EPCOR Distribution Inc.

Transcription

1 Alberta Energy and Utilities Board Decision Distribution Tariff Application August 13, 2004

2 ALBERTA ENERGY AND UTILITIES BOARD Decision : 2004 Distribution Tariff Application Application No Published by Alberta Energy and Utilities Board Avenue SW Calgary, Alberta T2P 3G4 Telephone: (403) Fax: (403) Web site:

3 Contents 1 INTRODUCTION LOAD FORECAST OPERATING EXPENSES Inflation Related Increases to Operating Expenses Non-Inflation Related Increases in Operating Costs Overall Operating Costs Distribution Operations Customer Services Site, Metering, Settlement and Tariff Services Support Services Bad Debt Employee Numbers and Compensation FTEs At Risk Compensation Pension Funding Vacant Position Allowance Executive Compensation Hearing Costs Donations and Community Support Corporate Affiliate Transactions Other Affiliate Transactions Affiliate Code of Conduct Benchmarking and Uniform System of Accounts REVENUE OFFSETS Water Meter Reading Services provided to EWSI Service Connections, Jobbing, Material Sales DEFERRAL ACCOUNTS Transmission Access Charge Deferral Account AESO Charge Deferral Account Hearing Cost Reserve Account Self-Insurance Reserve Account RATE BASE Opening Balances Capitalization Policy Capital Additions General Regulated Default Supply Compliance Project Meter Data Management Remote Project Vehicles Other Data Processing Equipment Customer Contributions Working Capital EUB Decision (August 13, 2004) i

4 7 DEPRECIATION General Complexity of Method Regulatory Treatment of Net Salvage Deprecation Expense Other RETURN ON RATE BASE General Cost of Equity and Equity Ratio Cost of Debt and Debt Ratio DISTRIBUTION ACCESS SERVICE TARIFF DAS Cost of Service General Use of On-Peak Energy to Allocate Primary Distribution Costs DAS Rate Design General Revenue to Cost Ratios Complexity of Method Customer-Specific Rates Lifeline Rates Fee Schedule Terms and Conditions SYSTEM ACCESS SERVICE TARIFF SAS Cost of Service SAS Rate Design Complexity of Method FRANCHISE FEE Board Jurisdiction Bill Presentation Level of Method of Collection of the Fee REFILING PROCESS SUMMARY OF BOARD DIRECTIONS RESPECTING THE REFILING SUMMARY OF BOARD DIRECTIONS REPECTING THE NEXT GTA APPENDIX 1 HEARING PARTICIPANTS APPENDIX 2 EXAMPLE OF A BASIC FORM OF SIMPLIFIED DEPRECIATION METHOD APPENDIX 3 BOARD PRIMARY SYSTEM ALLOCATION ANALYSIS ii EUB Decision (August 13, 2004)

5 List of Tables Table 1. EDI 2004 Commercial Sales Forecast... 5 Table 2. EDI 2004 Forecast Cost Escalation % from Table 3 of EDI s GTA... 9 Table 3. EDI and CG Recommended Forecast Inflation % for Table 4. EDI Per Customer O&M Expenses Table 5. EDI Support Services Costs Table 6. EDI Accounts with Major Support Services Cost Increases Table 7. EDI Bad Debts Related to Revenue Offsets Table 8. EUI Allocation to EDI Table 9. EDI Allocation of IT Expense Table 10. CG Recommended IT O&M Allocation Table 11. Benchmarking of EDI and EPC Table 12. Revenues Received from Edmonton Water Services Inc Table 13. EDI Comparison of Capital Asset Review and Asset Tracking System Table 14. Comparison of EDI and ECP Overhead Capitalized Table 15. EDI Investment in Information Software Account Table 16. CG Recommended EDI Debt Rates Table 17. Minimum System Calculation Table 18. EDI Stratified Customer Consumption Table 19. Extraneous Price Signals in Proposed EDI per UA Table 20. General Structural Concerns with Proposed EDI Tariff per UA Table 21. Concerns with Proposed EDI DAS Tariff per UA Table 22. Concerns with Proposed EDI SAS Tariff per UA EUB Decision (August 13, 2004) iii

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7 ALBERTA ENERGY AND UTILITIES BOARD Calgary Alberta EPCOR DISTRIBUTION INC. Decision DISTRIBUTION TARIFF APPLICATION Application No PART B: 2004 FINAL DISTRIBUTION TARIFF File No INTRODUCTION With the passage of the new Electric Utilities Act, SA 2003, c.e-5.1 (EUA), which came into force on June 1, 2003, the municipal electric distribution systems of the Cities of Edmonton and Calgary became subject to the jurisdiction of the Alberta Energy and Utilities Board (Board). In particular, the Board became the regulatory authority for (EDI) and ENMAX Power Corporation (EPC) for the purposes of approving distribution tariffs (DT) to be effective January 1, The Distribution Tariff Regulation, AR 163/2003 (DT Regulation), required EDI and EPC to apply to the Board for approval of their DTs on or before October 1, The DT Regulation required the Board either to approve a final DT for EDI and EPC to take effect on January 1, 2004, or to approve an interim DT no later than November 30, 2003 to take effect on January 1, As required by the DT Regulation, EDI filed an application on October 1, 2003, seeking interim and final approval of its 2004 DT (2004 DT Application). The Board issued interim Decision on November 14, 2003 approving an interim DT to take affect January 1, In order to approve a final 2004 DT, the Board conducted an oral hearing in Edmonton over the period March 1, 2004 to March 10, 2004, with written argument received April 26, 2004 and written reply received on May 17, The Board considers the record of these proceedings to have closed on May 17, Parties participating in the proceedings are shown in Appendix 1 to this Decision. 2 LOAD FORECAST EDI s 2004 load forecast was based on Dr. Stokes Billing Determinant Outlook report included as Appendix D to EDI s Application (Exhibit ). Additional information was provided in a number of responses to information requests, 3 by EDI s load forecast and inflation factors panel (Tr. pp ), and in responses to undertakings provided by the witnesses (Exhibits , 51, 52) EUA, section 102 DT Regulation, section 4(1). BR-EDI-12, AE-EDI-14, 15, 16, 17, 19, 21, and PICA-EDI-69 EUB Decision (August 13, 2004) 1

8 Views of the Applicant EDI submitted that PICA suggested that the growth rate Dr. Stokes used for average consumption per household for 2003 was understated as it was lower than the five-year trend. 4 In response, Dr. Stokes confirmed that his Billing Determinant Outlook was prepared based on the latest data available at the time his study was done, which included seven months of actual consumption data for Dr. Stokes also explained that he had used a longer rather than shorter span of historical data based on his concerns over the accuracy of more recent consumption data due to the effects of deregulation on the data collection process (Tr. pp ). Dr. Stokes also emphasized that in assessing the reasonableness of consumption data, the effects of cycles must be considered (Tr. pp ). EDI also noted that questions were asked respecting Dr. Stokes report in relation to energy consumption by industrial and commercial customers (commencing at Tr. p. 1796). EDI submitted that witnesses confirmed that Dr. Stokes assumptions were, if anything, conservatively biased in favour of customers. Mr. Cowburn also confirmed that because customers above 5 MW have a consumptionindependent rate, the assumed energy growth for commercial and industrial customers in EDI s load forecast will not affect their tariff charges, nor EDI s revenue (Tr. pp ). EDI submitted that the record demonstrates that EDI s load forecast is based on an economic outlook and other inputs and assumptions for the EDI service area that are reasonable and appropriate, and that ensure that the forecast provides a fair and reasonable estimate of EDI s 2004 load for ratemaking purposes. EDI noted that the CG took issