................................................................................................ 63

41. The Board directs EPC to incorporate this revised 2006 rate of return in its refiling application resulting from this Decision. ................................................................................ 65

42. The Board directs EPC to revise its forecast 2005 revenue requirement, proposed rates, proposed fees and proposed Terms and Conditions in accordance with the directions set out in this Decision; and to refile these items with the Board no later than February 10, 2006. The refiling directions are summarized in Appendix 2 for the convenience of all parties. ........... 66

43. The Board directs EPC, in its refiling, to calculate the difference between the revenue collected on existing 2005 rates and the revenue that would have been collected on final rates for the period January 1, 2005 to December 31, 2005. The Board directs EPC to propose a method of collecting or refunding this difference from customers, on a rate class instead of individual customer basis. The Board is of the view that a rate class rider consistent with the method approved in the 2004 EPC refiling is a more practical and appropriate form to use. 66

44. The Board further directs EPC, in its refiling, to file a summary of typical DT billings (broken down by DAS and SAS) to retailers comparing the existing 2005 DT rates with the 2005 refiled DT rates using the Board’s standard rate comparisons by low, average and high use customers in each rate class.............................................................................................. 66

45. The Board also directs EPC, in its refiling, to collaborate with EEC and file a summary of typical residential and commercial billings comparing the existing 2005 EEC RRT rates (including the existing 2005 EPC DT rates) with the 2005 refiled EEC RRT rates (including the 2005 refiled EPC DT rates) using the Board’s standard rate comparisons by low, average and high use customers in each rate class............................................................................... 66



APPENDIX 3 – SUMMARY OF BOARD FINDINGS AND CONCLUSIONS

This section is provided for the convenience of readers. In the event of any difference between the Approvals in this section and those in the main body of the Decision, the wording in the main body of the Decision shall prevail.

1. The Board approves the EPC economic forecast as set out in the Application........................ 4

2. The Board does not consider that there is a clear trend of under or over forecasting present in EPC’s Residential consumption forecast history. The Board considers EPC’s Residential energy consumption forecast to be reasonable and approves it as set out in the Application. . 5

3. The Board considers that EPC’s 2004 Residential site forecast error of 0.1% is indicative of a sound forecasting process, and therefore approves the EPC forecast number of Residential sites as set out in the Application.............................................................................................. 6

4. The Board has verified the revenue impact of the site errors and is in agreement with EPC that the impact is indeed less than 0.01% for both 2005 and 2006. Further, the Board has calculated the potential error which this minor site error may have on EPC’s Phase II Cost of Service allocations, and has determined again the impact to be negligible. The Board does not consider that an error of this magnitude is a requisite for EPC to update its commercial site forecast. The Board therefore approves EPC’s commercial energy consumption and site forecast as set out in the Application. ....................................................................................... 6

5. The Board considers the EPC Streetlighting approach to be technically sound, and therefore approves it as set out in the Application. .................................................................................. 7

6. The Board considers the process used to derive monthly energy from annual energy to be technically sound and approves the monthly energy forecast as set out in the Application..... 8

7. Parties did not supply comment on this section. The Board approves the loss factors as set out in the Application................................................................................................................ 8

8. The Board approves in full EPC’s Load and Revenue Forecast as set out in the Application. 9

9. The Board has prepared a table (see Appendix 5) in which it compares the salaries and wages using the recommendations of the CG to the EPC applied for amounts. As can be seen in Appendix 5, the starting point is the 2004 actuals. To this, the Board has incorporated the 4% escalation rate for 2005 and 2006 recommended by the CG and the backfilling of approximately ¼ of 17 positions in 2005 and another ¼ of 17 positions in 2006 as recommended by the CG. In addition, the Board has incorporated the updated vacant position allowance in 2005 of $1.1 million. The Board made this adjustment to account for the fact that the 2004 actuals have no vacant position allowance included in them. As can be seen in Appendix 5, the resulting differences would be a reduction of $0.3 million in 2005 and an increase of $0.3 million in 2006. The Board considers that the reduction of $0.3 million in 2005 is offset by the increase of $0.3 million in 2006. Consequently, the Board has determined that no reduction is required to the Distribution function salaries and wages. The Board therefore approves the salaries and wages for the Distribution function of $24.5 million in 2005 and $25.2 million in 2006 as requested by EPC. .......................................... 13

10. The Board notes that the 2004 actual OM&A expenditures for the Network function amounted to $2.8 million. The Board also notes that the 2005 and 2006 forecast amounts of $3.3 million and $3.4 million respectively, as presented on Schedule 4.1 do not include the



impact of the vacant position allowance attributable to the Network function. Once the updated vacant position allowance for this function is taken into account, the comparable forecast amounts are $2.7 million for 2005 and $2.8 million for 2006. The Board considers that this is reasonable compared to the actual expenditures for 2004 and therefore no further reductions are necessary. ........................................................................................................ 13

11. The Board rejects the recommendation of the CG that the Board direct EPC to develop a formal plan for the purposes of forecasting revenue metering expense for the next GTA. However, the Board expects that EPC will provide, in its next GTA, any reasons and documentation necessary to support its assumptions regarding the number of meters to be recertified during the test periods. .......................................................................................... 15

12. Accordingly, the Board does not approve the reduction in revenue requirement for Financing Costs suggested by the CG since the Board has already reduced the revenue requirement in the above section..................................................................................................................... 22

13. The Board agrees with EPC that the costs have already been appropriately allocated to all regulated and unregulated businesses within the ENMAX group of companies. The Board approves the Governance costs as filed. ................................................................................. 22

14. The Board agrees with EPC’s submission that much of the costs in the “other” category are accounted for by adjusting the non-salary costs listed in Exhibit 326-028 by the general inflationary factor of 2.2%. Accordingly, the Board accepts EPC’s inclusion of these costs in the 2005-06 revenue requirement. .......................................................................................... 23

15. The Board notes that EPC has forecast increases in SSC Operating Costs in both 2005 and 2006 even though there was a decrease in costs from 2003 to 2004. The Board agrees with EEC that operating costs such as snowfall removal are difficult to forecast and a one year downtrend due to reduced snow removal costs does not necessarily equate to an overall reduction in operating costs. As such, the Board is satisfied that the SSC Operating Costs are reasonable, but does consider that forecasting for operating costs which are subject to weather related volatility should be based on periods of time longer than one year. The Board requests that EPC consider inclusion of such analysis in future applications. ....................... 24

16. The Board rejects the recommendation made by the CG with regard to having EPC conduct another independent study of compensation levels. The Board was satisfied that the Mercer study presented in this Application, albeit with an expanded scope, was acceptable. ........... 28

17. Finally, the Board has reviewed the EPC calculation of its SAS expense forecasts, and considers that the 2005 and 2006 EPC SAS charge forecasts are reasonable. The Board therefore approves the 2005 and 2006 EPC SAS charge forecasts as applied for.................. 31

18. The Board is in agreement with EPC that the TAC deferral should contain non-volume variances between forecast and actual tariff charges as well as any other applicable AESO rates, deferral account dispositions or riders. If the Board were to rule that the deferral account be based simply on actual Transmission costs compared to actual Transmission revenue, it would be eliminating the volume forecast risk element from EPC’s Transmission component. The Board’s intent is not to eliminate this forecast risk, and thus approves in full the requested EPC TAC deferral account calculation procedure as applied for..................... 31

19. The Board also considers that EPC’s applied for form of TAC rider in 2005 is still appropriate, given the relative similarity of the 2003 and 2005 AESO Tariff. The Board therefore approves in full EPC’s applied for methodology of using a ¢/kWh rider for all of its customers for its 2005 deferral account. ................................................................................. 31



20. The Board agrees there was a forecast error in EPC’s starting balance for 2005. The Board also agreed with the CG statement that the entire hearing costs for the Phase I and II portions of the 2004 EPC proceeding were $0.75 million. The Board considers that a value of $0.65 million will represent an upper boundary on EPC’s hearing costs for 2005 and 2006. As such, the Board considers that EPC’s revised 2005 starting balance of $1.1 million should be sufficient to cover its hearing reserve costs for 2005, and will not award any extra amount. 32

21. The Board therefore denies EPC’s updated request for $0.3 million for hearing reserve funding in 2005. ...................................................................................................................... 33

22. The Board has reviewed the items on which EPC based its forecast for 2005 and 2006 and notes the similarities. The Board does not consider that there is anything to suggest that the magnitude of cost items in 2006 will not be similar to 2005. Using EPC’s 2005 year-end forecast of $0.1 million, the Board considers that an amount of $1.0 million will be required by EPC in 2006, resulting in a total hearing cost reserve for 2006 of $1.1 million................ 33

23. The Board therefore approves a hearing reserve cost funding amount of $1.0 million for 2006......................................................................................................................................... 33

24. The Board notes the magnitude of the CG estimate of revenue requirement impact of the change and considers that the aggregate additional cost of $57,000 spread over 2005 and 2006 should be more than offset in future by cost savings related to having a similar accounting treatment for both plans. The Board therefore approves EPC’s request to change to a “cash basis” accounting treatment for its SRP................................................................. 35

25. The Board considers however, that the statutory legislation that EPC’s pension deficit be retired within five years be given the most weight in arriving at its Decision. The Board considers that EPC’s applied for amounts and deferral methodology represent a balanced approach to retiring its pension deficit, in that recognition has been given to the fact that the investment conditions and actuarial assumptions which led to the deficit forecast appear to be changing to the benefit of the pension fund. The Board therefore approves EPC’s pension funding request and deferral account as applied for. .............................................................. 36

26. The Board notes that EPC has not included the forecast value of $6.05 million in its rate base forecast or capital expenditures for 2005 and 2006. The Board therefore does not consider it appropriate that EPC be awarded any cash return on this forecast expenditure. However, the Board will allow EPC to include a non-cash return in the form of AFUDC for any customer contribution expenditures incurred during 2006. Assuming it is approved, following the substation’s completion and in-service date, it is open to EPC to apply at the time of the next GTA to add the $6.05 customer contribution together with associated AFUDC to the rate base. The Board therefore denies the requested cash amount of $0.2 million related to AESO Customer Contribution Carrying Charges in the 2006 revenue requirement. ........................ 36

27. The Board considers that this is an important initiative and that all utilities should be encouraged to move it forward with priority. The Board considers that EPC’s participation in this process is valid and that EPC should participate fully to see this matter implemented as soon as reasonably practical. Consequently, EPC should be entitled to recover any prudently incurred costs associated with the scoping and implementation process. The Board approves the establishment of the EPC requested operating expense and capital expense deferral accounts to deal with the scoping and implementation costs incurred by EPC in association with the development of a uniform system of accounts. ........................................................ 37



28. The Board is satisfied that the material presented in these exhibits clearly presents that the capitalized overhead rate was calculated to be approximately 19%. Consequently, the Board rejects the suggestion of the CG on this matter. ..................................................................... 38

29. The Board is satisfied with the forecast EPC provided for Distribution and approves the forecast as filed, subject to the comments that are applicable to the entire capital expenditures area.......................................................................................................................................... 39

30. The Board is aware that the 2004 actual capital expenditures for EPC were significantly greater than the approved forecast amounts. The Board has expressed its concerns with respect to this issue in conjunction with its comments on Section 4.7, the operating expenses capitalized. The Board agrees with EPC that the issue of the accuracy of capital expenditure forecasting should be dealt with on a macro basis instead of examining each separate project. The Board considers that the management of EPC has to deal with the capital spending on an overall level, as priorities and timeline estimates continually change. The Board also considers that the fact that EPC did indeed under-recover in 2004 demonstrates that the $0.4 million in question was a single item in a much larger program and that EPC is not engaging in what the CG refers to as “double-dipping”. Consequently, the Board rejects the recommendation of the CG..................................................................................................... 40

31. The discussion regarding 2004 capital expenditures set out in section 6.3.3 above applies equally here. The fact that on an overall basis, the 2004 actual capital expenditures were more than the forecast amount, the Board does not have persuasive evidence that EPC has a tendency to over-forecast capital expenditures. Consequently, the Board rejects the recommendation of the CG..................................................................................................... 41

32. The Board is satisfied with the forecast EPC provided for Information Technology, General Plant and Other and approves the forecast as filed, subject to the comments that are applicable to the entire capital expenditures area. .................................................................. 43

33. The Board is satisfied with the forecast for the revenue lag days that EPC provided and approves the forecast amounts as filed. .................................................................................. 43

34. The Board is satisfied with the forecast for the system access service charges lag days that EPC provided and approves the forecast amounts as filed. .................................................... 44

35. The Board is satisfied with the forecast for the OM&A lag days that EPC provided and approves the forecast amounts as filed. .................................................................................. 44

36. The Board is satisfied with the forecast for the long-term debt interest lag days that EPC provided and approves the forecast amounts as filed. ............................................................ 44

37. The Board is satisfied with the forecast for the depreciation lag days that EPC provided and approves the forecast amounts as filed. .................................................................................. 44

38. The Board is satisfied with the forecast for the dividend and retained earnings lag days that EPC provided and approves the forecast amounts as filed. .................................................... 44

39. The Board is satisfied with the forecast net lead/lag days EPC provided and approves these days as filed............................................................................................................................. 44

40. The Board is satisfied with the forecast for materials and supplies inventory that EPC provided and approves the forecast amounts as filed. ............................................................ 45

41. The Board is satisfied with the forecast for customer deposits that EPC provided and approves the forecast amounts as filed. .................................................................................. 45



42. The Board is satisfied with the forecast for the SAS deferral account that EPC provided and approves the forecast amounts as filed. .................................................................................. 45

43. The Board is satisfied with the forecast for the AESO capital charges deferral account that EPC provided and approves the forecast amounts as filed. .................................................... 45

44. The Board is satisfied with the forecast for the GST subject to changes to any of the expense amounts that result from directions in other parts of this Decision. ....................................... 46

45. For the same reason the Board rejects Mr. Kennedy’s assertion that a simplified depreciation system would necessarily increase the business risk of EPC. In fact, it could reduce the business risk if there is a premature recovery of investment. ................................................. 51

46. The Board considers it open to EPC, in its refiling, to request approval to revise the debt financing requirements shown on Schedule 8 to the extent necessary to be consistent with the GCOC deemed 61% debt and 39% equity GCOC capital structure as result of the Board’s findings respecting CFCFC. ................................................................................................... 63

47. The Board agrees with EPC that its deemed capital structure as determined in Decision 2004-052 continues to apply. The Board therefore approves EPC’s capital structure as applied for.................................................................................................................................................. 63

48. The Board notes that EPC has modified its 2005 and 2006 revenue requirements to reflect the new lower rate for the 2005 issue. With respect to the 2006 issue, the Board is in agreement with EPC that the rate for the 2006 issue could be higher or lower than the original forecast. The Board does not consider it appropriate for the 2006 issue to be revised lower as suggested by the CG because of this equal probability of the 2006 rate being higher or lower. The Board therefore approves EPC’s 2005 embedded cost of debt as revised by the lower rate for the 2005 issue, and EPC’s 2006 embedded cost of debt as revised by the lower rate for the 2005 issue. ................................................................................................................... 64

49. The Board agrees with EPC that its rate of return on common equity for 2005 is 9.50%, per EUB Order U2004-423. The Board therefore approves EPC’s 2005 rate of return on common equity as applied for................................................................................................................ 65

50. The Board does not consider that Order U2004-423 applies to the 2006 rate of return on common equity, since that order was only with respect to 2005. While at the time EPC filed its application, Order 2004-423 would have been the best information on which to base its forecast, following the hearing, Order U2005-410, dated November 22, 2005 was issued which approved a generic rate of return of 8.93% for 2006. The Board considers it appropriate to apply this rate established in this order, and therefore, approves a rate of return on common equity of 8.93% for EPC for 2006. ..................................................................... 65

51. The Board therefore approves EPC’s rental costs as applied for............................................ 66



APPENDIX 4 – BOARD DETERMINED VACANT POSITION ALLOWANCE

Appendix 4 - Board Determined Vacant Po

(Consists of 2 pages)



APPENDIX 5 – BOARD TEST - SALARIES AND WAGES

Appendix 5 - Board Test - Salaries and W

(Consists of 1 page)



APPENDIX 6 – BOARD DETERMINED MANAGEMENT SALARIES

Appendix 6 - Board Determined Managem

(Consists of 1 page)



APPENDIX 7 – BOARD DETERMINED EXECUTIVE COMPENSATION

Appendix 7 - Board Determined Executive




APPENDIX 8 – BOARD APPROVED ELG METHOD

Appendix 8 - Board Approved ELG Method




APPENDIX 9 – BOARD APPROVED DEPRECIATION RATES

Appendix 9 - Board Approved Depreciatio




APPENDIX 10 – BOARD CALCULATIONS ILLUSTRATING TREATMENT OF CFCFC

Appendix 10 - Board CFCFC Calculations



2005-2006 DT ENMAX Power CorporationAppendix 4Page 1 of 2

ENMAX Power CorporationDistribution

Board Determined Vacant Position Allowance2005

(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)= (B)/(A) = (C)*(D) = (E)-(F) = (G)/(D) = (G)*(I)

2004 CG EPC 2005 CG 2005 Per Board 2005 2005Allocated Recommended Vacancy 2005 Calculated Recommended Final Vacancy Cost Per Vacancy

Function Complement Vacancies Rate Forecast Vacancies Backfilling Vacancies Rate FTE Allowance

Distribution 247.5 16.0 6.5% 260.0 16.8 4.3 12.5 4.8% 91,026$ 1,137,825$

Transmission & Network 45.9 7.6 16.6% 42.9 7.1 0.0 7.1 16.6% 83,926$ 595,875$

Wholesale Services 116.0 0.0 0.0% 129.6 0.0 0.0 0.0 0.0% 72,010$ -$

General 7.7 3.8 49.4% 3.0 1.5 0.0 1.5 50.0% 72,900$ 109,350$

Executive and Administration 8.8 0.0 0.0% 7.6 0.0 0.0 0.0 0.0% 184,457$ -$

Human Resources, Legal, Facilities 23.4 0.0 0.0% 22.6 0.0 0.0 0.0 0.0% 116,026$ -$

Information Services 40.9 1.9 4.6% 36.9 1.7 0.0 1.7 4.6% 111,262$ 189,145$

Finance and Supply Chain Management 48.8 1.8 3.7% 37.8 1.4 0.0 1.4 3.7% 92,946$ 130,124$

Regulatory 9.2 1.2 13.0% 8.4 1.1 0.0 1.1 13.1% 137,257$ 150,983$

548.2 32.3 5.9% 548.8 29.6 4.3 25.3 4.6% 2,313,302$

EPC Forecast vacancy allowance $1,500,000

Reduction in EPC Revenue Requirement $813,302

Sources:

Column (A) - Exhibit 268 (Revised BR.EPC-4(d) Attachment)

Column (B) - CG Argument (Page 64)

Column (D) - Exhibit 244 (Revised Schedule 4.4)

Column (F) - CG Argument (Page 13)

Column (I) - Exhibit 206 (CG.EPC-47(b) Attachment)

(2005) EUB Decision 2006-002 (January 13, 2006)


ENMAX Power CorporationDistribution

Board Determined Vacant Position Allowance2006

(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)= (B)/(A) = (C)*(D) = (E)-(F) = (G)/(D) = (G)*(I)

2004 CG EPC 2006 CG 2006 Per Board 2006 2006Allocated Recommended Vacancy 2006 Calculated Recommended Final Vacancy Cost Per Vacancy

Function Complement Vacancies Rate Forecast Vacancies Backfilling Vacancies Rate FTE Allowance

Distribution 247.5 16.0 6.5% 260.6 16.8 8.5 8.3 3.2% 93,538$ 776,365$

Transmission & Network 45.9 7.6 16.6% 43.6 7.2 0.0 7.2 16.5% 85,812$ 617,846$

Wholesale Services 116.0 0.0 0.0% 133.0 0.0 0.0 0.0 0.0% 74,370$ -$

General 7.7 3.8 49.4% 3.5 1.7 0.0 1.7 48.6% 68,219$ 115,972$

Executive and Administration 8.8 0.0 0.0% 7.5 0.0 0.0 0.0 0.0% 194,052$ -$

Human Resources, Legal, Facilities 23.4 0.0 0.0% 23.1 0.0 0.0 0.0 0.0% 119,460$ -$

Information Services 40.9 1.9 4.6% 39.9 1.9 0.0 1.9 4.8% 128,164$ 243,512$

Finance and Supply Chain Management 48.8 1.8 3.7% 38.5 1.4 0.0 1.4 3.6% 95,373$ 133,522$

Regulatory 9.2 1.2 13.0% 8.4 1.1 0.0 1.1 13.1% 144,050$ 158,455$

548.2 32.3 5.9% 558.1 30.1 8.5 21.6 3.9% 2,045,673$

EPC Forecast vacancy allowance $1,700,000

Reduction in EPC Revenue Requirement $345,673

Sources:

Column (A) - Exhibit 268 (Revised BR.EPC-4(d) Attachment)

Column (B) - CG Argument (Page 64)

Column (D) - Exhibit 244 (Revised Schedule 4.4)

Column (F) - CG Argument (Page 13)

Column (I) - Exhibit 206 (CG.EPC-47(b) Attachment)

(2006) EUB Decision 2006-002 (January 13, 2006)


ENMAX Power CorporationBoard Test on Salaries and Wages - Distribution Function

$m

Salaries and Wages - 2004 Actual 21.8$ (Exh 211 - Sch 4.2.1)

Add: Inflation at 4.0% 0.9

Add: 1/4 of 17 Positions Times Annual Salary 0.4 (Salary Information - Exhibit 206)

Add: Vacant Position Allowance - Updated 1.1 (Appendix 4 Of Decision)

Board Test - Salaries and Wages - 2005 24.2$

EPC Application 24.5 (Exh 013 - Sch 4.2.1)

Difference (0.3)$


Add: Inflation of 4.0% 1.0

Add: 1/4 of 17 Positions Times Annual Salary 0.4 (Salary Information - Exhibit 206)


EPC Application 25.2 (Exh 013 - Sch 4.2.1)

Difference 0.3$

(2005 and 2006) EUB Decision 2006-002 (January 13, 2006)


ENMAX Power CorporationBoard Determined Salaries and Wages Reduction

Management/Professional Employees

2005 2006

Total forecasted management/professional employees (A) 146.2 149.0(Exh 137 - Attachment to TM.EPC-9)

Average total remuneration (B) 117,800$ 117,800$ (EPC Argument - Page 22)

Total forecasted management/professional salaries before inflation (C) = (A)*(B) 17,222,360$ 17,552,200$

Reduction (D) 1% 1%

Board determined reduction (E) = (C)*(D) 172,224$ 175,522$

(2005 and 2006) EUB Decision 2006-002 (January 13, 2006)


ENMAX Power CorporationBoard Determined Salaries and Wages Reduction

Executive Compensation

EPC DTBase Pay Benefits

2004 Decision (A) 374,000$ 68,000$ (Exh 326-20)

FTEs - 2004 Decision (B) 1.47 1.47 (Exh 326-20)

Average - 2004 Decision (C) = (A)/(B) 254,422$ 46,259$

Inflation rate approved by Board (D) 4.0% 4.0%

# of forecasted FTEs for 2005 (E) 2.01 2.01 (Exh 326-20)

Board approved - 2005 (F) = (C)*(1+D)*(E) 531,843$ 96,699$

EPC DT Forecast (G) 619,000$ 112,000$ (Exh 326-20)

Board determined reduction - 2005 (H) = (F)-(G) (87,157)$ (15,301)$

Board approved - 2005 (I) = (F) 531,843$ 96,699$

Inflation rate approved by Board (J) = (D) 4.0% 4.0%

Board approved - 2006 (K) = (I)*(1+J) 553,117$ 100,567$

EPC DT Forecast (L) 650,000$ 118,000$ (Exh 326-20)

Board determined reduction - 2006 (M) = (K)-(L) (96,883)$ (17,433)$

(EPC DT) EUB Decision 2006-002 (January 13, 2006)

2005-2006 DT ENMAX Power CorporationAppendix 8

Page 1 of 23

Ex 326-5 Aid to Undertaking Response of Mr. Kennedy at Transcript Volume 4, page 935 ENMAX POWER CORPORATION

Calculation of the Annual Accrual Factors and Accrued Factors as at December 31, 2003 for a 15-R3 Iowa Curve

Ave ELG Beg of interval End of Interval Average Accrual Factors Applicable to each vintageVintage Beg End Life ELG Survivors Survivors Survivors 2003 2002 2001 2000

Column (B) C (D) (E) (F) (G) (H) (I) (J) (K) (L) (M)

2003 0 0.5 0.25 0.06716 0.01679 400.00% 100.00000 99.93284 99.96642 0.06715705%2002 0.5 1.5 1 0.17828 0.17828 100.00% 99.93284 99.75457 99.84371 0.08913765% 0.08913765%2001 1.5 2.5 2 0.28854 0.57708 50.00% 99.75457 99.46603 99.61030 0.07213439% 0.14426878% 0.07213439%2000 2.5 3.5 3 0.44677 1.34031 33.33% 99.46603 99.01926 99.24265 0.07446163% 0.14892326% 0.14892326% 0.07446163%1999 3.5 4.5 4 0.66410 2.65641 25.00% 99.01926 98.35516 98.68721 0.08301267% 0.16602534% 0.16602534% 0.16602534%1998 4.5 5.5 5 0.95018 4.75092 20.00% 98.35516 97.40497 97.88007 0.09501845% 0.19003690% 0.19003690% 0.19003690%1997 5.5 6.5 6 1.31727 7.90360 16.67% 97.40497 96.08771 96.74634 0.10977229% 0.21954458% 0.21954458% 0.21954458%1996 6.5 7.5 7 1.77418 12.41924 14.29% 96.08771 94.31353 95.20062 0.12672694% 0.25345389% 0.25345389% 0.25345389%1995 7.5 8.5 8 2.32660 18.61282 12.50% 94.31353 91.98693 93.15023 0.14541267% 0.29082533% 0.29082533% 0.29082533%1994 8.5 9.5 9 3.00360 27.03237 11.11% 91.98693 88.98333 90.48513 0.16686651% 0.33373302% 0.33373302% 0.33373302%1993 9.5 10.5 10 3.81040 38.10396 10.00% 88.98333 85.17293 87.07813 0.19051978% 0.38103956% 0.38103956% 0.38103956%1992 10.5 11.5 11 4.77828 52.56112 9.09% 85.17293 80.39465 82.78379 0.21719470% 0.43438941% 0.43438941% 0.43438941%1991 11.5 12.5 12 5.92539 71.10471 8.33% 80.39465 74.46926 77.43195 0.24689135% 0.49378270% 0.49378270% 0.49378270%1990 12.5 13.5 13 7.21685 93.81908 7.69% 74.46926 67.25241 70.86083 0.27757125% 0.55514250% 0.55514250% 0.55514250%1989 13.5 14.5 14 8.52818 119.39445 7.14% 67.25241 58.72423 62.98832 0.30457768% 0.60915536% 0.60915536% 0.60915536%1988 14.5 15.5 15 9.63980 144.59698 6.67% 58.72423 49.08443 53.90433 0.32132662% 0.64265325% 0.64265325% 0.64265325%1987 15.5 16.5 16 10.23847 163.81552 6.25% 49.08443 38.84596 43.96520 0.31995219% 0.63990437% 0.63990437% 0.63990437%1986 16.5 17.5 17 10.05785 170.98345 5.88% 38.84596 28.78811 33.81704 0.29581911% 0.59163822% 0.59163822% 0.59163822%1985 17.5 18.5 18 9.01873 162.33721 5.56% 28.78811 19.76938 24.27875 0.25052038% 0.50104076% 0.50104076% 0.50104076%1984 18.5 19.5 19 7.32224 139.12264 5.26% 19.76938 12.44713 16.10826 0.19269064% 0.38538129% 0.38538129% 0.38538129%1983 19.5 20.5 20 5.38580 107.71609 5.00% 12.44713 7.06133 9.75423 0.13464511% 0.26929023% 0.26929023% 0.26929023%1982 20.5 21.5 21 3.58517 75.28860 4.76% 7.06133 3.47616 5.26874 0.08536122% 0.17072244% 0.17072244% 0.17072244%1981 21.5 22.5 22 2.12166 46.67642 4.55% 3.47616 1.35450 2.41533 0.04821945% 0.09643889% 0.09643889% 0.09643889%1980 22.5 23.5 23 1.03650 23.83941 4.35% 1.35450 0.31801 0.83625 0.02253252% 0.04506504% 0.04506504% 0.04506504%1979 23.5 24.5 24 0.29491 7.07778 4.17% 0.31801 0.02310 0.17055 0.00614391% 0.01228782% 0.01228782% 0.01228782%1978 24.5 25.4 24.9625 0.02310 0.57661 4.01% 0.02310 0.00000 0.01155 0.00046268% 0.00092536% 0.00092536% 0.00092536%

100 15 3.94412885% 7.66480595% 7.50353391% 7.35693789%Annual Accrual Factor Per Board 3.95000000% 7.68000000% 7.53000000% 7.41000000%Annual Accrual Factor Per Gannet Fleming 7.74000000% 7.55000000% 7.43000000% 7.32000000%Annual Accrual Factor Overstatement 1.96 0.98 0.99 0.99

Calculations:Column D = Figures from Iowa Curve 15 R3 belowColumn E = Life multiplied by the ELG Group ( the sum of this column equals the area under the Iowa curve or the Average Service Life Estimate)Column F = 1/LifeColumn H = Balance of survivors at the end of the age interval (prior balance - ELG group)Column I = mid point average of the survivors during the age intervalColumn J through AI= (1/Life)*ELG group for each vintage from 2003 back to 1978Annual Accrual Factor = Sum of column J weighted by the appropriate mid point average of survivors at each age intervalColumn AK = sum of the column J though AI factors for each age intervalColumn AL = December 31, 2003 Accrued Factors = sum of the column J through AI factors divided by the remaining ELG groups Column AN = December 31, 2003 Accrued Factors as indicated at page II-12 of the Gannett Fleming report

Age Interval

(15R3 per Board) EUB Decision 2006-002 (January 13, 2006)


Page 2 of 23



Ave ELG Beg of interval End of Interval AverageVintage Beg End Life ELG Survivors Survivors Survivors

Column (B) C (D) (E) (F) (G) (H) (I)

2003 0 0.5 0.25 0.06716 0.01679 400.00% 100.00000 99.93284 99.966422002 0.5 1.5 1 0.17828 0.17828 100.00% 99.93284 99.75457 99.843712001 1.5 2.5 2 0.28854 0.57708 50.00% 99.75457 99.46603 99.610302000 2.5 3.5 3 0.44677 1.34031 33.33% 99.46603 99.01926 99.242651999 3.5 4.5 4 0.66410 2.65641 25.00% 99.01926 98.35516 98.687211998 4.5 5.5 5 0.95018 4.75092 20.00% 98.35516 97.40497 97.880071997 5.5 6.5 6 1.31727 7.90360 16.67% 97.40497 96.08771 96.746341996 6.5 7.5 7 1.77418 12.41924 14.29% 96.08771 94.31353 95.200621995 7.5 8.5 8 2.32660 18.61282 12.50% 94.31353 91.98693 93.150231994 8.5 9.5 9 3.00360 27.03237 11.11% 91.98693 88.98333 90.485131993 9.5 10.5 10 3.81040 38.10396 10.00% 88.98333 85.17293 87.078131992 10.5 11.5 11 4.77828 52.56112 9.09% 85.17293 80.39465 82.783791991 11.5 12.5 12 5.92539 71.10471 8.33% 80.39465 74.46926 77.431951990 12.5 13.5 13 7.21685 93.81908 7.69% 74.46926 67.25241 70.860831989 13.5 14.5 14 8.52818 119.39445 7.14% 67.25241 58.72423 62.988321988 14.5 15.5 15 9.63980 144.59698 6.67% 58.72423 49.08443 53.904331987 15.5 16.5 16 10.23847 163.81552 6.25% 49.08443 38.84596 43.965201986 16.5 17.5 17 10.05785 170.98345 5.88% 38.84596 28.78811 33.817041985 17.5 18.5 18 9.01873 162.33721 5.56% 28.78811 19.76938 24.278751984 18.5 19.5 19 7.32224 139.12264 5.26% 19.76938 12.44713 16.108261983 19.5 20.5 20 5.38580 107.71609 5.00% 12.44713 7.06133 9.754231982 20.5 21.5 21 3.58517 75.28860 4.76% 7.06133 3.47616 5.268741981 21.5 22.5 22 2.12166 46.67642 4.55% 3.47616 1.35450 2.415331980 22.5 23.5 23 1.03650 23.83941 4.35% 1.35450 0.31801 0.836251979 23.5 24.5 24 0.29491 7.07778 4.17% 0.31801 0.02310 0.170551978 24.5 25.4 24.9625 0.02310 0.57661 4.01% 0.02310 0.00000 0.01155

100 15Annual Accrual Factor Per BoardAnnual Accrual Factor Per Gannet FlemingAnnual Accrual Factor Overstatement


Age Interval Accrual Factors Applicable to each vintage1999 1998 1997 1996(N) (O) (P) (Q)

0.08301267%0.19003690% 0.09501845%0.21954458% 0.21954458% 0.10977229%0.25345389% 0.25345389% 0.25345389% 0.12672694%0.29082533% 0.29082533% 0.29082533% 0.29082533%0.33373302% 0.33373302% 0.33373302% 0.33373302%0.38103956% 0.38103956% 0.38103956% 0.38103956%0.43438941% 0.43438941% 0.43438941% 0.43438941%0.49378270% 0.49378270% 0.49378270% 0.49378270%0.55514250% 0.55514250% 0.55514250% 0.55514250%0.60915536% 0.60915536% 0.60915536% 0.60915536%0.64265325% 0.64265325% 0.64265325% 0.64265325%0.63990437% 0.63990437% 0.63990437% 0.63990437%0.59163822% 0.59163822% 0.59163822% 0.59163822%0.50104076% 0.50104076% 0.50104076% 0.50104076%0.38538129% 0.38538129% 0.38538129% 0.38538129%0.26929023% 0.26929023% 0.26929023% 0.26929023%0.17072244% 0.17072244% 0.17072244% 0.17072244%0.09643889% 0.09643889% 0.09643889% 0.09643889%0.04506504% 0.04506504% 0.04506504% 0.04506504%0.01228782% 0.01228782% 0.01228782% 0.01228782%0.00092536% 0.00092536% 0.00092536% 0.00092536%

7.19946359% 7.02143247% 6.81664172% 6.58014249%7.30000000% 7.17000000% 7.05000000% 6.91000000%

7.20000000% 7.08000000% 6.95000000% 6.82000000%0.99 0.99 0.99 0.99



Page 3 of 23




Column (B) C (D) (E) (F) (G) (H) (I)

2003 0 0.5 0.25 0.06716 0.01679 400.00% 100.00000 99.93284 99.966422002 0.5 1.5 1 0.17828 0.17828 100.00% 99.93284 99.75457 99.843712001 1.5 2.5 2 0.28854 0.57708 50.00% 99.75457 99.46603 99.610302000 2.5 3.5 3 0.44677 1.34031 33.33% 99.46603 99.01926 99.242651999 3.5 4.5 4 0.66410 2.65641 25.00% 99.01926 98.35516 98.687211998 4.5 5.5 5 0.95018 4.75092 20.00% 98.35516 97.40497 97.880071997 5.5 6.5 6 1.31727 7.90360 16.67% 97.40497 96.08771 96.746341996 6.5 7.5 7 1.77418 12.41924 14.29% 96.08771 94.31353 95.200621995 7.5 8.5 8 2.32660 18.61282 12.50% 94.31353 91.98693 93.150231994 8.5 9.5 9 3.00360 27.03237 11.11% 91.98693 88.98333 90.485131993 9.5 10.5 10 3.81040 38.10396 10.00% 88.98333 85.17293 87.078131992 10.5 11.5 11 4.77828 52.56112 9.09% 85.17293 80.39465 82.783791991 11.5 12.5 12 5.92539 71.10471 8.33% 80.39465 74.46926 77.431951990 12.5 13.5 13 7.21685 93.81908 7.69% 74.46926 67.25241 70.860831989 13.5 14.5 14 8.52818 119.39445 7.14% 67.25241 58.72423 62.988321988 14.5 15.5 15 9.63980 144.59698 6.67% 58.72423 49.08443 53.904331987 15.5 16.5 16 10.23847 163.81552 6.25% 49.08443 38.84596 43.965201986 16.5 17.5 17 10.05785 170.98345 5.88% 38.84596 28.78811 33.817041985 17.5 18.5 18 9.01873 162.33721 5.56% 28.78811 19.76938 24.278751984 18.5 19.5 19 7.32224 139.12264 5.26% 19.76938 12.44713 16.108261983 19.5 20.5 20 5.38580 107.71609 5.00% 12.44713 7.06133 9.754231982 20.5 21.5 21 3.58517 75.28860 4.76% 7.06133 3.47616 5.268741981 21.5 22.5 22 2.12166 46.67642 4.55% 3.47616 1.35450 2.415331980 22.5 23.5 23 1.03650 23.83941 4.35% 1.35450 0.31801 0.836251979 23.5 24.5 24 0.29491 7.07778 4.17% 0.31801 0.02310 0.170551978 24.5 25.4 24.9625 0.02310 0.57661 4.01% 0.02310 0.00000 0.01155



Age Interval Accrual Factors Applicable to each vintage1995 1994 1993 1992

R (S) (T) (U)

0.14541267%0.33373302% 0.16686651%0.38103956% 0.38103956% 0.19051978%0.43438941% 0.43438941% 0.43438941% 0.21719470%0.49378270% 0.49378270% 0.49378270% 0.49378270%0.55514250% 0.55514250% 0.55514250% 0.55514250%0.60915536% 0.60915536% 0.60915536% 0.60915536%0.64265325% 0.64265325% 0.64265325% 0.64265325%0.63990437% 0.63990437% 0.63990437% 0.63990437%0.59163822% 0.59163822% 0.59163822% 0.59163822%0.50104076% 0.50104076% 0.50104076% 0.50104076%0.38538129% 0.38538129% 0.38538129% 0.38538129%0.26929023% 0.26929023% 0.26929023% 0.26929023%0.17072244% 0.17072244% 0.17072244% 0.17072244%0.09643889% 0.09643889% 0.09643889% 0.09643889%0.04506504% 0.04506504% 0.04506504% 0.04506504%0.01228782% 0.01228782% 0.01228782% 0.01228782%0.00092536% 0.00092536% 0.00092536% 0.00092536%

6.30800288% 5.99572370% 5.63833742% 5.23062293%6.77000000% 6.63000000% 6.48000000% 6.32000000%

6.68000000% 6.53000000% 6.38000000% 6.22000000%0.99 0.98 0.98 0.98



Page 4 of 23




Column (B) C (D) (E) (F) (G) (H) (I)

2003 0 0.5 0.25 0.06716 0.01679 400.00% 100.00000 99.93284 99.966422002 0.5 1.5 1 0.17828 0.17828 100.00% 99.93284 99.75457 99.843712001 1.5 2.5 2 0.28854 0.57708 50.00% 99.75457 99.46603 99.610302000 2.5 3.5 3 0.44677 1.34031 33.33% 99.46603 99.01926 99.242651999 3.5 4.5 4 0.66410 2.65641 25.00% 99.01926 98.35516 98.687211998 4.5 5.5 5 0.95018 4.75092 20.00% 98.35516 97.40497 97.880071997 5.5 6.5 6 1.31727 7.90360 16.67% 97.40497 96.08771 96.746341996 6.5 7.5 7 1.77418 12.41924 14.29% 96.08771 94.31353 95.200621995 7.5 8.5 8 2.32660 18.61282 12.50% 94.31353 91.98693 93.150231994 8.5 9.5 9 3.00360 27.03237 11.11% 91.98693 88.98333 90.485131993 9.5 10.5 10 3.81040 38.10396 10.00% 88.98333 85.17293 87.078131992 10.5 11.5 11 4.77828 52.56112 9.09% 85.17293 80.39465 82.783791991 11.5 12.5 12 5.92539 71.10471 8.33% 80.39465 74.46926 77.431951990 12.5 13.5 13 7.21685 93.81908 7.69% 74.46926 67.25241 70.860831989 13.5 14.5 14 8.52818 119.39445 7.14% 67.25241 58.72423 62.988321988 14.5 15.5 15 9.63980 144.59698 6.67% 58.72423 49.08443 53.904331987 15.5 16.5 16 10.23847 163.81552 6.25% 49.08443 38.84596 43.965201986 16.5 17.5 17 10.05785 170.98345 5.88% 38.84596 28.78811 33.817041985 17.5 18.5 18 9.01873 162.33721 5.56% 28.78811 19.76938 24.278751984 18.5 19.5 19 7.32224 139.12264 5.26% 19.76938 12.44713 16.108261983 19.5 20.5 20 5.38580 107.71609 5.00% 12.44713 7.06133 9.754231982 20.5 21.5 21 3.58517 75.28860 4.76% 7.06133 3.47616 5.268741981 21.5 22.5 22 2.12166 46.67642 4.55% 3.47616 1.35450 2.415331980 22.5 23.5 23 1.03650 23.83941 4.35% 1.35450 0.31801 0.836251979 23.5 24.5 24 0.29491 7.07778 4.17% 0.31801 0.02310 0.170551978 24.5 25.4 24.9625 0.02310 0.57661 4.01% 0.02310 0.00000 0.01155



Age Interval Accrual Factors Applicable to each vintage1991 1990 1989 1988(V) (W) (X) (Y)

0.24689135%0.55514250% 0.27757125%0.60915536% 0.60915536% 0.30457768%0.64265325% 0.64265325% 0.64265325% 0.32132662%0.63990437% 0.63990437% 0.63990437% 0.63990437%0.59163822% 0.59163822% 0.59163822% 0.59163822%0.50104076% 0.50104076% 0.50104076% 0.50104076%0.38538129% 0.38538129% 0.38538129% 0.38538129%0.26929023% 0.26929023% 0.26929023% 0.26929023%0.17072244% 0.17072244% 0.17072244% 0.17072244%0.09643889% 0.09643889% 0.09643889% 0.09643889%0.04506504% 0.04506504% 0.04506504% 0.04506504%0.01228782% 0.01228782% 0.01228782% 0.01228782%0.00092536% 0.00092536% 0.00092536% 0.00092536%

4.76653688% 4.24207428% 3.65992535% 3.03402105%6.16000000% 5.99000000% 5.81000000% 5.63000000%

6.06000000% 5.89000000% 5.71000000% 5.53000000%0.98 0.98 0.98 0.98



Page 5 of 23




Column (B) C (D) (E) (F) (G) (H) (I)

2003 0 0.5 0.25 0.06716 0.01679 400.00% 100.00000 99.93284 99.966422002 0.5 1.5 1 0.17828 0.17828 100.00% 99.93284 99.75457 99.843712001 1.5 2.5 2 0.28854 0.57708 50.00% 99.75457 99.46603 99.610302000 2.5 3.5 3 0.44677 1.34031 33.33% 99.46603 99.01926 99.242651999 3.5 4.5 4 0.66410 2.65641 25.00% 99.01926 98.35516 98.687211998 4.5 5.5 5 0.95018 4.75092 20.00% 98.35516 97.40497 97.880071997 5.5 6.5 6 1.31727 7.90360 16.67% 97.40497 96.08771 96.746341996 6.5 7.5 7 1.77418 12.41924 14.29% 96.08771 94.31353 95.200621995 7.5 8.5 8 2.32660 18.61282 12.50% 94.31353 91.98693 93.150231994 8.5 9.5 9 3.00360 27.03237 11.11% 91.98693 88.98333 90.485131993 9.5 10.5 10 3.81040 38.10396 10.00% 88.98333 85.17293 87.078131992 10.5 11.5 11 4.77828 52.56112 9.09% 85.17293 80.39465 82.783791991 11.5 12.5 12 5.92539 71.10471 8.33% 80.39465 74.46926 77.431951990 12.5 13.5 13 7.21685 93.81908 7.69% 74.46926 67.25241 70.860831989 13.5 14.5 14 8.52818 119.39445 7.14% 67.25241 58.72423 62.988321988 14.5 15.5 15 9.63980 144.59698 6.67% 58.72423 49.08443 53.904331987 15.5 16.5 16 10.23847 163.81552 6.25% 49.08443 38.84596 43.965201986 16.5 17.5 17 10.05785 170.98345 5.88% 38.84596 28.78811 33.817041985 17.5 18.5 18 9.01873 162.33721 5.56% 28.78811 19.76938 24.278751984 18.5 19.5 19 7.32224 139.12264 5.26% 19.76938 12.44713 16.108261983 19.5 20.5 20 5.38580 107.71609 5.00% 12.44713 7.06133 9.754231982 20.5 21.5 21 3.58517 75.28860 4.76% 7.06133 3.47616 5.268741981 21.5 22.5 22 2.12166 46.67642 4.55% 3.47616 1.35450 2.415331980 22.5 23.5 23 1.03650 23.83941 4.35% 1.35450 0.31801 0.836251979 23.5 24.5 24 0.29491 7.07778 4.17% 0.31801 0.02310 0.170551978 24.5 25.4 24.9625 0.02310 0.57661 4.01% 0.02310 0.00000 0.01155



Age Interval Accrual Factors Applicable to each vintage1987 1986 1985 1984(A) (AA) (AB) (AC)

0.31995219%0.59163822% 0.29581911%0.50104076% 0.50104076% 0.25052038%0.38538129% 0.38538129% 0.38538129% 0.19269064%0.26929023% 0.26929023% 0.26929023% 0.26929023%0.17072244% 0.17072244% 0.17072244% 0.17072244%0.09643889% 0.09643889% 0.09643889% 0.09643889%0.04506504% 0.04506504% 0.04506504% 0.04506504%0.01228782% 0.01228782% 0.01228782% 0.01228782%0.00092536% 0.00092536% 0.00092536% 0.00092536%

2.39274224% 1.77697094% 1.23063145% 0.78742042%5.44000000% 5.25000000% 5.07000000% 4.89000000%

5.34000000% 5.16000000% 4.97000000% 4.80000000%0.98 0.98 0.98 0.98



Page 6 of 23




Column (B) C (D) (E) (F) (G) (H) (I)

2003 0 0.5 0.25 0.06716 0.01679 400.00% 100.00000 99.93284 99.966422002 0.5 1.5 1 0.17828 0.17828 100.00% 99.93284 99.75457 99.843712001 1.5 2.5 2 0.28854 0.57708 50.00% 99.75457 99.46603 99.610302000 2.5 3.5 3 0.44677 1.34031 33.33% 99.46603 99.01926 99.242651999 3.5 4.5 4 0.66410 2.65641 25.00% 99.01926 98.35516 98.687211998 4.5 5.5 5 0.95018 4.75092 20.00% 98.35516 97.40497 97.880071997 5.5 6.5 6 1.31727 7.90360 16.67% 97.40497 96.08771 96.746341996 6.5 7.5 7 1.77418 12.41924 14.29% 96.08771 94.31353 95.200621995 7.5 8.5 8 2.32660 18.61282 12.50% 94.31353 91.98693 93.150231994 8.5 9.5 9 3.00360 27.03237 11.11% 91.98693 88.98333 90.485131993 9.5 10.5 10 3.81040 38.10396 10.00% 88.98333 85.17293 87.078131992 10.5 11.5 11 4.77828 52.56112 9.09% 85.17293 80.39465 82.783791991 11.5 12.5 12 5.92539 71.10471 8.33% 80.39465 74.46926 77.431951990 12.5 13.5 13 7.21685 93.81908 7.69% 74.46926 67.25241 70.860831989 13.5 14.5 14 8.52818 119.39445 7.14% 67.25241 58.72423 62.988321988 14.5 15.5 15 9.63980 144.59698 6.67% 58.72423 49.08443 53.904331987 15.5 16.5 16 10.23847 163.81552 6.25% 49.08443 38.84596 43.965201986 16.5 17.5 17 10.05785 170.98345 5.88% 38.84596 28.78811 33.817041985 17.5 18.5 18 9.01873 162.33721 5.56% 28.78811 19.76938 24.278751984 18.5 19.5 19 7.32224 139.12264 5.26% 19.76938 12.44713 16.108261983 19.5 20.5 20 5.38580 107.71609 5.00% 12.44713 7.06133 9.754231982 20.5 21.5 21 3.58517 75.28860 4.76% 7.06133 3.47616 5.268741981 21.5 22.5 22 2.12166 46.67642 4.55% 3.47616 1.35450 2.415331980 22.5 23.5 23 1.03650 23.83941 4.35% 1.35450 0.31801 0.836251979 23.5 24.5 24 0.29491 7.07778 4.17% 0.31801 0.02310 0.170551978 24.5 25.4 24.9625 0.02310 0.57661 4.01% 0.02310 0.00000 0.01155



Age Interval Accrual Factors Applicable to each vintage1983 1982 1981 1980(AD) (AE) (AF) (AG)

0.13464511%0.17072244% 0.08536122%0.09643889% 0.09643889% 0.04821945%0.04506504% 0.04506504% 0.04506504% 0.02253252%0.01228782% 0.01228782% 0.01228782% 0.01228782%0.00092536% 0.00092536% 0.00092536% 0.00092536%

0.46008467% 0.24007833% 0.10649766% 0.03574570%4.72000000% 4.56000000% 4.41000000% 4.27000000%

4.63000000% 4.48000000% 4.34000000% 4.20000000%0.98 0.98 0.98 0.98



Page 7 of 23




Column (B) C (D) (E) (F) (G) (H) (I)

2003 0 0.5 0.25 0.06716 0.01679 400.00% 100.00000 99.93284 99.966422002 0.5 1.5 1 0.17828 0.17828 100.00% 99.93284 99.75457 99.843712001 1.5 2.5 2 0.28854 0.57708 50.00% 99.75457 99.46603 99.610302000 2.5 3.5 3 0.44677 1.34031 33.33% 99.46603 99.01926 99.242651999 3.5 4.5 4 0.66410 2.65641 25.00% 99.01926 98.35516 98.687211998 4.5 5.5 5 0.95018 4.75092 20.00% 98.35516 97.40497 97.880071997 5.5 6.5 6 1.31727 7.90360 16.67% 97.40497 96.08771 96.746341996 6.5 7.5 7 1.77418 12.41924 14.29% 96.08771 94.31353 95.200621995 7.5 8.5 8 2.32660 18.61282 12.50% 94.31353 91.98693 93.150231994 8.5 9.5 9 3.00360 27.03237 11.11% 91.98693 88.98333 90.485131993 9.5 10.5 10 3.81040 38.10396 10.00% 88.98333 85.17293 87.078131992 10.5 11.5 11 4.77828 52.56112 9.09% 85.17293 80.39465 82.783791991 11.5 12.5 12 5.92539 71.10471 8.33% 80.39465 74.46926 77.431951990 12.5 13.5 13 7.21685 93.81908 7.69% 74.46926 67.25241 70.860831989 13.5 14.5 14 8.52818 119.39445 7.14% 67.25241 58.72423 62.988321988 14.5 15.5 15 9.63980 144.59698 6.67% 58.72423 49.08443 53.904331987 15.5 16.5 16 10.23847 163.81552 6.25% 49.08443 38.84596 43.965201986 16.5 17.5 17 10.05785 170.98345 5.88% 38.84596 28.78811 33.817041985 17.5 18.5 18 9.01873 162.33721 5.56% 28.78811 19.76938 24.278751984 18.5 19.5 19 7.32224 139.12264 5.26% 19.76938 12.44713 16.108261983 19.5 20.5 20 5.38580 107.71609 5.00% 12.44713 7.06133 9.754231982 20.5 21.5 21 3.58517 75.28860 4.76% 7.06133 3.47616 5.268741981 21.5 22.5 22 2.12166 46.67642 4.55% 3.47616 1.35450 2.415331980 22.5 23.5 23 1.03650 23.83941 4.35% 1.35450 0.31801 0.836251979 23.5 24.5 24 0.29491 7.07778 4.17% 0.31801 0.02310 0.170551978 24.5 25.4 24.9625 0.02310 0.57661 4.01% 0.02310 0.00000 0.01155



Age Interval

Accrued FactorAccrual Factors Applicable Check

to each vintage ELG Accruals1979 1978(AH) (AI)

0.0671570470.1782753090.2885375630.4467697660.6641013580.9501845241.3172674971.7741772062.3266026703.0035971503.8103956244.7782835035.9253923557.2168524948.5281750029.639798726

10.23846999910.0578497409.0187337277.3222444595.3858045173.5851713172.1216556631.036495873

0.00614391% 0.2949076970.00092536% 0.00046268% 0.023133916

100.0000.00706927% 0.00046268% 100.00004.14000000% 4.01000000%

4.08000000% 3.97220000%0.99 0.99



Page 8 of 23




Column (B) C (D) (E) (F) (G) (H) (I)

2003 0 0.5 0.25 0.06716 0.01679 400.00% 100.00000 99.93284 99.966422002 0.5 1.5 1 0.17828 0.17828 100.00% 99.93284 99.75457 99.843712001 1.5 2.5 2 0.28854 0.57708 50.00% 99.75457 99.46603 99.610302000 2.5 3.5 3 0.44677 1.34031 33.33% 99.46603 99.01926 99.242651999 3.5 4.5 4 0.66410 2.65641 25.00% 99.01926 98.35516 98.687211998 4.5 5.5 5 0.95018 4.75092 20.00% 98.35516 97.40497 97.880071997 5.5 6.5 6 1.31727 7.90360 16.67% 97.40497 96.08771 96.746341996 6.5 7.5 7 1.77418 12.41924 14.29% 96.08771 94.31353 95.200621995 7.5 8.5 8 2.32660 18.61282 12.50% 94.31353 91.98693 93.150231994 8.5 9.5 9 3.00360 27.03237 11.11% 91.98693 88.98333 90.485131993 9.5 10.5 10 3.81040 38.10396 10.00% 88.98333 85.17293 87.078131992 10.5 11.5 11 4.77828 52.56112 9.09% 85.17293 80.39465 82.783791991 11.5 12.5 12 5.92539 71.10471 8.33% 80.39465 74.46926 77.431951990 12.5 13.5 13 7.21685 93.81908 7.69% 74.46926 67.25241 70.860831989 13.5 14.5 14 8.52818 119.39445 7.14% 67.25241 58.72423 62.988321988 14.5 15.5 15 9.63980 144.59698 6.67% 58.72423 49.08443 53.904331987 15.5 16.5 16 10.23847 163.81552 6.25% 49.08443 38.84596 43.965201986 16.5 17.5 17 10.05785 170.98345 5.88% 38.84596 28.78811 33.817041985 17.5 18.5 18 9.01873 162.33721 5.56% 28.78811 19.76938 24.278751984 18.5 19.5 19 7.32224 139.12264 5.26% 19.76938 12.44713 16.108261983 19.5 20.5 20 5.38580 107.71609 5.00% 12.44713 7.06133 9.754231982 20.5 21.5 21 3.58517 75.28860 4.76% 7.06133 3.47616 5.268741981 21.5 22.5 22 2.12166 46.67642 4.55% 3.47616 1.35450 2.415331980 22.5 23.5 23 1.03650 23.83941 4.35% 1.35450 0.31801 0.836251979 23.5 24.5 24 0.29491 7.07778 4.17% 0.31801 0.02310 0.170551978 24.5 25.4 24.9625 0.02310 0.57661 4.01% 0.02310 0.00000 0.01155



Age IntervalAccrued Factor Accrued Factor

Per Board Per Gannet FlemingVintage Page II-12 of GF Report

0.03880000 2003 0.03870.11390000 2002 0.11330.18680000 2001 0.18580.25740000 2000 0.25620.32560000 1999 0.32400.39110000 1998 0.38940.45370000 1997 0.45180.51320000 1996 0.51150.56950000 1995 0.56780.62230000 1994 0.62040.67160000 1993 0.66990.71710000 1992 0.71530.75860000 1991 0.75750.79580000 1990 0.79520.82850000 1989 0.82800.85660000 1988 0.85720.88040000 1987 0.88110.90040000 1986 0.90300.91720000 1985 0.91950.93170000 1984 0.93600.94480000 1983 0.94920.95690000 1982 0.96320.96810000 1981 0.97650.97640000 1980 0.98700.98150000 1979 0.99961.00000000 1978 1.0000



Page 9 of 23




Column (B) C (D) (E) (F) (G) (H) (I)

2003 0 0.5 0.25 0.06716 0.01679 400.00% 100.00000 99.93284 99.966422002 0.5 1.5 1 0.17828 0.17828 100.00% 99.93284 99.75457 99.843712001 1.5 2.5 2 0.28854 0.57708 50.00% 99.75457 99.46603 99.610302000 2.5 3.5 3 0.44677 1.34031 33.33% 99.46603 99.01926 99.242651999 3.5 4.5 4 0.66410 2.65641 25.00% 99.01926 98.35516 98.687211998 4.5 5.5 5 0.95018 4.75092 20.00% 98.35516 97.40497 97.880071997 5.5 6.5 6 1.31727 7.90360 16.67% 97.40497 96.08771 96.746341996 6.5 7.5 7 1.77418 12.41924 14.29% 96.08771 94.31353 95.200621995 7.5 8.5 8 2.32660 18.61282 12.50% 94.31353 91.98693 93.150231994 8.5 9.5 9 3.00360 27.03237 11.11% 91.98693 88.98333 90.485131993 9.5 10.5 10 3.81040 38.10396 10.00% 88.98333 85.17293 87.078131992 10.5 11.5 11 4.77828 52.56112 9.09% 85.17293 80.39465 82.783791991 11.5 12.5 12 5.92539 71.10471 8.33% 80.39465 74.46926 77.431951990 12.5 13.5 13 7.21685 93.81908 7.69% 74.46926 67.25241 70.860831989 13.5 14.5 14 8.52818 119.39445 7.14% 67.25241 58.72423 62.988321988 14.5 15.5 15 9.63980 144.59698 6.67% 58.72423 49.08443 53.904331987 15.5 16.5 16 10.23847 163.81552 6.25% 49.08443 38.84596 43.965201986 16.5 17.5 17 10.05785 170.98345 5.88% 38.84596 28.78811 33.817041985 17.5 18.5 18 9.01873 162.33721 5.56% 28.78811 19.76938 24.278751984 18.5 19.5 19 7.32224 139.12264 5.26% 19.76938 12.44713 16.108261983 19.5 20.5 20 5.38580 107.71609 5.00% 12.44713 7.06133 9.754231982 20.5 21.5 21 3.58517 75.28860 4.76% 7.06133 3.47616 5.268741981 21.5 22.5 22 2.12166 46.67642 4.55% 3.47616 1.35450 2.415331980 22.5 23.5 23 1.03650 23.83941 4.35% 1.35450 0.31801 0.836251979 23.5 24.5 24 0.29491 7.07778 4.17% 0.31801 0.02310 0.170551978 24.5 25.4 24.9625 0.02310 0.57661 4.01% 0.02310 0.00000 0.01155



Age IntervalAccrued Factor Overstatement

0.997422680.994732220.994646680.995338000.995086000.995653290.995812210.996687450.997014930.996946810.997468730.997489890.998549960.999246040.999396501.000700441.000795091.002887611.002507631.004615221.004657071.006583761.008676791.010856211.018441161.00000000



Page 10 of 23

Iowa Curve 15 R3 (Source: Engineering Valuation and Depreciation - 5th printing 1970, Appendix B, Page 413)Iowa Curve Per Board Iowa Curve Per GF Method

Ret frequency Ret frequency Ret frequency Survivors at Check on ASL Age Survivors % Retirements % Age Survivors % Retirements % Iowa Curve Per GFAge X value End of age

0.0 100.00000000 0.0 100.000000000 -10.00 100.000000000

0.08 -9.95 0.154794241554 0.015479424155 99.984520576 0.001160957 0.067157050.23 -9.85 0.168398555755 0.016839855575 99.967680720 0.003788968 0.14495130 0.14495 0.132040.38 -9.75 0.182954073982 0.018295407398 99.949385313 0.006860778 0.5 99.932842950.52 -9.65 0.198508320660 0.019850832066 99.929534481 0.0104216870.67 -9.55 0.215109958184 0.021510995818 99.908023485 0.0145199220.83 -9.45 0.232808742145 0.023280874214 99.884742611 0.019206721 0.178275310.98 -9.35 0.251655471837 0.025165547184 99.859577064 0.024536409 1.0 99.855048701.13 -9.25 0.271701936060 0.027170193606 99.832406870 0.0305664681.28 -9.15 0.293000854217 0.029300085422 99.803106785 0.037357609 0.22815061 0.22815 0.220041.43 -9.05 0.315605812762 0.031560581276 99.771546203 0.044973828 1.5 99.754567641.58 -8.95 0.339571197088 0.033957119709 99.737589084 0.0534824641.73 -8.85 0.364952118979 0.036495211898 99.701093872 0.0629542411.88 -8.75 0.391804339805 0.039180433980 99.661913438 0.073463314 0.28853756 2.0 99.626898092.03 -8.65 0.420184189663 0.042018418966 99.619895019 0.0850872982.18 -8.55 0.450148482781 0.045014848278 99.574880170 0.0979072952.33 -8.45 0.481754429488 0.048175442949 99.526704728 0.112007905 0.36130744 0.36131 0.349012.48 -8.35 0.515059545206 0.051505954521 99.475198773 0.127477237 2.5 99.466030082.63 -8.25 0.550121556917 0.055012155692 99.420186617 0.1444069092.78 -8.15 0.586998307724 0.058699830772 99.361486787 0.1628920302.93 -8.05 0.625747660132 0.062574766013 99.298912021 0.183031191 0.44676977 3.0 99.265590653.08 -7.95 0.666427398861 0.066642739886 99.232269281 0.2049264253.23 -7.85 0.709095134034 0.070909513403 99.161359767 0.2286831813.38 -7.75 0.753808205740 0.075380820574 99.085978947 0.254410269 3.5 99.01926031 0.54697098 0.54697 0.531683.53 -7.65 0.800623591084 0.080062359108 99.005916588 0.2822198163.68 -7.55 0.849597814946 0.084959781495 98.920956806 0.3122271973.83 -7.45 0.900786865808 0.090078686581 98.830878119 0.344550976 0.664101363.98 -7.35 0.954246118127 0.095424611813 98.735453508 0.379312832 4.0 98.718619674.13 -7.25 1.010030262880 0.101003026288 98.634450481 0.4166374834.28 -7.15 1.068193247990 0.106819324799 98.527631157 0.4566526144.43 -7.05 1.128788230509 0.112878823051 98.414752334 0.499488792 4.5 98.35515896 0.79774763 0.79775 0.776484.58 -6.95 1.191867542489 0.119186754249 98.295565579 0.5452794014.73 -6.85 1.257482672602 0.125748267260 98.169817312 0.5941605634.88 -6.75 1.325684265620 0.132568426562 98.037248885 0.646271079 0.95018452 5.0 97.920872045.03 -6.65 1.396522141905 0.139652214190 97.897596671 0.7017523765.18 -6.55 1.470045339096 0.147004533910 97.750592137 0.7607484635.33 -6.45 1.546302178131 0.154630217813 97.595961920 0.823405910 1.12383341 1.12383 1.095205.48 -6.35 1.625340355673 0.162534035567 97.433427884 0.889873845 5.5 97.404974435.63 -6.25 1.707207064910 0.170720706491 97.262707177 0.9603039745.78 -6.15 1.791949146465 0.179194914646 97.083512263 1.0348506325.93 -6.05 1.879613270959 0.187961327096 96.895550936 1.113670863 1.31726750 6.0 96.797038636.08 -5.95 1.970246154385 0.197024615438 96.698526320 1.1969245396.23 -5.85 2.063894807058 0.206389480706 96.492136840 1.2847745176.38 -5.75 2.160606816416 0.216060681642 96.276076158 1.377386845 6.5 96.08770694 1.53308091 1.53308 1.500856.53 -5.65 2.260430663293 0.226043066329 96.050033092 1.4749310086.68 -5.55 2.363416070630 0.236341607063 95.813691485 1.5775802276.83 -5.45 2.469614382710 0.246961438271 95.566730046 1.685511816 1.774177216.98 -5.35 2.579078972127 0.257907897213 95.308822149 1.798907583 7.0 95.263957727.13 -5.25 2.691865670594 0.269186567059 95.039635582 1.9179542907.28 -5.15 2.808033218592 0.280803321859 94.758832260 2.0428441677.43 -5.05 2.927643727537 0.292764372754 94.466067887 2.173775468 7.5 94.31352973 2.03831890 2.03832 1.996867.58 -4.95 3.050763146815 0.305076314682 94.160991573 2.310953084

Comparison

(Iowa Curve 15 R3) EUB Decision 2006-002 (January 13, 2006)


Page 11 of 23



Comparison

7.73 -4.85 3.177461726550 0.317746172655 93.843245400 2.4545891847.88 -4.75 3.307814465439 0.330781446544 93.512463954 2.604903892 2.32660267 8.0 93.225638838.03 -4.65 3.441901531392 0.344190153139 93.168273800 2.7621259798.18 -4.55 3.579808641073 0.357980864107 92.810292936 2.9264935648.33 -4.45 3.721627382820 0.372162738282 92.438130198 3.098254796 8.5 91.98692706 2.65080852 2.65081 2.598368.48 -4.35 3.867455465776 0.386745546578 92.051384651 3.2776685078.63 -4.25 4.017396876541 0.401739687654 91.649644964 3.4650048068.78 -4.15 4.171561923196 0.417156192320 91.232488771 3.660545588 3.003597158.93 -4.05 4.330067145239 0.433006714524 90.799482057 3.864584927 9.0 90.574830309.08 -3.95 4.493035066916 0.449303506692 90.350178550 4.0774293239.23 -3.85 4.660593770559 0.466059377056 89.884119173 4.2993977539.38 -3.75 4.832876266065 0.483287626607 89.400831547 4.530821499 9.5 88.98332991 3.38553126 3.38553 3.328469.53 -3.65 5.010019632477 0.501001963248 88.899829583 4.7720437009.68 -3.55 5.192163907964 0.519216390796 88.380613193 5.0234185819.83 -3.45 5.379450705294 0.537945070529 87.842668122 5.285310318 3.810395629.98 -3.35 5.572021531257 0.557202153126 87.285465969 5.558091477 10.0 87.18929904

10.13 -3.25 5.770015790519 0.577001579052 86.708464390 5.84214098810.28 -3.15 5.973568457044 0.597356845704 86.111107544 6.13784159010.43 -3.05 6.182807399625 0.618280739963 85.492826804 6.445576714 10.5 85.17293429 4.27260845 4.27261 4.2001510.58 -2.95 6.397850352249 0.639785035225 84.853041769 6.76572674810.73 -2.85 6.618801524942 0.661880152494 84.191161616 7.09866463510.88 -2.75 6.845747856533 0.684574785653 83.506586831 7.444750794 4.77828350 11.0 82.9166905911.03 -2.65 7.078754917324 0.707875491732 82.798711339 7.80432729611.18 -2.55 7.317862476978 0.731786247698 82.066925091 8.17771131811.33 -2.45 7.563079761061 0.756307976106 81.310617115 8.565187829 5.33247765 5.33248 5.2427311.48 -2.35 7.814380428402 0.781438042840 80.529179072 8.967001542 11.5 80.3946507811.63 -2.25 8.071697310802 0.807169731080 79.722009341 9.38334812411.78 -2.15 8.334916966450 0.833491696645 78.888517645 9.81436472811.93 -2.05 8.603874108580 0.860387410858 78.028130234 10.260119874 5.92539235 12.0 77.5842129312.08 -1.95 8.878345981236 0.887834598124 77.140295636 10.72060277212.23 -1.85 9.158046764320 0.915804676432 76.224490959 11.19571216912.38 -1.75 9.442622100165 0.944262210017 75.280228749 11.685244849 12.5 74.46925843 6.55570374 6.55570 6.4639712.53 -1.65 9.731643843471 0.973164384347 74.307064365 12.18888391412.68 -1.55 10.024605145212 1.002460514521 73.304603850 12.70618702212.83 -1.45 10.320915988912 1.032091598891 72.272512251 13.236574756 7.2168524912.98 -1.35 10.619899304076 1.061989930408 71.210522321 13.779319347 13.0 71.0285091913.13 -1.25 10.920787786296 1.092078778630 70.118443542 14.33353397013.28 -1.15 11.222721556284 1.122272155628 68.996171387 14.898162866 7.88120020 7.88120 7.7808613.43 -1.05 11.524746790552 1.152474679055 67.843696708 15.471972566 13.5 67.2524059413.58 -0.95 11.825815454254 1.182581545425 66.661115162 16.05354447913.73 -0.85 12.124786261711 1.212478626171 65.448636536 16.64126914413.88 -0.75 12.420426981917 1.242042698192 64.206593838 17.233342437 8.52817500 14.0 63.1473089914.03 -0.65 12.711418194849 1.271141819485 62.935452018 17.82776401814.18 -0.55 12.996358589374 1.299635858937 61.635816160 18.42233830014.33 -0.45 13.273771874973 1.327377187497 60.308438972 19.014678211 9.12984078 9.12984 9.0412314.48 -0.35 13.542115357336 1.354211535734 58.954227436 19.602211980 14.5 58.7242309314.63 -0.25 13.799790202174 1.379979020217 57.574248416 20.18219317114.78 -0.15 14.045153382545 1.404515338254 56.169733078 20.75171412314.93 -0.05 14.276531272862 1.427653127286 54.742079951 21.307722925 9.63979873 15.0 54.0174682115.08 0.05 14.492234817940 1.449223481794 53.292856469 21.84704398815.23 0.15 14.690576168365 1.469057616837 51.823798852 22.36640221615.38 0.25 14.869886634897 1.486988663490 50.336810188 22.862450701 15.5 49.08443221 10.02139800 10.02140 9.9772415.53 0.35 15.028535775099 1.502853577510 48.833956611 23.331801791



Page 12 of 23



Comparison

15.68 0.45 15.164951385926 1.516495138593 47.317461472 23.77106129715.83 0.55 15.277640137423 1.527764013742 45.789697459 24.176865517 10.2384700015.98 0.65 15.365208546114 1.536520854611 44.253176604 24.545920652 16.0 43.9960702016.13 0.75 15.426383953112 1.542638395311 42.710538209 24.87504412416.28 0.85 15.460035142757 1.546003514276 41.164534694 25.16120719516.43 0.95 15.465192213702 1.546519221370 39.618015473 25.401578211 16.5 38.84596221 10.25682490 10.25682 10.2656916.58 1.05 15.441065297158 1.544106529716 38.073908943 25.59356573016.73 1.15 15.387061707557 1.538706170756 36.535202773 25.73486070616.88 1.25 15.302801110200 1.530280111020 35.004922662 25.823476873 10.05784974 17.0 33.7392453017.03 1.35 15.188128299662 1.518812829966 33.486109832 25.85778843017.18 1.45 15.043123202347 1.504312320235 31.981797511 25.83656410017.33 1.55 14.868107747473 1.486810774747 30.494986737 25.758996672 9.63752259 9.63752 9.7188817.48 1.65 14.663649293015 1.466364929301 29.028621807 25.624727140 17.5 28.7881124717.63 1.75 14.430560346931 1.443056034693 27.585565773 25.43386261117.78 1.85 14.169894388955 1.416989438895 26.168576334 25.186987276 9.0187337317.93 1.95 13.882937673669 1.388293767367 24.780282566 24.885165780 18.0 24.1017227218.08 2.05 13.571196980534 1.357119698053 23.423162868 24.52993854218.23 2.15 13.236383369331 1.323638336933 22.099524531 24.12330869118.38 2.25 12.880392098456 1.288039209846 20.811485321 23.667720481 18.5 19.76937874 8.23248211 8.23248 8.3541818.53 2.35 12.505278966135 1.250527896614 19.560957425 23.16602928518.68 2.45 12.113233438408 1.211323343841 18.349634081 22.62146344618.83 2.55 11.706549029490 1.170654902949 17.178979178 22.037578548 7.3222444618.98 2.65 11.287591496695 1.128759149669 16.050220028 21.418204865 19.0 15.8692406019.13 2.75 10.858765499861 1.085876549986 14.964343478 20.76738901819.28 2.85 10.422480450657 1.042248045066 13.922095433 20.08933106919.43 2.95 9.981116336614 0.998111633661 12.923983800 19.388318484 19.5 12.44713428 6.35724553 6.35725 6.5033519.58 3.05 9.536990344828 0.953699034483 11.970284765 18.66865860019.73 3.15 9.092325127897 0.909232512790 11.061052252 17.93461131519.88 3.25 8.649219547056 0.864921954706 10.196130298 17.190323850 5.38580452 20.0 9.5119950720.03 3.35 8.209622692689 0.820962269269 9.375168028 16.43976944220.18 3.45 7.775311919185 0.777531191918 8.597636837 15.68669179720.33 3.55 7.347875539028 0.734787553903 7.862849283 14.934557033 4.44678292 4.44678 4.5897820.48 3.65 6.928700701078 0.692870070108 7.169979213 14.186514685 20.5 7.0613297720.63 3.75 6.518966831941 0.651896683194 6.518082529 13.44536909120.78 3.85 6.119644850617 0.611964485062 5.906118044 12.713562177 3.5851713220.93 3.95 5.731502179616 0.573150217962 5.332967826 11.993168311 21.0 5.0652121621.08 4.05 5.355113376422 0.535511337642 4.797456489 11.28590144121.23 4.15 4.990876004468 0.499087600447 4.298368888 10.59313431921.38 4.25 4.639031160671 0.463903116067 3.834465772 9.915929106 21.5 3.47615845 2.81542072 2.81542 2.9154721.53 4.35 4.299687885883 0.429968788588 3.404496984 9.25507817421.68 4.45 3.972850514363 0.397285051436 3.007211932 8.61115349021.83 4.55 3.658447877855 0.365844787786 2.641367144 7.984562493 2.12165566 22.0 2.2497914421.98 4.65 3.356363177618 0.335636317762 2.305730827 7.37560808322.13 4.75 3.066463281299 0.306646328130 1.999084498 6.78455001022.28 4.85 2.788626196955 0.278862619695 1.720221879 6.211664854 1.52276691 1.52277 1.6114422.43 4.95 2.522765527136 0.252276552714 1.467945326 5.657301695 22.5 1.3545027922.58 5.05 2.268850812710 0.226885081271 1.241060245 5.12193071022.73 5.15 2.026922836113 0.202692283611 1.038367961 4.60618214522.88 5.25 1.797103160547 0.179710316055 0.858657645 4.110873480 1.03649587 23.0 0.7270245323.03 5.35 1.579597424575 0.157959742458 0.700697903 3.63702307023.18 5.45 1.374692175820 0.137469217582 0.563228685 3.18584911723.33 5.55 1.182745294384 0.118274529438 0.444954156 2.758753399 0.61226298 0.61226 0.6696723.48 5.65 1.004170304012 0.100417030401 0.344537125 2.357289789



Page 13 of 23



Comparison

23.63 5.75 0.839415071998 0.083941507200 0.260595618 1.983118108 23.5 0.3180069123.78 5.85 0.688935530696 0.068893553070 0.191702065 1.63794422423.93 5.95 0.553165086054 0.055316508605 0.136385556 1.323447468 0.29490770 24.0 0.1147615424.08 6.05 0.432480282163 0.043248028216 0.093137528 1.04119627924.23 6.15 0.327163031658 0.032716303166 0.060421225 0.79255244424.38 6.25 0.237359254166 0.023735925417 0.036685300 0.578563182 24.5 0.02309922 0.11374741 0.11375 0.1342524.53 6.35 0.163033010439 0.016303301044 0.020381999 0.39983845824.68 6.45 0.103914014570 0.010391401457 0.009990597 0.25640783124.83 6.55 0.059434357085 0.005943435708 0.004047161 0.147545791 0.0230992224.98 6.65 0.028646314272 0.002864631427 0.001182530 0.071544170 25.0 0.0010141325.13 6.75 0.010103894518 0.001010389452 0.000172140 0.025386035 0.00101413 0.00101 0.0021325.28 6.85 0.001662510018 0.000166251002 0.000005889 0.004201994 25.4 0.00000000

25.425 6.949999 0.000000000000 0.000000000000 0.000000000 0.000000000 25.4 0.00000000100.0000000 100.00000000 100.00000000 100.00000000

999.999941105395 99.999994110540 1499.9999037



Page 14 of 23



Ave ELG Beg of interval End of Interval Average Accrual Factors Applicable to each vintageVintage Beg End Life ELG Survivors Survivors Survivors 2003 2002 2001 2000 1999 1998

Column (B) C (D) (E) (F) (G) (H) (I) (J) (K) (L) (M) (N) (O)

2003 0.0 1.0 0.5 0.13204 0.06602 200.00% 100.00000 99.86796 99.93398 0.1320400%2002 1.0 2.0 1.5 0.22004 0.33006 66.67% 99.86796 99.64792 99.75794 0.0733467% 0.14669333%2001 2.0 3.0 2.5 0.34901 0.872525 40.00% 99.64792 99.29891 99.47342 0.0698020% 0.13960400% 0.13960400%2000 3.0 4.0 3.5 0.53168 1.86088 28.57% 99.29891 98.76723 99.03307 0.0759543% 0.15190857% 0.15190857% 0.15190857%1999 4.0 5.0 4.5 0.77648 3.49416 22.22% 98.76723 97.99075 98.37899 0.0862756% 0.17255111% 0.17255111% 0.17255111% 0.17255111%1998 5.0 6.0 5.5 1.0952 6.0236 18.18% 97.99075 96.89555 97.44315 0.0995636% 0.19912727% 0.19912727% 0.19912727% 0.19912727% 0.19912727%1997 6.0 7.0 6.5 1.50085 9.755525 15.38% 96.89555 95.39470 96.14513 0.1154500% 0.23090000% 0.23090000% 0.23090000% 0.23090000% 0.23090000%1996 7.0 8.0 7.5 1.99686 14.97645 13.33% 95.39470 93.39784 94.39627 0.1331240% 0.26624800% 0.26624800% 0.26624800% 0.26624800% 0.26624800%1995 8.0 9.0 8.5 2.59836 22.08606 11.76% 93.39784 90.79948 92.09866 0.1528447% 0.30568941% 0.30568941% 0.30568941% 0.30568941% 0.30568941%1994 9.0 10.0 9.5 3.32846 31.62037 10.53% 90.79948 87.47102 89.13525 0.1751821% 0.35036421% 0.35036421% 0.35036421% 0.35036421% 0.35036421%1993 10.0 11.0 10.5 4.20015 44.101575 9.52% 87.47102 83.27087 85.37095 0.2000071% 0.40001429% 0.40001429% 0.40001429% 0.40001429% 0.40001429%1992 11.0 12.0 11.5 5.24273 60.291395 8.70% 83.27087 78.02814 80.64951 0.2279448% 0.45588957% 0.45588957% 0.45588957% 0.45588957% 0.45588957%1991 12.0 13.0 12.5 6.46397 80.799625 8.00% 78.02814 71.56417 74.79616 0.2585588% 0.51711760% 0.51711760% 0.51711760% 0.51711760% 0.51711760%1990 13.0 14.0 13.5 7.78086 105.04161 7.41% 71.56417 63.78331 67.67374 0.2881800% 0.57636000% 0.57636000% 0.57636000% 0.57636000% 0.57636000%1989 14.0 15.0 14.5 9.04123 131.097835 6.90% 63.78331 54.74208 59.26270 0.3117666% 0.62353310% 0.62353310% 0.62353310% 0.62353310% 0.62353310%1988 15.0 16.0 15.5 9.97724 154.64722 6.45% 54.74208 44.76484 49.75346 0.3218465% 0.64369290% 0.64369290% 0.64369290% 0.64369290% 0.64369290%1987 16.0 17.0 16.5 10.26569 169.383885 6.06% 44.76484 34.49915 39.63200 0.3110815% 0.62216303% 0.62216303% 0.62216303% 0.62216303% 0.62216303%1986 17.0 18.0 17.5 9.71888 170.0804 5.71% 34.49915 24.78027 29.63971 0.2776823% 0.55536457% 0.55536457% 0.55536457% 0.55536457% 0.55536457%1985 18.0 19.0 18.5 8.35418 154.55233 5.41% 24.78027 16.42609 20.60318 0.2257886% 0.45157730% 0.45157730% 0.45157730% 0.45157730% 0.45157730%1984 19.0 20.0 19.5 6.50335 126.815325 5.13% 16.42609 9.92274 13.17442 0.1667526% 0.33350513% 0.33350513% 0.33350513% 0.33350513% 0.33350513%1983 20.0 21.0 20.5 4.58978 94.09049 4.88% 9.92274 5.33296 7.62785 0.1119459% 0.22389171% 0.22389171% 0.22389171% 0.22389171% 0.22389171%1982 21.0 22.0 21.5 2.91547 62.682605 4.65% 5.33296 2.41749 3.87522 0.0678016% 0.13560326% 0.13560326% 0.13560326% 0.13560326% 0.13560326%1981 22.0 23.0 22.5 1.61144 36.2574 4.44% 2.41749 0.80605 1.61177 0.0358098% 0.07161956% 0.07161956% 0.07161956% 0.07161956% 0.07161956%1980 23.0 24.0 23.5 0.66967 15.737245 4.26% 0.80605 0.13638 0.47121 0.0142483% 0.02849660% 0.02849660% 0.02849660% 0.02849660% 0.02849660%1979 24.0 25.0 24.5 0.13425 3.289125 4.08% 0.13638 0.00213 0.06925 0.0027398% 0.00547959% 0.00547959% 0.00547959% 0.00547959% 0.00547959%1978 25.0 25.4 25.2 0.00213 0.053702625 3.97% 0.00213 0.00000 0.00106 0.0000422% 0.00008448% 0.00008448% 0.00008448% 0.00008448% 0.00008448%

100 15 3.93577929% 7.60747858% 7.46078525% 7.32118125% 7.16927268% 6.99672157%Annual Accrual Factor Per Gannet Fleming ELG Grouping (Corrected) 3.94000000% 7.63000000% 7.50000000% 7.39000000% 7.29000000% 7.18000000%Annual Accrual Factor Per Gannet Fleming 7.74000000% 7.55000000% 7.43000000% 7.32000000% 7.20000000% 7.08000000%Accrual Factor Overstatement 1.96 0.99 0.99 0.99 0.99 0.99

Calculations:Column E = Life multiplied by the ELG Group ( the sum of this column equals the area under the Iowa curve or the Average Service

Life Estimate)Column F = 1/LifeColumn H = Balance of survivors at the end of the age interval (prior balance - ELG group)Column I = mid point average of the survivors during the age intervalColumn J through AI= (1/Life)*ELG group (adjusted for mid year convention at first age interval) for each vintage from 2003 back to 1978Annual Accrual Factor = Sum of column J weighted by the appropriate mid point average of survivors at each age intervalColumn AK = sum of the column J though AI factors for each age intervalColumn AL = December 31, 2003 Accrued Factors = sum of the column J through AI factors (adjusted for the mid year convention in for

the most recent age interval) divided by the remaining ELG groups Column AN = December 31, 2003 Accrued Factors as indicated at page II-12 of the Gannett Fleming report

Age Interval

(15R3 per GF(Corrected)) EUB Decision 2006-002 (January 13, 2006)


Page 15 of 23




Column (B) C (D) (E) (F) (G) (H) (I)

2003 0.0 1.0 0.5 0.13204 0.06602 200.00% 100.00000 99.86796 99.933982002 1.0 2.0 1.5 0.22004 0.33006 66.67% 99.86796 99.64792 99.757942001 2.0 3.0 2.5 0.34901 0.872525 40.00% 99.64792 99.29891 99.473422000 3.0 4.0 3.5 0.53168 1.86088 28.57% 99.29891 98.76723 99.033071999 4.0 5.0 4.5 0.77648 3.49416 22.22% 98.76723 97.99075 98.378991998 5.0 6.0 5.5 1.0952 6.0236 18.18% 97.99075 96.89555 97.443151997 6.0 7.0 6.5 1.50085 9.755525 15.38% 96.89555 95.39470 96.145131996 7.0 8.0 7.5 1.99686 14.97645 13.33% 95.39470 93.39784 94.396271995 8.0 9.0 8.5 2.59836 22.08606 11.76% 93.39784 90.79948 92.098661994 9.0 10.0 9.5 3.32846 31.62037 10.53% 90.79948 87.47102 89.135251993 10.0 11.0 10.5 4.20015 44.101575 9.52% 87.47102 83.27087 85.370951992 11.0 12.0 11.5 5.24273 60.291395 8.70% 83.27087 78.02814 80.649511991 12.0 13.0 12.5 6.46397 80.799625 8.00% 78.02814 71.56417 74.796161990 13.0 14.0 13.5 7.78086 105.04161 7.41% 71.56417 63.78331 67.673741989 14.0 15.0 14.5 9.04123 131.097835 6.90% 63.78331 54.74208 59.262701988 15.0 16.0 15.5 9.97724 154.64722 6.45% 54.74208 44.76484 49.753461987 16.0 17.0 16.5 10.26569 169.383885 6.06% 44.76484 34.49915 39.632001986 17.0 18.0 17.5 9.71888 170.0804 5.71% 34.49915 24.78027 29.639711985 18.0 19.0 18.5 8.35418 154.55233 5.41% 24.78027 16.42609 20.603181984 19.0 20.0 19.5 6.50335 126.815325 5.13% 16.42609 9.92274 13.174421983 20.0 21.0 20.5 4.58978 94.09049 4.88% 9.92274 5.33296 7.627851982 21.0 22.0 21.5 2.91547 62.682605 4.65% 5.33296 2.41749 3.875221981 22.0 23.0 22.5 1.61144 36.2574 4.44% 2.41749 0.80605 1.611771980 23.0 24.0 23.5 0.66967 15.737245 4.26% 0.80605 0.13638 0.471211979 24.0 25.0 24.5 0.13425 3.289125 4.08% 0.13638 0.00213 0.069251978 25.0 25.4 25.2 0.00213 0.053702625 3.97% 0.00213 0.00000 0.00106

100 15Annual Accrual Factor Per Gannet Fleming ELG Grouping (Corrected)Annual Accrual Factor Per Gannet FlemingAccrual Factor Overstatement




Age Interval Accrual Factors Applicable to each vintage1997 1996 1995 1994 1993 1992(P) (Q) R (S) (T) (U)

0.23090000%0.26624800% 0.26624800%0.30568941% 0.30568941% 0.30568941%0.35036421% 0.35036421% 0.35036421% 0.35036421%0.40001429% 0.40001429% 0.40001429% 0.40001429% 0.40001429%0.45588957% 0.45588957% 0.45588957% 0.45588957% 0.45588957% 0.45588957%0.51711760% 0.51711760% 0.51711760% 0.51711760% 0.51711760% 0.51711760%0.57636000% 0.57636000% 0.57636000% 0.57636000% 0.57636000% 0.57636000%0.62353310% 0.62353310% 0.62353310% 0.62353310% 0.62353310% 0.62353310%0.64369290% 0.64369290% 0.64369290% 0.64369290% 0.64369290% 0.64369290%0.62216303% 0.62216303% 0.62216303% 0.62216303% 0.62216303% 0.62216303%0.55536457% 0.55536457% 0.55536457% 0.55536457% 0.55536457% 0.55536457%0.45157730% 0.45157730% 0.45157730% 0.45157730% 0.45157730% 0.45157730%0.33350513% 0.33350513% 0.33350513% 0.33350513% 0.33350513% 0.33350513%0.22389171% 0.22389171% 0.22389171% 0.22389171% 0.22389171% 0.22389171%0.13560326% 0.13560326% 0.13560326% 0.13560326% 0.13560326% 0.13560326%0.07161956% 0.07161956% 0.07161956% 0.07161956% 0.07161956% 0.07161956%0.02849660% 0.02849660% 0.02849660% 0.02849660% 0.02849660% 0.02849660%0.00547959% 0.00547959% 0.00547959% 0.00547959% 0.00547959% 0.00547959%0.00008448% 0.00008448% 0.00008448% 0.00008448% 0.00008448% 0.00008448%

6.79759430% 6.56669430% 6.30044630% 5.99475688% 5.64439267% 5.24437839%7.07000000% 6.96000000% 6.84000000% 6.73000000% 6.61000000% 6.50000000%

6.95000000% 6.82000000% 6.68000000% 6.53000000% 6.38000000% 6.22000000%0.98 0.98 0.98 0.97 0.97 0.96



Page 16 of 23




Column (B) C (D) (E) (F) (G) (H) (I)

2003 0.0 1.0 0.5 0.13204 0.06602 200.00% 100.00000 99.86796 99.933982002 1.0 2.0 1.5 0.22004 0.33006 66.67% 99.86796 99.64792 99.757942001 2.0 3.0 2.5 0.34901 0.872525 40.00% 99.64792 99.29891 99.473422000 3.0 4.0 3.5 0.53168 1.86088 28.57% 99.29891 98.76723 99.033071999 4.0 5.0 4.5 0.77648 3.49416 22.22% 98.76723 97.99075 98.378991998 5.0 6.0 5.5 1.0952 6.0236 18.18% 97.99075 96.89555 97.443151997 6.0 7.0 6.5 1.50085 9.755525 15.38% 96.89555 95.39470 96.145131996 7.0 8.0 7.5 1.99686 14.97645 13.33% 95.39470 93.39784 94.396271995 8.0 9.0 8.5 2.59836 22.08606 11.76% 93.39784 90.79948 92.098661994 9.0 10.0 9.5 3.32846 31.62037 10.53% 90.79948 87.47102 89.135251993 10.0 11.0 10.5 4.20015 44.101575 9.52% 87.47102 83.27087 85.370951992 11.0 12.0 11.5 5.24273 60.291395 8.70% 83.27087 78.02814 80.649511991 12.0 13.0 12.5 6.46397 80.799625 8.00% 78.02814 71.56417 74.796161990 13.0 14.0 13.5 7.78086 105.04161 7.41% 71.56417 63.78331 67.673741989 14.0 15.0 14.5 9.04123 131.097835 6.90% 63.78331 54.74208 59.262701988 15.0 16.0 15.5 9.97724 154.64722 6.45% 54.74208 44.76484 49.753461987 16.0 17.0 16.5 10.26569 169.383885 6.06% 44.76484 34.49915 39.632001986 17.0 18.0 17.5 9.71888 170.0804 5.71% 34.49915 24.78027 29.639711985 18.0 19.0 18.5 8.35418 154.55233 5.41% 24.78027 16.42609 20.603181984 19.0 20.0 19.5 6.50335 126.815325 5.13% 16.42609 9.92274 13.174421983 20.0 21.0 20.5 4.58978 94.09049 4.88% 9.92274 5.33296 7.627851982 21.0 22.0 21.5 2.91547 62.682605 4.65% 5.33296 2.41749 3.875221981 22.0 23.0 22.5 1.61144 36.2574 4.44% 2.41749 0.80605 1.611771980 23.0 24.0 23.5 0.66967 15.737245 4.26% 0.80605 0.13638 0.471211979 24.0 25.0 24.5 0.13425 3.289125 4.08% 0.13638 0.00213 0.069251978 25.0 25.4 25.2 0.00213 0.053702625 3.97% 0.00213 0.00000 0.00106





Age Interval Accrual Factors Applicable to each vintage1991 1990 1989 1988 1987 1986(V) (W) (X) (Y) (A) (AA)

0.51711760%0.57636000% 0.57636000%0.62353310% 0.62353310% 0.62353310%0.64369290% 0.64369290% 0.64369290% 0.64369290%0.62216303% 0.62216303% 0.62216303% 0.62216303% 0.62216303%0.55536457% 0.55536457% 0.55536457% 0.55536457% 0.55536457% 0.55536457%0.45157730% 0.45157730% 0.45157730% 0.45157730% 0.45157730% 0.45157730%0.33350513% 0.33350513% 0.33350513% 0.33350513% 0.33350513% 0.33350513%0.22389171% 0.22389171% 0.22389171% 0.22389171% 0.22389171% 0.22389171%0.13560326% 0.13560326% 0.13560326% 0.13560326% 0.13560326% 0.13560326%0.07161956% 0.07161956% 0.07161956% 0.07161956% 0.07161956% 0.07161956%0.02849660% 0.02849660% 0.02849660% 0.02849660% 0.02849660% 0.02849660%0.00547959% 0.00547959% 0.00547959% 0.00547959% 0.00547959% 0.00547959%0.00008448% 0.00008448% 0.00008448% 0.00008448% 0.00008448% 0.00008448%

4.78848882% 4.27137122% 3.69501122% 3.07147812% 2.42778522% 1.80562219%6.40000000% 6.31000000% 6.23000000% 6.17000000% 6.13000000% 6.09000000%

6.06000000% 5.89000000% 5.71000000% 5.53000000% 5.34000000% 5.16000000%0.95 0.93 0.92 0.90 0.87 0.85



Page 17 of 23




Column (B) C (D) (E) (F) (G) (H) (I)

2003 0.0 1.0 0.5 0.13204 0.06602 200.00% 100.00000 99.86796 99.933982002 1.0 2.0 1.5 0.22004 0.33006 66.67% 99.86796 99.64792 99.757942001 2.0 3.0 2.5 0.34901 0.872525 40.00% 99.64792 99.29891 99.473422000 3.0 4.0 3.5 0.53168 1.86088 28.57% 99.29891 98.76723 99.033071999 4.0 5.0 4.5 0.77648 3.49416 22.22% 98.76723 97.99075 98.378991998 5.0 6.0 5.5 1.0952 6.0236 18.18% 97.99075 96.89555 97.443151997 6.0 7.0 6.5 1.50085 9.755525 15.38% 96.89555 95.39470 96.145131996 7.0 8.0 7.5 1.99686 14.97645 13.33% 95.39470 93.39784 94.396271995 8.0 9.0 8.5 2.59836 22.08606 11.76% 93.39784 90.79948 92.098661994 9.0 10.0 9.5 3.32846 31.62037 10.53% 90.79948 87.47102 89.135251993 10.0 11.0 10.5 4.20015 44.101575 9.52% 87.47102 83.27087 85.370951992 11.0 12.0 11.5 5.24273 60.291395 8.70% 83.27087 78.02814 80.649511991 12.0 13.0 12.5 6.46397 80.799625 8.00% 78.02814 71.56417 74.796161990 13.0 14.0 13.5 7.78086 105.04161 7.41% 71.56417 63.78331 67.673741989 14.0 15.0 14.5 9.04123 131.097835 6.90% 63.78331 54.74208 59.262701988 15.0 16.0 15.5 9.97724 154.64722 6.45% 54.74208 44.76484 49.753461987 16.0 17.0 16.5 10.26569 169.383885 6.06% 44.76484 34.49915 39.632001986 17.0 18.0 17.5 9.71888 170.0804 5.71% 34.49915 24.78027 29.639711985 18.0 19.0 18.5 8.35418 154.55233 5.41% 24.78027 16.42609 20.603181984 19.0 20.0 19.5 6.50335 126.815325 5.13% 16.42609 9.92274 13.174421983 20.0 21.0 20.5 4.58978 94.09049 4.88% 9.92274 5.33296 7.627851982 21.0 22.0 21.5 2.91547 62.682605 4.65% 5.33296 2.41749 3.875221981 22.0 23.0 22.5 1.61144 36.2574 4.44% 2.41749 0.80605 1.611771980 23.0 24.0 23.5 0.66967 15.737245 4.26% 0.80605 0.13638 0.471211979 24.0 25.0 24.5 0.13425 3.289125 4.08% 0.13638 0.00213 0.069251978 25.0 25.4 25.2 0.00213 0.053702625 3.97% 0.00213 0.00000 0.00106





Age Interval Accrual Factors Applicable to each vintage1985 1984 1983 1982 1981 1980(AB) (AC) (AD) (AE) (AF) (AG)

0.45157730%0.33350513% 0.33350513%0.22389171% 0.22389171% 0.22389171%0.13560326% 0.13560326% 0.13560326% 0.13560326%0.07161956% 0.07161956% 0.07161956% 0.07161956% 0.07161956%0.02849660% 0.02849660% 0.02849660% 0.02849660% 0.02849660% 0.02849660%0.00547959% 0.00547959% 0.00547959% 0.00547959% 0.00547959% 0.00547959%0.00008448% 0.00008448% 0.00008448% 0.00008448% 0.00008448% 0.00008448%

1.25025761% 0.79868032% 0.46517519% 0.24128348% 0.10568023% 0.03406067%6.07000000% 6.06000000% 6.10000000% 6.23000000% 6.56000000% 7.23000000%

4.97000000% 4.80000000% 4.63000000% 4.48000000% 4.34000000% 4.20000000%0.82 0.79 0.76 0.72 0.66 0.58



Page 18 of 23




Column (B) C (D) (E) (F) (G) (H) (I)

2003 0.0 1.0 0.5 0.13204 0.06602 200.00% 100.00000 99.86796 99.933982002 1.0 2.0 1.5 0.22004 0.33006 66.67% 99.86796 99.64792 99.757942001 2.0 3.0 2.5 0.34901 0.872525 40.00% 99.64792 99.29891 99.473422000 3.0 4.0 3.5 0.53168 1.86088 28.57% 99.29891 98.76723 99.033071999 4.0 5.0 4.5 0.77648 3.49416 22.22% 98.76723 97.99075 98.378991998 5.0 6.0 5.5 1.0952 6.0236 18.18% 97.99075 96.89555 97.443151997 6.0 7.0 6.5 1.50085 9.755525 15.38% 96.89555 95.39470 96.145131996 7.0 8.0 7.5 1.99686 14.97645 13.33% 95.39470 93.39784 94.396271995 8.0 9.0 8.5 2.59836 22.08606 11.76% 93.39784 90.79948 92.098661994 9.0 10.0 9.5 3.32846 31.62037 10.53% 90.79948 87.47102 89.135251993 10.0 11.0 10.5 4.20015 44.101575 9.52% 87.47102 83.27087 85.370951992 11.0 12.0 11.5 5.24273 60.291395 8.70% 83.27087 78.02814 80.649511991 12.0 13.0 12.5 6.46397 80.799625 8.00% 78.02814 71.56417 74.796161990 13.0 14.0 13.5 7.78086 105.04161 7.41% 71.56417 63.78331 67.673741989 14.0 15.0 14.5 9.04123 131.097835 6.90% 63.78331 54.74208 59.262701988 15.0 16.0 15.5 9.97724 154.64722 6.45% 54.74208 44.76484 49.753461987 16.0 17.0 16.5 10.26569 169.383885 6.06% 44.76484 34.49915 39.632001986 17.0 18.0 17.5 9.71888 170.0804 5.71% 34.49915 24.78027 29.639711985 18.0 19.0 18.5 8.35418 154.55233 5.41% 24.78027 16.42609 20.603181984 19.0 20.0 19.5 6.50335 126.815325 5.13% 16.42609 9.92274 13.174421983 20.0 21.0 20.5 4.58978 94.09049 4.88% 9.92274 5.33296 7.627851982 21.0 22.0 21.5 2.91547 62.682605 4.65% 5.33296 2.41749 3.875221981 22.0 23.0 22.5 1.61144 36.2574 4.44% 2.41749 0.80605 1.611771980 23.0 24.0 23.5 0.66967 15.737245 4.26% 0.80605 0.13638 0.471211979 24.0 25.0 24.5 0.13425 3.289125 4.08% 0.13638 0.00213 0.069251978 25.0 25.4 25.2 0.00213 0.053702625 3.97% 0.00213 0.00000 0.00106





Age Interval

Accrued Factor Accrued FactorAccrual Factors Applicable Check

to each vintage ELG Accruals Per GF Corrected1979 1978(AH) (AI)

0.132040000 0.038100000.220040000 0.112300000.349010000 0.184300000.531680000 0.254100000.776480000 0.321300001.095200000 0.385800001.500850000 0.447400001.996860000 0.505900002.598360000 0.561200003.328460000 0.613000004.200150000 0.661300005.242730000 0.705700006.463970000 0.746100007.780860000 0.782100009.041230000 0.813600009.977240000 0.84060000

10.265690000 0.863600009.718880000 0.882900008.354180000 0.899500006.503350000 0.914200004.589780000 0.927500002.915470000 0.939900001.611440000 0.950800000.669670000 0.95880000

0.00547959% 0.134250000 0.971700000.00008448% 0.00005703% 0.002126832 1.00000000

0.00556407% 0.00005703% 100.00000 100.0008.03000000% 5.35000000%

4.08000000% 3.97220000%0.51 0.74



Page 19 of 23




Column (B) C (D) (E) (F) (G) (H) (I)

2003 0.0 1.0 0.5 0.13204 0.06602 200.00% 100.00000 99.86796 99.933982002 1.0 2.0 1.5 0.22004 0.33006 66.67% 99.86796 99.64792 99.757942001 2.0 3.0 2.5 0.34901 0.872525 40.00% 99.64792 99.29891 99.473422000 3.0 4.0 3.5 0.53168 1.86088 28.57% 99.29891 98.76723 99.033071999 4.0 5.0 4.5 0.77648 3.49416 22.22% 98.76723 97.99075 98.378991998 5.0 6.0 5.5 1.0952 6.0236 18.18% 97.99075 96.89555 97.443151997 6.0 7.0 6.5 1.50085 9.755525 15.38% 96.89555 95.39470 96.145131996 7.0 8.0 7.5 1.99686 14.97645 13.33% 95.39470 93.39784 94.396271995 8.0 9.0 8.5 2.59836 22.08606 11.76% 93.39784 90.79948 92.098661994 9.0 10.0 9.5 3.32846 31.62037 10.53% 90.79948 87.47102 89.135251993 10.0 11.0 10.5 4.20015 44.101575 9.52% 87.47102 83.27087 85.370951992 11.0 12.0 11.5 5.24273 60.291395 8.70% 83.27087 78.02814 80.649511991 12.0 13.0 12.5 6.46397 80.799625 8.00% 78.02814 71.56417 74.796161990 13.0 14.0 13.5 7.78086 105.04161 7.41% 71.56417 63.78331 67.673741989 14.0 15.0 14.5 9.04123 131.097835 6.90% 63.78331 54.74208 59.262701988 15.0 16.0 15.5 9.97724 154.64722 6.45% 54.74208 44.76484 49.753461987 16.0 17.0 16.5 10.26569 169.383885 6.06% 44.76484 34.49915 39.632001986 17.0 18.0 17.5 9.71888 170.0804 5.71% 34.49915 24.78027 29.639711985 18.0 19.0 18.5 8.35418 154.55233 5.41% 24.78027 16.42609 20.603181984 19.0 20.0 19.5 6.50335 126.815325 5.13% 16.42609 9.92274 13.174421983 20.0 21.0 20.5 4.58978 94.09049 4.88% 9.92274 5.33296 7.627851982 21.0 22.0 21.5 2.91547 62.682605 4.65% 5.33296 2.41749 3.875221981 22.0 23.0 22.5 1.61144 36.2574 4.44% 2.41749 0.80605 1.611771980 23.0 24.0 23.5 0.66967 15.737245 4.26% 0.80605 0.13638 0.471211979 24.0 25.0 24.5 0.13425 3.289125 4.08% 0.13638 0.00213 0.069251978 25.0 25.4 25.2 0.00213 0.053702625 3.97% 0.00213 0.00000 0.00106





Age IntervalAccrued Factor

Per Gannet Fleming OverstatementVintage Page II-12 of GF Report

2003 0.0387 1.015748032002 0.1133 1.008904722001 0.1858 1.008138902000 0.2562 1.008264461999 0.3240 1.008403361998 0.3894 1.009331261997 0.4518 1.009834601996 0.5115 1.011069381995 0.5678 1.011760511994 0.6204 1.012071781993 0.6699 1.013004691992 0.7153 1.013603511991 0.7575 1.015279451990 0.7952 1.016749781989 0.8280 1.017699121988 0.8572 1.019747801987 0.8811 1.020264011986 0.9030 1.022765891985 0.9195 1.022234571984 0.9360 1.023845991983 0.9492 1.023396231982 0.9632 1.024789871981 0.9765 1.027029871980 0.9870 1.029411761979 0.9996 1.028712571978 1.0000 1.00000000



Page 20 of 23

Ex 326-5 Aid to Undertaking Response of Mr. Kennedy at Transcript Volume 4, page 935ENMAX POWER CORPORATIONCalculation of the Annual Accrual Factors and Accrued Factors as at December 31, 2003 for a 15-R3 Iowa Curve

Beginning Ending Average Accrual Factors Applicable to each vintageVintage Life ELG Survivors Survivors Survivors 2003 2002 2001 2000 1999 1998 1997 1996

Column B C (D) (E) (F) (G) (H) (I) (J) (K) (L) (M) (N) (O) (P) (Q)

2003 0.5 0.13204 0.06602 200.00% 100.0000 99.86796 99.933980 0.13204000%2002 1.5 0.22004 0.33006 66.67% 99.86796 99.64792 99.757940 0.14669333% 0.07334667%2001 2.5 0.34901 0.872525 40.00% 99.64792 99.29891 99.473415 0.13960400% 0.13960400% 0.06980200%2000 3.5 0.53168 1.86088 28.57% 99.29891 98.76723 99.033070 0.15190857% 0.15190857% 0.15190857% 0.07595429%1999 4.5 0.77648 3.49416 22.22% 98.76723 97.99075 98.378990 0.17255111% 0.17255111% 0.17255111% 0.17255111% 0.08627556%1998 5.5 1.0952 6.0236 18.18% 97.99075 96.89555 97.443150 0.19912727% 0.19912727% 0.19912727% 0.19912727% 0.19912727% 0.09956364%1997 6.5 1.50085 9.755525 15.38% 96.89555 95.3947 96.145125 0.23090000% 0.23090000% 0.23090000% 0.23090000% 0.23090000% 0.23090000% 0.11545000%1996 7.5 1.99686 14.97645 13.33% 95.39470 93.39784 94.396270 0.26624800% 0.26624800% 0.26624800% 0.26624800% 0.26624800% 0.26624800% 0.26624800% 0.13312400%1995 8.5 2.59836 22.08606 11.76% 93.39784 90.79948 92.098660 0.30568941% 0.30568941% 0.30568941% 0.30568941% 0.30568941% 0.30568941% 0.30568941% 0.30568941%1994 9.5 3.32846 31.62037 10.53% 90.79948 87.47102 89.135250 0.35036421% 0.35036421% 0.35036421% 0.35036421% 0.35036421% 0.35036421% 0.35036421% 0.35036421%1993 10.5 4.20015 44.101575 9.52% 87.47102 83.27087 85.370945 0.40001429% 0.40001429% 0.40001429% 0.40001429% 0.40001429% 0.40001429% 0.40001429% 0.40001429%1992 11.5 5.24273 60.291395 8.70% 83.27087 78.02814 80.649505 0.45588957% 0.45588957% 0.45588957% 0.45588957% 0.45588957% 0.45588957% 0.45588957% 0.45588957%1991 12.5 6.46397 80.799625 8.00% 78.02814 71.56417 74.796155 0.51711760% 0.51711760% 0.51711760% 0.51711760% 0.51711760% 0.51711760% 0.51711760% 0.51711760%1990 13.5 7.78086 105.04161 7.41% 71.56417 63.78331 67.673740 0.57636000% 0.57636000% 0.57636000% 0.57636000% 0.57636000% 0.57636000% 0.57636000% 0.57636000%1989 14.5 9.04123 131.097835 6.90% 63.78331 54.74208 59.262695 0.62353310% 0.62353310% 0.62353310% 0.62353310% 0.62353310% 0.62353310% 0.62353310% 0.62353310%1988 15.5 9.97724 154.64722 6.45% 54.74208 44.76484 49.753460 0.64369290% 0.64369290% 0.64369290% 0.64369290% 0.64369290% 0.64369290% 0.64369290% 0.64369290%1987 16.5 10.26569 169.383885 6.06% 44.76484 34.49915 39.631995 0.62216303% 0.62216303% 0.62216303% 0.62216303% 0.62216303% 0.62216303% 0.62216303% 0.62216303%1986 17.5 9.71888 170.0804 5.71% 34.49915 24.78027 29.639710 0.55536457% 0.55536457% 0.55536457% 0.55536457% 0.55536457% 0.55536457% 0.55536457% 0.55536457%1985 18.5 8.35418 154.55233 5.41% 24.78027 16.42609 20.603180 0.45157730% 0.45157730% 0.45157730% 0.45157730% 0.45157730% 0.45157730% 0.45157730% 0.45157730%1984 19.5 6.50335 126.815325 5.13% 16.42609 9.92274 13.174415 0.33350513% 0.33350513% 0.33350513% 0.33350513% 0.33350513% 0.33350513% 0.33350513% 0.33350513%1983 20.5 4.58978 94.09049 4.88% 9.92274 5.33296 7.627850 0.22389171% 0.22389171% 0.22389171% 0.22389171% 0.22389171% 0.22389171% 0.22389171% 0.22389171%1982 21.5 2.91547 62.682605 4.65% 5.33296 2.41749 3.875225 0.13560326% 0.13560326% 0.13560326% 0.13560326% 0.13560326% 0.13560326% 0.13560326% 0.13560326%1981 22.5 1.61144 36.2574 4.44% 2.41749 0.80605 1.611770 0.07161956% 0.07161956% 0.07161956% 0.07161956% 0.07161956% 0.07161956% 0.07161956% 0.07161956%1980 23.5 0.66967 15.737245 4.26% 0.80605 0.13638 0.471215 0.02849660% 0.02849660% 0.02849660% 0.02849660% 0.02849660% 0.02849660% 0.02849660% 0.02849660%1979 24.5 0.13425 3.289125 4.08% 0.13638 0.00213 0.069255 0.00547959% 0.00547959% 0.00547959% 0.00547959% 0.00547959% 0.00547959% 0.00547959% 0.00547959%1978 25.175 0.00213 0.05362275 3.97% 0.00213 0 0.000373 0.00008461% 0.00008461% 0.00008461% 0.00008461% 0.00008461% 0.00008461% 0.00008461% 0.00008461%

100 1500.007338 7.73951871% 7.53413204% 7.39098338% 7.24522709% 7.08299725% 6.89715806% 6.68214442% 6.43357042%Annual Accrual Factor 7.74000000% 7.55000000% 7.43000000% 7.32000000% 7.20000000% 7.08000000% 6.95000000% 6.82000000%

Calculations:Column E = Life multiplied by the ELG Group ( the sum of this column equals the area under the Iowa

curve or the Average Service Life Estimate)Column F = 1/LifeColumn H = Balance of survivors at the end of the age interval (prior balance - ELG group)Column I = mid point average of the survivors during the age intervalColumn J through AI= (1/Life)*ELG group (adjusted for mid year convention at first age interval) for each

vintage from 2003 back to 1978Annual Accrual Factor = Sum of column J weighted by the appropriate mid point average of survivors at

each age intervalColumn AK = sum of the column J though AI factors for each age intervalColumn AL = December 31, 2003 Accrued Factors = sum of the column J through AI factors (adjusted for

the mid year convention in for the most recent age interval) divided by the remaining ELG groups Column AN = December 31, 2003 Accrued Factors as indicated at page II-12 of the Gannett Fleming report

(15R3 per GF (Exhibit 326-005)) EUB Decision 2006-002 (January 13, 2006)


Page 21 of 23


Beginning Ending AverageVintage Life ELG Survivors Survivors Survivors

Column B C (D) (E) (F) (G) (H) (I)

2003 0.5 0.13204 0.06602 200.00% 100.0000 99.86796 99.9339802002 1.5 0.22004 0.33006 66.67% 99.86796 99.64792 99.7579402001 2.5 0.34901 0.872525 40.00% 99.64792 99.29891 99.4734152000 3.5 0.53168 1.86088 28.57% 99.29891 98.76723 99.0330701999 4.5 0.77648 3.49416 22.22% 98.76723 97.99075 98.3789901998 5.5 1.0952 6.0236 18.18% 97.99075 96.89555 97.4431501997 6.5 1.50085 9.755525 15.38% 96.89555 95.3947 96.1451251996 7.5 1.99686 14.97645 13.33% 95.39470 93.39784 94.3962701995 8.5 2.59836 22.08606 11.76% 93.39784 90.79948 92.0986601994 9.5 3.32846 31.62037 10.53% 90.79948 87.47102 89.1352501993 10.5 4.20015 44.101575 9.52% 87.47102 83.27087 85.3709451992 11.5 5.24273 60.291395 8.70% 83.27087 78.02814 80.6495051991 12.5 6.46397 80.799625 8.00% 78.02814 71.56417 74.7961551990 13.5 7.78086 105.04161 7.41% 71.56417 63.78331 67.6737401989 14.5 9.04123 131.097835 6.90% 63.78331 54.74208 59.2626951988 15.5 9.97724 154.64722 6.45% 54.74208 44.76484 49.7534601987 16.5 10.26569 169.383885 6.06% 44.76484 34.49915 39.6319951986 17.5 9.71888 170.0804 5.71% 34.49915 24.78027 29.6397101985 18.5 8.35418 154.55233 5.41% 24.78027 16.42609 20.6031801984 19.5 6.50335 126.815325 5.13% 16.42609 9.92274 13.1744151983 20.5 4.58978 94.09049 4.88% 9.92274 5.33296 7.6278501982 21.5 2.91547 62.682605 4.65% 5.33296 2.41749 3.8752251981 22.5 1.61144 36.2574 4.44% 2.41749 0.80605 1.6117701980 23.5 0.66967 15.737245 4.26% 0.80605 0.13638 0.4712151979 24.5 0.13425 3.289125 4.08% 0.13638 0.00213 0.0692551978 25.175 0.00213 0.05362275 3.97% 0.00213 0 0.000373

100 1500.007338Annual Accrual Factor






Accrual Factors Applicable to each vintage1995 1994 1993 1992 1991 1990 1989 1988

R (S) (T) (U) (V) (W) (X) (Y)

0.15284471%0.35036421% 0.17518211%0.40001429% 0.40001429% 0.20000714%0.45588957% 0.45588957% 0.45588957% 0.22794478%0.51711760% 0.51711760% 0.51711760% 0.51711760% 0.25855880%0.57636000% 0.57636000% 0.57636000% 0.57636000% 0.57636000% 0.28818000%0.62353310% 0.62353310% 0.62353310% 0.62353310% 0.62353310% 0.62353310% 0.31176655%0.64369290% 0.64369290% 0.64369290% 0.64369290% 0.64369290% 0.64369290% 0.64369290% 0.32184645%0.62216303% 0.62216303% 0.62216303% 0.62216303% 0.62216303% 0.62216303% 0.62216303% 0.62216303%0.55536457% 0.55536457% 0.55536457% 0.55536457% 0.55536457% 0.55536457% 0.55536457% 0.55536457%0.45157730% 0.45157730% 0.45157730% 0.45157730% 0.45157730% 0.45157730% 0.45157730% 0.45157730%0.33350513% 0.33350513% 0.33350513% 0.33350513% 0.33350513% 0.33350513% 0.33350513% 0.33350513%0.22389171% 0.22389171% 0.22389171% 0.22389171% 0.22389171% 0.22389171% 0.22389171% 0.22389171%0.13560326% 0.13560326% 0.13560326% 0.13560326% 0.13560326% 0.13560326% 0.13560326% 0.13560326%0.07161956% 0.07161956% 0.07161956% 0.07161956% 0.07161956% 0.07161956% 0.07161956% 0.07161956%0.02849660% 0.02849660% 0.02849660% 0.02849660% 0.02849660% 0.02849660% 0.02849660% 0.02849660%0.00547959% 0.00547959% 0.00547959% 0.00547959% 0.00547959% 0.00547959% 0.00547959% 0.00547959%0.00008461% 0.00008461% 0.00008461% 0.00008461% 0.00008461% 0.00008461% 0.00008461% 0.00008461%6.14760172% 5.81957490% 5.44438566% 5.01643373% 4.52993015% 3.98319135% 3.38324480% 2.74963179%6.68000000% 6.53000000% 6.38000000% 6.22000000% 6.06000000% 5.89000000% 5.71000000% 5.53000000%



Page 22 of 23




2003 0.5 0.13204 0.06602 200.00% 100.0000 99.86796 99.9339802002 1.5 0.22004 0.33006 66.67% 99.86796 99.64792 99.7579402001 2.5 0.34901 0.872525 40.00% 99.64792 99.29891 99.4734152000 3.5 0.53168 1.86088 28.57% 99.29891 98.76723 99.0330701999 4.5 0.77648 3.49416 22.22% 98.76723 97.99075 98.3789901998 5.5 1.0952 6.0236 18.18% 97.99075 96.89555 97.4431501997 6.5 1.50085 9.755525 15.38% 96.89555 95.3947 96.1451251996 7.5 1.99686 14.97645 13.33% 95.39470 93.39784 94.3962701995 8.5 2.59836 22.08606 11.76% 93.39784 90.79948 92.0986601994 9.5 3.32846 31.62037 10.53% 90.79948 87.47102 89.1352501993 10.5 4.20015 44.101575 9.52% 87.47102 83.27087 85.3709451992 11.5 5.24273 60.291395 8.70% 83.27087 78.02814 80.6495051991 12.5 6.46397 80.799625 8.00% 78.02814 71.56417 74.7961551990 13.5 7.78086 105.04161 7.41% 71.56417 63.78331 67.6737401989 14.5 9.04123 131.097835 6.90% 63.78331 54.74208 59.2626951988 15.5 9.97724 154.64722 6.45% 54.74208 44.76484 49.7534601987 16.5 10.26569 169.383885 6.06% 44.76484 34.49915 39.6319951986 17.5 9.71888 170.0804 5.71% 34.49915 24.78027 29.6397101985 18.5 8.35418 154.55233 5.41% 24.78027 16.42609 20.6031801984 19.5 6.50335 126.815325 5.13% 16.42609 9.92274 13.1744151983 20.5 4.58978 94.09049 4.88% 9.92274 5.33296 7.6278501982 21.5 2.91547 62.682605 4.65% 5.33296 2.41749 3.8752251981 22.5 1.61144 36.2574 4.44% 2.41749 0.80605 1.6117701980 23.5 0.66967 15.737245 4.26% 0.80605 0.13638 0.4712151979 24.5 0.13425 3.289125 4.08% 0.13638 0.00213 0.0692551978 25.175 0.00213 0.05362275 3.97% 0.00213 0 0.000373







Accrual Factors Applicable to each vintage1987 1986 1985 1984 1983 1982 1981 1980(A) (AA) (AB) (AC) (AD) (AE) (AF) (AG)

0.31108152%0.55536457% 0.27768229%0.45157730% 0.45157730% 0.22578865%0.33350513% 0.33350513% 0.33350513% 0.16675256%0.22389171% 0.22389171% 0.22389171% 0.22389171% 0.11194585%0.13560326% 0.13560326% 0.13560326% 0.13560326% 0.13560326% 0.06780163%0.07161956% 0.07161956% 0.07161956% 0.07161956% 0.07161956% 0.07161956% 0.03580978%0.02849660% 0.02849660% 0.02849660% 0.02849660% 0.02849660% 0.02849660% 0.02849660% 0.01424830%0.00547959% 0.00547959% 0.00547959% 0.00547959% 0.00547959% 0.00547959% 0.00547959% 0.00547959%0.00008461% 0.00008461% 0.00008461% 0.00008461% 0.00008461% 0.00008461% 0.00008461% 0.00008461%2.11670383% 1.52794003% 1.02446909% 0.63192788% 0.35322946% 0.17348198% 0.06987057% 0.01981250%5.34000000% 5.16000000% 4.97000000% 4.80000000% 4.63000000% 4.48000000% 4.34000000% 4.20000000%



Page 23 of 23




2003 0.5 0.13204 0.06602 200.00% 100.0000 99.86796 99.9339802002 1.5 0.22004 0.33006 66.67% 99.86796 99.64792 99.7579402001 2.5 0.34901 0.872525 40.00% 99.64792 99.29891 99.4734152000 3.5 0.53168 1.86088 28.57% 99.29891 98.76723 99.0330701999 4.5 0.77648 3.49416 22.22% 98.76723 97.99075 98.3789901998 5.5 1.0952 6.0236 18.18% 97.99075 96.89555 97.4431501997 6.5 1.50085 9.755525 15.38% 96.89555 95.3947 96.1451251996 7.5 1.99686 14.97645 13.33% 95.39470 93.39784 94.3962701995 8.5 2.59836 22.08606 11.76% 93.39784 90.79948 92.0986601994 9.5 3.32846 31.62037 10.53% 90.79948 87.47102 89.1352501993 10.5 4.20015 44.101575 9.52% 87.47102 83.27087 85.3709451992 11.5 5.24273 60.291395 8.70% 83.27087 78.02814 80.6495051991 12.5 6.46397 80.799625 8.00% 78.02814 71.56417 74.7961551990 13.5 7.78086 105.04161 7.41% 71.56417 63.78331 67.6737401989 14.5 9.04123 131.097835 6.90% 63.78331 54.74208 59.2626951988 15.5 9.97724 154.64722 6.45% 54.74208 44.76484 49.7534601987 16.5 10.26569 169.383885 6.06% 44.76484 34.49915 39.6319951986 17.5 9.71888 170.0804 5.71% 34.49915 24.78027 29.6397101985 18.5 8.35418 154.55233 5.41% 24.78027 16.42609 20.6031801984 19.5 6.50335 126.815325 5.13% 16.42609 9.92274 13.1744151983 20.5 4.58978 94.09049 4.88% 9.92274 5.33296 7.6278501982 21.5 2.91547 62.682605 4.65% 5.33296 2.41749 3.8752251981 22.5 1.61144 36.2574 4.44% 2.41749 0.80605 1.6117701980 23.5 0.66967 15.737245 4.26% 0.80605 0.13638 0.4712151979 24.5 0.13425 3.289125 4.08% 0.13638 0.00213 0.0692551978 25.175 0.00213 0.05362275 3.97% 0.00213 0 0.000373







1979 1978 Accrued Factor Vintage Page II-12 of GF Report(AH) (AI)

0.132040000 0.03869759 2003 0.03870.220040000 0.11389584 2002 0.11330.349010000 0.18682841 2001 0.18580.531680000 0.25766806 2000 0.25620.776480000 0.32620728 1999 0.32401.095200000 0.39220220 1998 0.38941.500850000 0.45540418 1997 0.45181.996860000 0.51558049 1996 0.51152.598360000 0.57257611 1995 0.56783.328460000 0.62624368 1994 0.62044.200150000 0.67640826 1993 0.66995.242730000 0.72289842 1992 0.71536.463970000 0.76545247 1991 0.75757.780860000 0.80374611 1990 0.79529.041230000 0.83755110 1989 0.82809.977240000 0.86673706 1988 0.8572

10.265690000 0.89138970 1987 0.88119.718880000 0.91189346 1986 0.90308.354180000 0.92883870 1985 0.91956.503350000 0.94306633 1984 0.93604.589780000 0.95539347 1983 0.94922.915470000 0.96638578 1982 0.96321.611440000 0.97617901 1981 0.97650.669670000 0.98418776 1980 0.9870

0.00273980% 0.134250000 0.98953653 1979 0.99960.00008461% 0.00001481% 0.002130000 0.99304896 1978 1.00000.00282440% 0.00001481% 100.00000000 100.0004.08000000% 3.97220000%



Page 1 of 28

Appropriateness of Appropriateness ofSimplified Method Simplified Method 2003 Yr End EPC 2003 EPC 2003 Board Approved Board Approved Difference

Asset Per View of Per View of Closing Balance Depreciation Depreciation Depreciation 2003 Yr End 2003Account Gannet Fleming The Board Balance Rate Expense Rate Depreciation Base

Accounts Appoved for ELG CalculationsBoard Approved corrects for 1/2 year

EPC Distribution471.1 Land Rights Good Candidate Good Candidate $114,463.34 2.36 $2,701.00 2.14 $2,454.62 -$246.38472.1 Buildings Less Appropriate Fine for Now $481,953.69 2.49 $12,008.00 3.38 $16,265.94 $4,257.94472.2 Site Development Good Candidate Good Candidate $291,723.32 4.16 $12,126.00 3.87 $11,276.72 -$849.28473.1 Wood Poles Not Appropriate Not Appropriate $60,925,143.65 2.43 $1,479,962.00 2.20 $1,342,042.76 -$137,919.24473.2 Overhead Transformers Good Candidate Good Candidate $1,075.22 3.05 $33.00 2.16 $23.25 -$9.75473.9 Insulators Not Appropriate Fine for Now $42,894.70 2.97 $1,275.00 2.12 $908.75 -$366.25474.1 Primary Conductor - Overhead Not Appropriate Not Appropriate $31,974,113.42 2.64 $844,153.00 2.56 $818,722.16 -$25,430.84474.2 Secondary Conductor - Overhead Not Appropriate Not Appropriate $5,553,764.48 1.84 $102,190.00 1.82 $101,339.30 -$850.70474.3 Fault Indicators - Overhead Not Appropriate Not Appropriate $220,645.73 2.11 $4,663.00 2.11 $4,663.00 $0.00474.6 Switches - Overhead Not Appropriate Not Appropriate $5,850,632.64 1.51 $88,207.00 1.46 $85,507.42 -$2,699.58475.1 Underground Conduit Not Appropriate Fine for Now $20,692,210.44 2.56 $529,317.00 2.22 $460,175.71 -$69,141.29475.2 Transformer Pads Not Appropriate Fine for Now $28,842,109.25 1.92 $554,143.00 1.62 $466,065.57 -$88,077.43475.3 Pull Boxes Good Candidate Good Candidate $12,062,991.96 2.41 $290,961.00 2.24 $269,933.82 -$21,027.18475.5 Manholes Good Candidate Good Candidate $4,255,577.15 1.86 $79,175.00 1.70 $72,149.70 -$7,025.30476.1 Primary Cable - Underground Not Appropriate Not Appropriate $105,363,402.20 3.05 $3,211,492.00 2.83 $2,980,117.63 -$231,374.37476.2 Secondary Cable - Underground Less Appropriate Not Appropriate $34,824,024.03 3.68 $1,279,880.00 3.40 $1,182,964.07 -$96,915.93476.6 Switches - Underground Not Appropriate Not Appropriate $11,801,755.21 3.32 $392,314.00 3.18 $375,512.47 -$16,801.53477.1 Transformers - Overhead Not Appropriate Not Appropriate -$3,147,156.78 2.21 -$69,702.00 2.93 -$92,270.40 -$22,568.40477.3 Transformers - Padmount Not Appropriate Not Appropriate $47,127,921.32 2.62 $1,233,845.00 2.52 $1,185,578.01 -$48,266.99477.4 Transformers - Minipad Not Appropriate Fine for Now $44,233,097.26 2.73 $1,205,836.00 2.49 $1,102,590.47 -$103,245.53477.5 Transformers - Substations Not Appropriate Fine for Now $829,960.16 3.07 $25,509.00 2.55 $21,183.58 -$4,325.42477.6 Switchgear Not Appropriate Fine for Now $1,390,285.29 3.42 $47,495.00 3.43 $47,666.92 $171.92477.7 Structures Not Appropriate Fine for Now $6,000.00 1.25 $75.00 14.37 $862.00 $787.00477.8 Protection Not Appropriate Fine for Now $1,115,594.14 3.76 $41,951.00 3.24 $36,181.43 -$5,769.57478.1 Telecontrol Less Appropriate Fine for Now $7,622.17 2.88 $220.00 2.15 $164.10 -$55.90478.2 Supervisory Equipment Good Candidate Good Candidate $1,120,889.06 8.45 $94,694.00 8.67 $97,143.72 $2,449.72479 Meters Good Candidate Good Candidate $36,770,081.55 3.53 $1,297,915.00 3.38 $1,241,057.67 -$56,857.33Total EPC Distribution $452,752,774.60 $12,762,438.00 $11,830,280.38 -$932,157.62

-$582,827.58% Effect of 1/2 yr correction on ELG Accts 63%

(Board Approved Rates) EUB Decision 2006-002 (January 13, 2006)


Page 2 of 28

Appropriateness of Appropriateness ofSimplified Method Simplified Method 2003 Yr End EPC 2003 EPC 2003 Board Approved Board Approved Difference

Asset Per View of Per View of Closing Balance Depreciation Depreciation Depreciation 2003 Yr End 2003Account Gannet Fleming The Board Balance Rate Expense Rate Depreciation Base

Accounts Appoved for ELG CalculationsEPC Network493.1 Wood Poles Less Appropriate Fine for Now $519,114.08 2.87 $14,914.00 2.81 $14,595.29 -$318.71494.1 Primary Conductor - Overhead Less Appropriate Fine for Now $28,720.00 2.76 $793.00 2.74 $786.93 -$6.07494.2 Secondary Conductor - Overhead Less Appropriate Fine for Now $323,398.74 3.29 $10,626.00 3.22 $10,401.18 -$224.82494.6 Switches - Overhead Less Appropriate Fine for Now -$18.22 0.00 $0.00 2.24 -$0.41 -$0.41495.1 Conduit - Underground Less Appropriate Fine for Now $8,353,388.58 2.40 $200,255.00 2.31 $193,279.34 -$6,975.66495.2 Transformer Pads Less Appropriate Fine for Now $37,563.70 2.30 $865.00 2.08 $781.46 -$83.54495.3 Pull Boxes Less Appropriate Fine for Now $52,590.42 2.17 $1,141.00 1.86 $978.11 -$162.89495.4 Vaults Less Appropriate Fine for Now $20,183,465.70 2.46 $496,848.00 2.33 $471,117.97 -$25,730.03495.5 Manholes Less Appropriate Fine for Now $15,745,171.70 2.28 $359,668.00 2.83 $444,921.93 $85,253.93496.1 Primary Cable - Underground Less Appropriate Fine for Now $29,729,792.52 5.91 $1,757,334.00 5.88 $1,749,413.93 -$7,920.07496.2 Secondary Cable- Underground Less Appropriate Fine for Now $10,970,301.09 5.53 $606,959.00 5.28 $578,693.78 -$28,265.22496.6 Switches - Underground Less Appropriate Fine for Now $1,071,978.78 4.66 $49,948.00 4.39 $47,033.33 -$2,914.67497.1 Transformers - Overhead Less Appropriate Fine for Now $200,661.58 7.11 $14,265.00 7.84 $15,741.49 $1,476.49497.2 Transformers - Underground Less Appropriate Fine for Now $32,197,626.07 5.55 $1,787,789.00 5.30 $1,707,235.00 -$80,554.00497.3 Transformers - Padmount Less Appropriate Fine for Now -$11,350.00 1.44 -$163.00 1.52 -$172.38 -$9.38497.4 Transformers - Padmount Less Appropriate Fine for Now -$28.00 0.00 $0.00 3.89 -$220.52 -$220.52497.6 Switchgear Less Appropriate Fine for Now $407,889.45 3.57 $14,567.00 2.70 $11,016.95 -$3,550.05497.7 Structures Less Appropriate Fine for Now 0.00 $0.00 0.00 $0.00 $0.00497.8 Protection Less Appropriate Fine for Now 0.00 $0.00 0.00 $0.00 $0.00498.1 Telecontrol Less Appropriate Fine for Now -$1,250.73 2.38 -$30.00 2.19 -$27.35 $2.65498.2 Supervisory Less Appropriate Fine for Now $1,525,743.65 1.18 $17,929.00 0.55 $8,364.66 -$9,564.34Total EPC Network $121,334,759.11 $5,333,708.00 $5,253,940.70 -$79,767.30

Total EPC Distribution and Network $574,087,533.71 3.2% $18,096,146 3.0% $17,084,221EPC General480 Structures and Improvements482.1 South Service center Not Appropriate To be determined 2.13 $603,032 2.13 $603,032 $0.00482.3 Leasehold Improvememts Good Candidate Good Candidate 20.00 $312,755 20.00 $312,755 $0.21Sub-Total $915,787 915,787 $0.21483.1 Office Furniture and Equipment Good Candidate Good Candidate 4.98 $356,934 4.98 $356,934 $0.00484 Vehicles Not Appropriate To be determined 2.65 $485,951 2.65 $485,951 $0.00485.1 Tools and Instruments Good Candidate Good Candidate 4.15 $476,646 4.15 $476,646 $0.00485.2 Radios Good Candidate Good Candidate 5.49 $98,535 5.49 $98,535 $0.00487.1 Computer Systems - Software Good Candidate Good Candidate 16.63 $10,747,480 16.63 $10,747,480 $0.00487.2 Computer Systems - Hardware Good Candidate Good Candidate 19.38 $3,784,000 19.38 $3,784,000 $0.00487.3 Computer Systems - Enterprise Software Good Candidate Good Candidate 10.00 $900,867 10.00 $900,867 $0.00Sub-Total $16,850,413 $16,850,413Total EPC General $17,766,200 $17,766,200

Grand Total -$1,011,924.92

(Board Approved Rates) EUB Decision 2006-002 (January 13, 2006)

2005-2006 DT

Simplified Depreciation Rates

ENMAX Power CorporationAppendix 9Page 3 of 28

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56789101112131415161718192021222324252627282930313233

A B C D E F G H I J K L2003 Yr End 2003 Yr End 2003 Yr End 2003 2003 Yr End 2003 Yr End Average True-Up 2003 Simplified

Asset Closing Balance Theoretical Actual Annual Accrued Accrued Remaining Adjusted Depreciation Account Balance Accrued Dep Accrued Dep Accruals Shortfall/(Excess) Percent Variance Life Accrual RateEPC Distribution471.1 Land Rights $114,463.34 $25,502.95 $0.00 $1,907.72 $25,502.95 100.0% 46.6 $546.90 $2,454.62 2.14472.1 Buildings $481,953.69 $517,818.35 $510,765.00 $16,265.94 $7,053.35 1.4% 8.2 $0.00 $16,265.94 3.38472.2 Site Development $291,723.32 $106,019.05 $94,892.00 $10,835.44 $11,127.05 11.7% 25.2 $441.28 $11,276.72 3.87473.1 Wood Poles $60,925,143.65 $22,093,578.28 $32,683,988.00 $1,370,815.73 -$10,590,409.72 -32.4% 43.9 -$241,333.42 $1,129,482.31 1.85473.2 Overhead Transformers $1,075.22 $108.87 $161.00 $24.19 -$52.13 -32.4% 55.5 -$0.94 $23.25 2.16473.9 Insulators $42,894.70 $5,983.83 $9,017.00 $965.13 -$3,033.17 -33.6% 53.8 -$56.38 $908.75 2.12474.1 Primary Conductor - Overhead $31,974,113.42 $14,366,789.27 $18,773,426.00 $813,886.52 -$4,406,636.73 -23.5% 37.3 -$117,988.81 $695,897.71 2.18474.2 Secondary Conductor - Overhead $5,553,764.48 $3,451,331.34 $4,996,808.00 $128,163.80 -$1,545,476.66 -30.9% 38.1 -$40,594.66 $87,569.13 1.58474.3 Fault Indicators - Overhead $220,645.73 $23,444.00 $44,126.00 $3,903.73 -$20,682.00 -46.9% 59.0 -$350.58 $3,553.16 1.61474.6 Switches - Overhead $5,850,632.64 $1,921,993.15 $3,627,719.00 $103,511.19 -$1,705,725.85 -47.0% 46.4 -$36,735.98 $66,775.22 1.14475.1 Underground Conduit $20,692,210.44 $6,039,800.80 $9,159,731.00 $551,792.28 -$3,119,930.20 -34.1% 34.1 -$91,616.57 $460,175.71 2.22475.2 Transformer Pads $28,842,109.25 $8,354,745.92 $13,950,783.00 $576,842.19 -$5,596,037.08 -40.1% 50.5 -$110,776.62 $466,065.57 1.62475.3 Pull Boxes $12,062,991.96 $4,266,999.30 $5,717,768.00 $301,574.80 -$1,450,768.70 -25.4% 45.9 -$31,640.98 $269,933.82 2.24475.5 Manholes $4,255,577.15 $1,667,095.10 $2,507,769.00 $92,204.17 -$840,673.90 -33.5% 41.9 -$20,054.47 $72,149.70 1.70476.1 Primary Cable - Underground $105,363,402.20 $39,442,051.88 $44,052,975.00 $3,043,831.62 -$4,610,923.12 -10.5% 32.0 -$143,902.60 $2,899,929.02 2.75476.2 Secondary Cable - Underground $34,824,024.03 $11,662,922.58 $11,751,216.00 $1,160,800.80 -$88,293.42 -0.8% 35.0 $0.00 $1,160,800.80 3.33476.6 Switches - Underground $11,801,755.21 $4,876,117.27 $5,209,597.00 $370,912.31 -$333,479.73 -6.4% 21.9 $0.00 $370,912.31 3.14477.1 Transformers - Overhead -$3,147,156.78 -$889,702.05 -$1,759,384.00 -$80,109.45 $869,681.95 -49.4% 43.9 $19,813.27 -$60,296.18 1.92477.3 Transformers - Padmount $47,127,921.32 $15,118,964.51 $19,881,166.00 $1,199,619.82 -$4,762,201.49 -24.0% 42.4 -$112,324.36 $1,087,295.45 2.31477.4 Transformers - Minipad $44,233,097.26 $14,450,960.26 $18,125,646.00 $1,179,549.26 -$3,674,685.74 -20.3% 47.7 -$76,958.79 $1,102,590.47 2.49477.5 Transformers - Substations $829,960.16 $693,904.11 $822,224.00 $26,558.73 -$128,319.89 -15.6% 23.9 -$5,375.14 $21,183.58 2.55477.6 Switchgear $1,390,285.29 $863,582.86 $840,539.00 $47,666.92 $23,043.86 2.7% 16.9 $0.00 $47,666.92 3.43477.7 Structures $6,000.00 $6,257.14 $7,293.00 $171.43 -$1,035.86 -14.2% -1.5 $690.57 $862.00 14.37477.8 Protection $1,115,594.14 $372,150.71 $383,991.00 $36,181.43 -$11,840.29 -3.1% 26.7 $0.00 $36,181.43 3.24478.1 Telecontrol $7,622.17 $1,063.77 $2,398.00 $206.00 -$1,334.23 -55.6% 31.8 -$41.91 $164.10 2.15478.2 Supervisory Equipment $1,120,889.06 $935,245.07 $874,811.00 $97,143.72 $60,434.07 6.9% 5.4 $0.00 $97,143.72 8.67479 Meters $36,770,081.55 $11,217,964.01 $6,585,003.00 $1,050,573.76 $4,632,961.01 70.4% 24.3 $190,483.91 $1,241,057.67 3.38Total EPC Distribution $452,752,774.60 $161,592,692.32 $198,854,428.00 $12,105,799.18 -$37,261,735.68 -$817,776.28 $11,288,022.90

(Simplified Dep Rates) EUB Decision 2006-002 (January 13, 2006)

2005-2006 DT

Simplified Depreciation Rates

ENMAX Power CorporationAppendix 9Page 4 of 28

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A B C D E F G H I J K L2003 Yr End 2003 Yr End 2003 Yr End 2003 2003 Yr End 2003 Yr End Average True-Up 2003 Simplified

Asset Closing Balance Theoretical Actual Annual Accrued Accrued Remaining Adjusted Depreciation Account Balance Accrued Dep Accrued Dep Accruals Shortfall/(Excess) Percent Variance Life Accrual Rate

3637383940414243444546474849505152535455565758

62636465666768697071727374

75

EPC Network493.1 Wood Poles $519,114.08 $364,440.96 $272,048.00 $11,247.47 $92,392.96 34.0% 27.6 $3,347.82 $14,595.29 2.81494.1 Primary Conductor - Overhead $28,720.00 $23,936.95 $21,101.00 $670.13 $2,835.95 13.4% 24.3 $116.80 $786.93 2.74494.2 Secondary Conductor - Overhead $323,398.74 $243,411.62 $164,200.04 $7,545.97 $79,211.58 48.2% 27.7 $2,855.21 $10,401.18 3.22494.6 Switches - Overhead -$18.22 -$2.34 -$3.30 -$0.43 $0.96 -29.1% 54.5 $0.02 -$0.41 2.24495.1 Conduit - Underground $8,353,388.58 $4,106,127.43 $3,177,651.06 $167,067.77 $928,476.37 29.2% 35.4 $26,211.57 $193,279.34 2.31495.2 Transformer Pads $37,563.70 $13,185.10 $11,903.50 $751.27 $1,281.60 10.8% 42.4 $30.19 $781.46 2.08495.3 Pull Boxes $52,590.42 $4,638.24 $8,734.96 $1,051.81 -$4,096.72 -46.9% 55.6 -$73.69 $978.11 1.86495.4 Vaults $20,183,465.70 $9,731,508.57 $7,310,616.00 $403,669.31 $2,420,892.57 33.1% 35.9 $67,448.66 $471,117.97 2.33495.5 Manholes $15,745,171.70 $12,082,985.14 $9,270,743.00 $314,903.43 $2,812,242.14 30.3% 21.6 $130,018.50 $444,921.93 2.83496.1 Primary Cable - Underground $29,729,792.52 $16,484,269.45 $7,011,114.00 $1,139,642.05 $9,473,155.45 135.1% 15.5 $609,771.88 $1,749,413.93 5.88496.2 Secondary Cable- Underground $10,970,301.09 $6,835,621.36 $2,923,314.00 $411,386.29 $3,912,307.36 133.8% 23.4 $167,307.49 $578,693.78 5.28496.6 Switches - Underground $1,071,978.78 $384,795.29 $176,848.00 $40,199.20 $207,947.29 117.6% 30.4 $6,834.12 $47,033.33 4.39497.1 Transformers - Overhead $200,661.58 $215,829.56 $100,567.00 $6,688.72 $115,262.56 114.6% 12.7 $9,052.77 $15,741.49 7.84497.2 Transformers - Underground $32,197,626.07 $25,348,770.11 $11,793,378.00 $1,073,254.20 $13,555,392.11 114.9% 21.4 $633,980.80 $1,707,235.00 5.30497.3 Transformers - Padmount -$11,350.00 $31,988.38 $5,309.00 -$378.31 $26,679.38 502.5% 129.6 $205.93 -$172.38 1.52497.4 Transformers - Padmount -$5,663.78 -$1,222.24 $0.00 -$188.79 -$1,222.24 -100.0% 38.5 -$31.73 -$220.52 3.89497.6 Switchgear $407,889.45 $68,445.43 $171,532.00 $13,596.32 -$103,086.57 -60.1% 40.0 -$2,579.36 $11,016.95 2.70497.7 Structures497.8 Protection498.1 Telecontrol -$1,250.73 -$125.07 -$143.00 -$27.79 $17.93 -12.5% 40.5 $0.44 -$27.35 2.19498.2 Supervisory $1,525,743.65 $768,575.39 $1,338,946.00 $33,905.41 -$570,370.61 -42.6% 22.3 -$25,540.76 $8,364.66 0.55Total EPC Network $121,329,123.33 $76,707,179 $43,757,859.26 $3,624,984.05 $32,949,320.07 $1,628,956.65 $5,253,940.70

EPC General480 Structures and Improvements482.1 South Service center $28,355,568.85 $636,283.00 -$33,251.00 $603,032.00 2.13482.3 Leasehold Improvememts $1,563,776.05 $312,755.00 $0.00 $312,755.00 20.00Sub-Total $29,919,344.90 $949,038.00 -$33,251.00 $915,787.00483.1 Office Furniture and Equipment $7,162,077.85 $356,934.00 $0.00 $356,934.00 4.98484 Vehicles $18,314,304.23 $1,272,508.00 -$786,557.00 $485,951.00 2.65485.1 Tools and Instruments $11,479,969.37 $573,998.00 -$97,352.00 $476,646.00 4.15485.2 Radios $1,795,179.68 $119,738.00 -$21,203.00 $98,535.00 5.49487.1 Computer Systems - Software $64,645,378.11 $10,747,480.00 $0.00 $10,747,480.00 16.63487.2 Computer Systems - Hardware $19,527,364.57 $3,784,000.00 $0.00 $3,784,000.00 19.38487.3 Computer Systems - Enterprise Software $9,008,667.08 $900,867.00 $0.00 $900,867.00 10.00Sub-Total $131,932,940.89 $17,755,525.00 -$905,112.00 $16,850,413.00Total EPC General $161,852,285.79 $18,704,563.00 -$938,363.00 $17,766,200.00

(Simplified Dep Rates) EUB Decision 2006-002 (January 13, 2006)


Acct 471.1 Land Rights Acct 472.1 Buildings Acct 472.2 Site DevelopmentYear Surviving Plant Age Year Surviving Plant Age Year Surviving Plant Age

2002 $0.00 1.5 $0.00 2002 $0.00 1.5 $0.00 2002 $0.00 1.5 $0.002003 $0.00 0.5 $0.00 2003 $0.00 0.5 $0.00 2003 $77,903.14 0.5 $38,951.57

$114,463.34 13.4 $1,530,176.75 $481,953.69 31.8 $15,342,766.01 $291,723.32 9.8 $2,854,359.11

ASL 60 ASL 40 ASL 35

Ave Rem Life 46.6 Ave Rem Life 8.2 Ave Rem Life 25.2

Annual Accrual $1,907.72 Annual Accrual $12,048.84 Annual Accrual $8,334.95Salvage Adjustment 0 $1,907.72 Salvage Adjustment -35 $16,265.94 Salvage Adjustment -30 $10,835.44

Theor Accruals $25,502.95 Theor Accruals $383,569.15 Theor Accruals $81,553.12Salvage Adjustment 0 $25,502.95 Salvage Adjustment -35 $517,818.35 Salvage Adjustment -30 $106,019.05

Acct 471.1 Land Rights Acct 472.1 Buildings Acct 472.2 Site Development

PROOF2000 $0.00 $0.00 2000 $0.00 $0.00 2000 $0.00 $0.002001 $666.22 $1,665.56 2001 $0.00 $0.00 2001 $0.00 $0.002002 $0.00 $0.00 2002 $0.00 $0.00 2002 $0.00 $0.002003 $0.00 $0.00 2003 $0.00 $0.00 2003 $2,225.80 $1,112.90

$1,907.72 $25,502.95 $12,048.84 $383,569.15 $8,334.95 $81,553.12

$1,907.72 $25,502.95 $12,048.84 $383,569.15 $8,334.95 $81,553.12

$0.00 $0.00 $0.00 $0.00 $0.00 $0.00

(Distribution Assets) EUB Decision 2006-002 (January 13, 2006)


PROOF

Acct 473.1 Wood Poles Acct 473.2 Overhead Transformers Acct 473.9 InsulatorsYear Surviving Plant Age Year Surviving Plant Age Year Surviving Plant Age

2002 $3,406,364.72 1.5 $5,109,547.08 2002 $0.00 1.5 $0.00 2002 $0.00 1.5 $0.002003 $3,553,501.72 0.5 $1,776,750.86 2003 $0.00 0.5 $0.00 2003 $0.00 0.5 $0.00

$60,925,143.65 16.1 $981,936,812.44 $1,075.22 4.5 $4,838.49 $42,894.70 6.2 $265,947.86



Annual Accrual $1,015,419.06 Annual Accrual $17.92 Annual Accrual $714.91Salvage Adjustment -35 $1,370,815.73 Salvage Adjustment -35 $24.19 Salvage Adjustment -35 $965.13

Theor Accruals $16,365,613.54 Theor Accruals $80.64 Theor Accruals $4,432.46Salvage Adjustment -35 $22,093,578.28 Salvage Adjustment -35 $108.87 Salvage Adjustment -35 $5,983.83

Acct 473.1 Wood Poles Acct 473.2 Overhead Transformers Acct 473.9 Insulators

2000 $39,088.95 $136,811.34 2000 $0.00 $0.00 2000 $0.00 $0.002001 $65,746.54 $164,366.35 2001 $0.00 $0.00 2001 $0.00 $0.002002 $56,772.75 $85,159.12 2002 $0.00 $0.00 2002 $0.00 $0.002003 $59,225.03 $29,612.51 2003 $0.00 $0.00 2003 $0.00 $0.00

$1,015,419.06 $16,365,613.54 $17.92 $80.64 $714.91 $4,432.46

$1,015,419.06 $16,365,613.54 $17.92 $80.64 $714.91 $4,432.46

$0.00 $0.00 $0.00 $0.00 $0.00 $0.00



PROOF

Acct 474.1 Primary Conductor - Overhead Acct 474.2 Secondary Conductor - Overhead Acct 474.3 Fault Indicators - OverheadYear Surviving Plant Age Year Surviving Plant Age Year Surviving Plant Age

2002 $864,208.20 1.5 $1,296,312.30 2002 $38,323.09 1.5 $57,484.64 2002 $0.00 1.5 $0.002003 $1,114,431.07 0.5 $557,215.54 2003 $62,290.60 0.5 $31,145.30 2003 $0.00 0.5 $0.00

$31,974,113.42 17.7 $564,409,578.39 $5,553,764.48 26.9 $149,557,691.23 $220,645.73 6.0 $1,325,095.71



Annual Accrual $581,347.52 Annual Accrual $85,442.53 Annual Accrual $3,394.55Salvage Adjustment -40 $813,886.52 Salvage Adjustment -50 $128,163.80 Salvage Adjustment -15 $3,903.73

Theor Accruals $10,261,992.33 Theor Accruals $2,300,887.56 Theor Accruals $20,386.09Salvage Adjustment -40 $14,366,789.27 Salvage Adjustment -50 $3,451,331.34 Salvage Adjustment -15 $23,444.00

Acct 474.1 Primary Conductor - Overhead Acct 474.2 Secondary Conductor - Overhead Acct 474.3 Fault Indicators - Overhead

2000 $19,675.25 $68,863.36 2000 $776.52 $2,717.84 2000 $36.33 $127.142001 $23,249.29 $58,123.23 2001 $528.20 $1,320.50 2001 $0.00 $0.002002 $15,712.88 $23,569.31 2002 $589.59 $884.38 2002 $0.00 $0.002003 $20,262.38 $10,131.19 2003 $958.32 $479.16 2003 $0.00 $0.00

$581,347.52 $10,261,992.33 $85,442.53 $2,300,887.56 $3,394.55 $20,386.09

$581,347.52 $10,261,992.33 $85,442.53 $2,300,887.56 $3,394.55 $20,386.09

$0.00 $0.00 $0.00 $0.00 $0.00 $0.00



PROOF

Acct 474.6 Switches - Overhead Acct 475.1 Underground ConduitYear Surviving Plant Age Year Surviving Plant Age

2002 $213,456.05 1.5 $320,184.08 2002 $3,421,058.80 1.5 $5,131,588.202003 $199,764.08 0.5 $99,882.04 2003 $3,845,145.02 0.5 $1,922,572.51

$5,850,632.64 18.6 $108,634,395.37 $20,692,210.44 10.9 $226,492,530.02

ASL 65 ASL 45

Ave Rem Life 46.4 Ave Rem Life 34.1

Annual Accrual $90,009.73 Annual Accrual $459,826.90Salvage Adjustment -15 $103,511.19 Salvage Adjustment -20 $551,792.28

Theor Accruals $1,671,298.39 Theor Accruals $5,033,167.33Salvage Adjustment -15 $1,921,993.15 Salvage Adjustment -20 $6,039,800.80

Acct 474.6 Switches - Overhead Acct 475.1 Underground Conduit

2000 $2,545.20 $8,908.19 2000 $34,160.02 $119,560.062001 $1,063.96 $2,659.91 2001 $38,757.45 $96,893.622002 $3,283.94 $4,925.91 2002 $76,023.53 $114,035.292003 $3,073.29 $1,536.65 2003 $85,447.67 $42,723.83

$90,009.73 $1,671,298.39 $459,826.90 $5,033,167.33

$90,009.73 $1,671,298.39 $459,826.90 $5,033,167.33

$0.00 $0.00 $0.00 $0.00



PROOF

Acct 475.2 Transformer Pads Acct 475.3 Pull BoxesYear Surviving Plant Age Year Surviving Plant Age

2002 $1,616,280.84 1.5 $2,424,421.26 2002 $801,391.27 1.5 $1,202,086.912003 $2,117,714.60 0.5 $1,058,857.30 2003 $860,245.79 0.5 $430,122.90

$28,842,109.25 14.5 $417,737,296.04 $12,062,991.96 14.1 $170,679,971.99

ASL 65 ASL 60




Acct 475.2 Transformer Pads Acct 475.3 Pull Boxes

2000 $7,060.17 $24,710.59 2000 $4,386.09 $15,351.322001 $13,288.51 $33,221.27 2001 $6,171.69 $15,429.232002 $24,865.86 $37,298.79 2002 $13,356.52 $20,034.782003 $32,580.22 $16,290.11 2003 $14,337.43 $7,168.71

$443,724.76 $6,426,727.63 $201,049.87 $2,844,666.20

$443,724.76 $6,426,727.63 $201,049.87 $2,844,666.20

$0.00 $0.00 $0.00 $0.00



Page 10 of 28

PROOF

Acct 475.5 Pull Boxes Acct 476.1 Primary Cable - Underground Acct 476.2 Secondary Cable - UndergroundYear Surviving Plant Age Year Surviving Plant Age Year Surviving Plant Age

2002 $0.00 1.5 $0.00 2002 $1,043,989.63 1.5 $1,565,984.45 2002 $3,697,243.41 1.5 $5,545,865.122003 $0.00 0.5 $0.00 2003 $13,586,302.15 0.5 $6,793,151.08 2003 $4,932,129.93 0.5 $2,466,064.97

$4,255,577.15 18.1 $76,942,850.87 $105,363,402.20 13.0 $1,365,301,795.98 $34,824,024.03 10.0 $349,887,677.52



Annual Accrual $70,926.29 Annual Accrual $2,341,408.94 Annual Accrual $773,867.20Salvage Adjustment -30 $92,204.17 Salvage Adjustment -30 $3,043,831.62 Salvage Adjustment -50 $1,160,800.80

Theor Accruals $1,282,380.85 Theor Accruals $30,340,039.91 Theor Accruals $7,775,281.72Salvage Adjustment -30 $1,667,095.10 Salvage Adjustment -30 $39,442,051.88 Salvage Adjustment -50 $11,662,922.58

Acct 475.5 Pull Boxes Acct 476.1 Primary Cable - Underground Acct 476.2 Secondary Cable - Underground

2000 $0.00 $0.00 2000 $146,697.06 $513,439.73 2000 $22,876.99 $80,069.472001 $4,234.24 $10,585.61 2001 $202,422.00 $506,054.99 2001 $50,530.03 $126,325.072002 $0.00 $0.00 2002 $23,199.77 $34,799.65 2002 $82,160.96 $123,241.452003 $0.00 $0.00 2003 $301,917.83 $150,958.91 2003 $109,602.89 $54,801.44

$70,926.29 $1,282,380.85 $2,341,408.94 $30,340,039.91 $773,867.20 $7,775,281.72

$70,926.29 $1,282,380.85 $2,341,408.94 $30,340,039.91 $773,867.20 $7,775,281.72

$0.00 $0.00 $0.00 $0.00 $0.00 $0.00



Page 11 of 28

PROOF

Acct 476.6 Switches - Underground Acct 477.1 Transformers - Overhead Acct 477.3 Transformers - PadmountYear Surviving Plant Age Year Surviving Plant Age Year Surviving Plant Age

2002 $497,464.16 1.5 $746,196.24 2002 $643,755.18 1.5 $965,632.77 2002 $2,718,047.87 1.5 $4,077,071.812003 $909,192.89 0.5 $454,596.45 2003 $1,499,543.40 0.5 $749,771.70 2003 $3,207,106.45 0.5 $1,603,553.23

$11,801,755.21 13.1 $155,149,185.73 -$3,147,156.78 11.1 -$34,952,580.64 $47,127,921.32 12.6 $593,959,319.95



Annual Accrual $337,193.01 Annual Accrual -$57,221.03 Annual Accrual $856,871.30Salvage Adjustment -10 $370,912.31 Salvage Adjustment -40 -$80,109.45 Salvage Adjustment -40 $1,199,619.82

Theor Accruals $4,432,833.88 Theor Accruals -$635,501.47 Theor Accruals $10,799,260.36Salvage Adjustment -10 $4,876,117.27 Salvage Adjustment -40 -$889,702.05 Salvage Adjustment -40 $15,118,964.51

Acct 476.6 Switches - Underground Acct 477.1 Transformers - Overhead Acct 477.3 Transformers - Padmount

2000 $4,513.61 $15,797.63 2000 $2,570.44 $8,996.54 2000 $37,964.36 $132,875.252001 $9,970.48 $24,926.19 2001 $11,499.07 $28,747.69 2001 $46,082.81 $115,207.032002 $14,213.26 $21,319.89 2002 $11,704.64 $17,556.96 2002 $49,419.05 $74,128.582003 $25,976.94 $12,988.47 2003 $27,264.43 $13,632.21 2003 $58,311.03 $29,155.51

$337,193.01 $4,432,833.88 -$57,221.03 -$635,501.47 $856,871.30 $10,799,260.36

$337,193.01 $4,432,833.88 -$57,221.03 -$635,501.47 $856,871.30 $10,799,260.36

$0.00 $0.00 $0.00 $0.00 $0.00 $0.00



Page 12 of 28

PROOF

Acct 477.4 Transformers - Minipad Acct 477.5 Transformers - SubstationsYear Surviving Plant Age Year Surviving Plant Age

2002 $3,421,760.59 1.5 $5,132,640.89 2002 $0.00 1.5 $0.002003 $4,652,844.45 0.5 $2,326,422.23 2003 $196,595.70 0.5 $98,297.85

$44,233,097.26 12.3 $541,911,009.63 $829,960.16 26.1 $21,684,503.30

ASL 60 ASL 50


Annual Accrual $737,218.29 Annual Accrual $16,599.20Salvage Adjustment -60 $1,179,549.26 Salvage Adjustment -60 $26,558.73

Theor Accruals $9,031,850.16 Theor Accruals $433,690.07Salvage Adjustment -60 $14,450,960.26 Salvage Adjustment -60 $693,904.11

Acct 477.4 Transformers - Minipad Acct 477.5 Transformers - Substations

2000 $20,766.34 $72,682.19 2000 $0.00 $0.002001 $40,283.89 $100,709.71 2001 $0.00 $0.002002 $57,029.34 $85,544.01 2002 $0.00 $0.002003 $77,547.41 $38,773.70 2003 $3,931.91 $1,965.96

$737,218.29 $9,031,850.16 $16,599.20 $433,690.07

$737,218.29 $9,031,850.16 $16,599.20 $433,690.07

$0.00 $0.00 $0.00 $0.00



Page 13 of 28

PROOF

Acct 477.6 Switchgear Acct 477.7 Structures Acct 477.8 ProtectionYear Surviving Plant Age Year Surviving Plant Age Year Surviving Plant Age

2002 $0.00 1.5 $0.00 2002 $0.00 1.5 $0.00 2002 $0.00 1.5 $0.002003 $213,045.46 0.5 $106,522.73 2003 $0.00 0.5 $0.00 2003 $104,831.40 0.5 $52,415.70

$1,390,285.29 18.1 $25,187,833.39 $6,000.00 36.5 $219,000.00 $1,115,594.14 10.3 $11,474,646.91


Ave Rem Life 16.9 Ave Rem Life -1.5 Ave Rem Life 26.7

Annual Accrual $39,722.44 Annual Accrual $171.43 Annual Accrual $30,151.19Salvage Adjustment -20 $47,666.92 Salvage Adjustment 0 $171.43 Salvage Adjustment -20 $36,181.43

Theor Accruals $719,652.38 Theor Accruals $6,257.14 Theor Accruals $310,125.59Salvage Adjustment -20 $863,582.86 Salvage Adjustment 0 $6,257.14 Salvage Adjustment -20 $372,150.71

Acct 477.6 Switchgear Acct 477.7 Structures Acct 477.8 Protection

2000 $631.93 $2,211.74 2000 $0.00 $0.00 2000 $0.00 $0.002001 $0.00 $0.00 2001 $0.00 $0.00 2001 $77.63 $194.072002 $0.00 $0.00 2002 $0.00 $0.00 2002 $0.00 $0.002003 $6,087.01 $3,043.51 2003 $0.00 $0.00 2003 $2,833.28 $1,416.64

$39,722.44 $719,652.38 $171.43 $6,257.14 $30,151.19 $310,125.59

$39,722.44 $719,652.38 $171.43 $6,257.14 $30,151.19 $310,125.59

$0.00 $0.00 $0.00 $0.00 $0.00 $0.00



Page 14 of 28

PROOF

Acct 478.1 Telecontrol Acct 478.2 Supervisory Equipment Acct 479 MetersYear Surviving Plant Age Year Surviving Plant Age Year Surviving Plant Age

2002 $0.00 1.5 $0.00 2002 $0.00 1.5 $0.00 2002 $2,123,089.63 1.5 $3,184,634.452003 $0.00 0.5 $0.00 2003 $6,276.37 0.5 $3,138.19 2003 $7,023,508.17 0.5 $3,511,754.09

$7,622.17 5.2 $39,359.61 $1,120,889.06 9.6 $10,791,289.25 $36,770,081.55 10.7 $392,628,740.45



Annual Accrual $206.00 Annual Accrual $74,725.94 Annual Accrual $1,050,573.76Salvage Adjustment 0 $206.00 Salvage Adjustment -30 $97,143.72 Salvage Adjustment 0 $1,050,573.76

Theor Accruals $1,063.77 Theor Accruals $719,419.28 Theor Accruals $11,217,964.01Salvage Adjustment 0 $1,063.77 Salvage Adjustment -30 $935,245.07 Salvage Adjustment 0 $11,217,964.01

Acct 478.1 Telecontrol Acct 478.2 Supervisory Equipment Acct 479 Meters

2000 $29.94 $104.78 2000 $0.00 $0.00 2000 $59,015.46 $206,554.112001 $0.00 $0.00 2001 $0.00 $0.00 2001 $75,375.56 $188,438.902002 $0.00 $0.00 2002 $0.00 $0.00 2002 $60,659.70 $90,989.562003 $0.00 $0.00 2003 $418.42 $209.21 2003 $200,671.66 $100,335.83

$206.00 $1,063.77 $74,725.94 $719,419.28 $1,050,573.76 $11,217,964.01

$206.00 $1,063.77 $74,725.94 $719,419.28 $1,050,573.76 $11,217,964.01

$0.00 $0.00 $0.00 $0.00 $0.00 $0.00



Page 15 of 28

Acct 493.1 Wood Poles Acct 494.1 Primary Conductor - Overhead Acct 494.2 Secondary Conductor - OverheadYear Surviving Plant Age Year Surviving Plant Age Year Surviving Plant Age

2002 $0.00 1.5 $0.00 2002 $0.00 1.5 $0.00 2002 $0.00 1.5 $0.002003 $3,370.25 0.5 $1,685.13 2003 $0.00 0.5 $0.00 2003 $57.91 0.5 $28.96

$519,114.08 32.4 $16,820,351.99 $28,720.00 35.7 $1,025,869.13 $323,398.74 32.3 $10,431,926.65



Annual Accrual $8,651.90 Annual Accrual $478.67 Annual Accrual $5,389.98Salvage Adjustment -30 $11,247.47 Salvage Adjustment -40 $670.13 Salvage Adjustment -40 $7,545.97

Theor Accruals $280,339.20 Theor Accruals $17,097.82 Theor Accruals $173,865.44Salvage Adjustment -30 $364,440.96 Salvage Adjustment -40 $23,936.95 Salvage Adjustment -40 $243,411.62

Acct 493.1 Wood Poles Acct 494.1 Primary Conductor - Overhead Acct 494.2 Secondary Conductor - Overhead

PROOF2000 $0.00 $0.00 2000 $0.00 $0.00 2000 $0.00 $0.002001 $0.00 $0.00 2001 $0.00 $0.00 2001 $0.00 $0.002002 $0.00 $0.00 2002 $0.00 $0.00 2002 $0.00 $0.002003 $56.17 $28.09 2003 $0.00 $0.00 2003 $0.97 $0.48

$8,651.90 $280,339.20 $478.67 $17,097.82 $5,389.98 $173,865.44

$8,651.90 $280,339.20 $478.67 $17,097.82 $5,389.98 $173,865.44

$0.00 $0.00 $0.00 $0.00 $0.00 $0.00

(Network Assets) EUB Decision 2006-002 (January 13, 2006)


Page 16 of 28

PROOF

Acct 494.6 Switches - Overhead Acct 495.1 Conduit UndergroundYear Surviving Plant Age Year Surviving Plant Age

2002 $0.00 1.5 $0.00 2002 $0.00 1.5 $0.002003 $0.00 0.5 $0.00 2003 $39,499.32 0.5 $19,749.66

-$18.22 5.5 -$100.21 $8,353,388.58 24.6 $205,306,371.34

ASL 60 ASL 60


Annual Accrual -$0.30 Annual Accrual $139,223.14Salvage Adjustment -40 -$0.43 Salvage Adjustment -20 $167,067.77

Theor Accruals -$1.67 Theor Accruals $3,421,772.86Salvage Adjustment -40 -$2.34 Salvage Adjustment -20 $4,106,127.43

Acct 494.6 Switches - Overhead Acct 495.1 Conduit Underground

2000 $0.00 $0.00 2000 $0.00 $0.002001 $0.00 $0.00 2001 $0.00 $0.002002 $0.00 $0.00 2002 $0.00 $0.002003 $0.00 $0.00 2003 $658.32 $329.16

-$0.30 -$1.67 $139,223.14 $3,421,772.86

-$0.30 -$1.67 $139,223.14 $3,421,772.86

$0.00 $0.00 $0.00 $0.00



Page 17 of 28

PROOF

Acct 495.2 Transformer Pads Acct 495.3 Pull BoxesYear Surviving Plant Age Year Surviving Plant Age

2002 $0.00 1.5 $0.00 2002 $3,675.24 1.5 $5,512.862003 $0.00 0.5 $0.00 2003 $2,146.15 0.5 $1,073.08

$37,563.70 17.6 $659,254.85 $52,590.42 4.4 $231,912.12

ASL 60 ASL 60


Annual Accrual $626.06 Annual Accrual $876.51Salvage Adjustment -20 $751.27 Salvage Adjustment -20 $1,051.81

Theor Accruals $10,987.58 Theor Accruals $3,865.20Salvage Adjustment -20 $13,185.10 Salvage Adjustment -20 $4,638.24

Acct 495.2 Transformer Pads Acct 495.3 Pull Boxes

2000 $0.00 $0.00 2000 $81.38 $284.822001 $0.00 $0.00 2001 $319.59 $798.992002 $0.00 $0.00 2002 $61.25 $91.882003 $0.00 $0.00 2003 $35.77 $17.88

$626.06 $10,987.58 $876.51 $3,865.20

$626.06 $10,987.58 $876.51 $3,865.20

$0.00 $0.00 $0.00 $0.00



Page 18 of 28

PROOF

Acct 495.4 Vaults Acct 495.5 ManholesYear Surviving Plant Age Year Surviving Plant Age

2002 $0.00 1.5 $0.00 2002 $0.00 1.5 $0.002003 $138,760.02 0.5 $69,380.01 2003 $37,859.03 0.5 $18,929.52

$20,183,465.70 24.1 $486,575,428.32 $15,745,171.70 38.4 $604,149,256.91

ASL 60 ASL 60




Acct 495.4 Vaults Acct 495.5 Manholes

2000 $1,929.50 $6,753.26 2000 $1,577.86 $5,522.502001 $0.00 $0.00 2001 $0.00 $0.002002 $0.00 $0.00 2002 $0.00 $0.002003 $2,312.67 $1,156.33 2003 $630.98 $315.49

$336,391.10 $8,109,590.47 $262,419.53 $10,069,154.28

$336,391.10 $8,109,590.47 $262,419.53 $10,069,154.28

$0.00 $0.00 $0.00 $0.00



Page 19 of 28

PROOF

Acct 496.1 Primary Cable Underground Acct 496.2 Secondary Cable UndergroundYear Surviving Plant Age Year Surviving Plant Age

2002 $746,033.99 1.5 $1,119,050.99 2002 $0.00 1.5 $0.002003 $2,994,025.47 0.5 $1,497,012.74 2003 $461,648.67 0.5 $230,824.34

$29,729,792.52 14.5 $430,024,420.33 $10,970,301.09 16.6 $182,283,236.40

ASL 30 ASL 40


Annual Accrual $990,993.08 Annual Accrual $274,257.53Salvage Adjustment -15 $1,139,642.05 Salvage Adjustment -50 $411,386.29


Acct 496.1 Primary Cable Underground Acct 496.2 Secondary Cable Underground

2000 $22,426.90 $78,494.15 2000 $0.00 $0.002001 $19,483.45 $48,708.63 2001 $5,094.31 $12,735.762002 $24,867.80 $37,301.70 2002 $0.00 $0.002003 $99,800.85 $49,900.42 2003 $11,541.22 $5,770.61

$990,993.08 $14,334,147.34 $274,257.53 $4,557,080.91

$990,993.08 $14,334,147.34 $274,257.53 $4,557,080.91

$0.00 $0.00 $0.00 $0.00



Page 20 of 28

PROOF

Acct 496.6 Switches - Underground Acct 497.1 Transformers - Overhead Acct 497.2 Network TransformersYear Surviving Plant Age Year Surviving Plant Age Year Surviving Plant Age

2002 $0.00 1.5 $0.00 2002 $0.00 1.5 $0.00 2002 $0.00 1.5 $0.002003 $66,771.86 0.5 $33,385.93 2003 $0.00 0.5 $0.00 2003 $500,821.43 0.5 $250,410.72

$1,071,978.79 9.6 $10,261,207.83 $200,661.58 32.3 $6,474,886.92 $32,197,626.07 23.6 $760,463,103.36



Annual Accrual $26,799.47 Annual Accrual $4,459.15 Annual Accrual $715,502.80Salvage Adjustment -50 $40,199.20 Salvage Adjustment -50 $6,688.72 Salvage Adjustment -50 $1,073,254.20

Theor Accruals $256,530.20 Theor Accruals $143,886.38 Theor Accruals $16,899,180.07Salvage Adjustment -50 $384,795.29 Salvage Adjustment -50 $215,829.56 Salvage Adjustment -50 $25,348,770.11

Acct 496.6 Switches - Underground Acct 497.1 Transformers - Overhead Acct 497.2 Network Transformers

2000 $0.00 $0.00 2000 $0.00 $0.00 2000 $6,194.40 $21,680.392001 $0.00 $0.00 2001 $0.00 $0.00 2001 $28,363.23 $70,908.092002 $0.00 $0.00 2002 $0.00 $0.00 2002 $0.00 $0.002003 $1,669.30 $834.65 2003 $0.00 $0.00 2003 $11,129.37 $5,564.68

$26,799.47 $256,530.20 $4,459.15 $143,886.38 $715,502.80 $16,899,180.07

$26,799.47 $256,530.20 $4,459.15 $143,886.38 $715,502.80 $16,899,180.07

$0.00 $0.00 $0.00 $0.00 $0.00 $0.00



Page 21 of 28

PROOF

Acct 497.3 Transformers - Padmount Acct 497.4 Transformers - PadmountYear Surviving Plant Age Year Surviving Plant Age

2002 $0.00 1.5 $0.00 2002 $0.00 1.5 $0.002003 $0.00 0.5 $0.00 2003 $0.00 0.5 $0.00

-$11,349.17 -84.6 $959,651.51 -$5,663.78 6.5 -$36,667.21

ASL 45 ASL 45


Annual Accrual -$252.20 Annual Accrual -$125.86Salvage Adjustment -50 -$378.31 Salvage Adjustment -50 -$188.79

Theor Accruals $21,325.59 Theor Accruals -$814.83Salvage Adjustment -50 $31,988.38 Salvage Adjustment -50 -$1,222.24

Acct 497.3 Transformers - Padmount Acct 497.4 Transformers - Padmount

2000 $155.46 $544.11 2000 $0.00 $0.002001 $0.00 $0.00 2001 $0.00 $0.002002 $0.00 $0.00 2002 $0.00 $0.002003 $0.00 $0.00 2003 $0.00 $0.00

-$252.20 $21,325.59 -$125.86 -$814.83

-$252.20 $21,325.59 -$125.86 -$814.83

$0.00 $0.00 $0.00 $0.00



Page 22 of 28

PROOF

Acct 497.6 Switchgear Acct 498.1 TelecontrolYear Surviving Plant Age Year Surviving Plant Age

2002 $0.00 1.5 $0.00 2002 $0.00 1.5 $0.002003 $0.00 0.5 $0.00 2003 $0.00 0.5 $0.00

$407,889.45 5.0 $2,053,362.88 -$1,250.73 4.5 -$5,628.29

ASL 45 ASL 45


Annual Accrual $9,064.21 Annual Accrual -$27.79Salvage Adjustment -50 $13,596.32 Salvage Adjustment 0 -$27.79

Theor Accruals $45,630.29 Theor Accruals -$125.07Salvage Adjustment -50 $68,445.43 Salvage Adjustment 0 -$125.07

Acct 497.6 Switchgear Acct 498.1 Telecontrol

2000 $2,042.57 $7,148.98 2000 $0.00 $0.002001 $0.00 $0.00 2001 $0.00 $0.002002 $0.00 $0.00 2002 $0.00 $0.002003 $0.00 $0.00 2003 $0.00 $0.00

$9,064.21 $45,630.29 -$27.79 -$125.07

$9,064.21 $45,630.29 -$27.79 -$125.07

$0.00 $0.00 $0.00 $0.00



Page 23 of 28

PROOF

Acct 498.2 SupervisoryYear Surviving Plant Age

2002 $0.00 1.5 $0.002003 $39,393.95 0.5 $19,696.98

$1,525,743.65 22.7 $34,585,892.35

ASL 45

Ave Rem Life 22.3

Annual Accrual $33,905.41Salvage Adjustment 0 $33,905.41

Theor Accruals $768,575.39Salvage Adjustment 0 $768,575.39

Acct 498.2 Supervisory

2000 $1,279.20 $4,477.192001 $0.00 $0.002002 $0.00 $0.002003 $875.42 $437.71

$33,905.41 $768,575.39

$33,905.41 $768,575.39

$0.00 $0.00



Page 24 of 28

Acct 473.1 Poles Acct 474.1 Primary Conductor Overhead

2002 $3,406,364.72 2.63 $89,587.39 0.0395 $134,551.00 2002 $864,208.20 2.84 $24,543.51 0.0426 $36,815.002003 $3,553,501.72 1.51 $53,657.88 0.0151 $53,658.00 2003 $1,114,431.07 1.63 $18,165.23 0.0163 $18,165.00

$60,925,143.65 1.86 $1,135,926.49 $16,776,331.00 $31,974,113.42 2.04 $652,290.12 $10,180,120.00

Net Salvage -35 -$397,574.27 Net Salvage -40 -$260,916.05

Total Accrual $1,533,500.76 Total Accrual $913,206.16

True-up -$191,458.00 True-up -$94,484.00

$60,925,143.65 2.20 $1,342,042.76 $31,974,113.42 2.56 $818,722.16

(Board ELG Correction) EUB Decision 2006-002 (January 13, 2006)


Page 25 of 28

Acct 474.2 O/H Secondary Conductor Acct 474.6 O/H Switches

2002 38,323.09 1.79 685.98 0.0269 1,031 2002 $213,456.05 2.16 $4,610.65 0.0324 $6,916.002003 62,290.60 0.91 $566.84 0.0091 567 2003 $199,764.08 1.18 $2,347.23 0.0118 $2,357.00

$5,553,764.48 1.59 $88,511.53 $2,284,794.00 $5,850,632.64 1.71 $99,940.37 $1,745,542.00


Total Accrual $132,767.30 Total Accrual $114,931.42

True-up -$31,428.00 True-up -$29,424.00

$5,553,764.48 1.82 $101,339.30 $5,850,632.64 1.46 $85,507.42



Page 26 of 28

Acct 476.1 U/G Primary Cable Acct 476.2 U/G Secondary Cable

2002 $1,043,989.63 2.57 $26,830.53 0.0386 $40,298.00 2002 $3,697,243.41 2.57 $95,019.16 0.0386 $142,714.002003 $13,586,302.15 1.31 $177,980.56 0.0131 $177,981.00 2003 $4,932,129.93 1.31 $64,610.90 0.0131 $64,611.00

$105,363,402.20 2.24 $2,360,756.64 $31,538,738.00 $34,824,024.03 2.26 $788,642.71 $8,169,706.00


Total Accrual $3,068,983.63 Total Accrual $1,182,964.07

True-up -$88,866.00 True-up $0.00

$105,363,402.20 2.83 $2,980,117.63 $34,824,024.03 3.40 $1,182,964.07



Page 27 of 28

Acct 476.6 U/G Switches Acct 477.1 O/H Transformers

2002 497,464.16 3.29 16,366.57 0.0494 24,575 2002 $643,755.18 2.11 $13,583.23 0.0317 $20,407.002003 909,192.89 1.68 $15,274.44 0.0168 15,274 2003 $1,499,543.40 1.08 $16,120.09 0.0108 $16,195.00

$11,801,755.21 2.89 $341,374.97 $4,536,099.00 -$3,147,156.78 2.49 -$78,520.29 -$716,873.00

Net Salvage -10 -$34,137.50 Net Salvage -40 $31,408.12

Total Accrual $375,512.47 Total Accrual -$109,928.40

True-up $0.00 True-up $17,658.00

$11,801,755.21 3.18 $375,512.47 -$3,147,156.78 2.93 -$92,270.40



Page 28 of 28

Acct 477.3 Padmount Transformers

2002 $2,718,047.87 2.11 $57,350.81 0.0317 $86,162.002003 $3,207,106.45 1.08 $34,476.39 0.0108 $34,637.00

$47,127,921.32 1.93 $908,147.86 $11,491,075.00

Net Salvage -40 -$363,259.15

Total Accrual $1,271,407.01

True-up -$85,829.00

$47,127,921.32 2.52 $1,185,578.01



Page 1 of 2

Per ENMAX

Cross Deemed Midyear CostLine Reference Structure Rate Base Rate Return

1 Long Term Debt Sched. 8.2.3 - L 32 61.0% 297.8 5.609% 16.7 2 Common Equity 39.0% 190.4 9.500% 18.1 3 Sched. 6.1 - L 12 100.0% 488.3 7.127% 34.8

CIG Argument Schedule - Recommendation #1Equity Funding Treated as No Cost Capital


4 2005 forecast mid-year rate base Sched. 6.1 - L 12 488.3 5 less 2004 equity funding D410G.EPG-4 (14.2) 6 less 2005 equity funding D410G.EPG-4 (19.0)

72005 mid-year rate base with equity funding treated as no cost capital

455.1

8 Long Term Debt Sched. 8.2.3 - L 32 61.0% 277.6 5.609% 15.6 9 Common Equity 39.0% 177.5 9.500% 16.9

10 Sched. 6.1 - L 12 100.0% 455.1 7.127% 32.4

Per BoardEquity Funding Treated as Construction Funds Collected From Customers (CFCFC)


11 2005 forecast mid-year rate base Sched. 6.1 - L 12 488.3 12 less mid-year 2004 CFCFC (D410G.EPG-4)/2 (7.1) 13 less mid-year 2005 CFCFC (D410G.EPG-4)/2 (9.5)

142005 mid-year rate base with equity funding treated as cust contributions

471.7


18 CIAC Rate 3.00%19 Mid-Year Cust Contributions 16.620 Reduction in Depreciation Expense 0.5

21 2005 Return reduction 1.222 2005 Depreciation Reduction 0.523 Total Revenue Req Reduction 1.7

ENMAX POWER CORPORATION

2005 Application - CIG Revised

($ Millions)REVISED RETURN ON RATE BASE

2005 Application


(2005 CFCFC) EUB Decision 2006-002 (January 13, 2006)


Page 2 of 2

Per ENMAX WITH BOARD DETERMINED COMMON EQUITY COST RATE


1 Long Term Debt Sched. 8.2.4 - L 29 61.0% 323.7 5.344% 17.3

2 Common Equity 39.0% 207.0 8.930% 18.5 3 Sched. 6.1 - L 12 100.0% 530.7 6.739% 35.8

CIG Argument Schedule - Recommendation #1Equity Funding Treated as No Cost Capital


4 2006 forecast mid-year rate base Sched. 6.1 - L 12 530.7

5 less 2004 equity funding D410G.EPG-4 (14.2)

6 less 2005 equity funding D410G.EPG-4 (19.0)

7 less 2006 equity funding estimated (19.0)

82006 mid-year rate base with equity funding treated as no cost capital

478.5

9 Long Term Debt Sched. 8.2.3 - L 32 61.0% 291.9 5.344% 15.6

10 Common Equity 39.0% 186.6 8.930% 16.7 11 Sched. 6.1 - L 12 100.0% 478.5 6.743% 32.3

Per BoardEquity Funding Treated as Construction Funds Collected From Customers (CFCFC)


12 2006 forecast mid-year rate base Sched. 6.1 - L 12 530.7 13 less 2004 CFCFC D410G.EPG-4 (14.2) 14 less 2005 CFCFC D410G.EPG-4 (19.0)

152006 mid-year rate base with equity funding treated as CFCFC

497.5


19 CIAC Rate 3.00%20 Mid-Year Cust Contributions 33.221 Reduction in Depreciation Expense 1.0

22 2006 Return reduction 2.223 2006 Depreciation Reduction 1.024 Total Revenue Req Reduction 3.2

ENMAX POWER CORPORATION

2006 Application - Board Revised

($ Millions)REVISED RETURN ON RATE BASE

2006 Application


(2006 CFCFC) EUB Decision 2006-002 (January 13, 2006)

ENMAX Power Corporation - auc.ab.ca · Decision 2006-002: ENMAX Power Corporation 2005 – 2006...

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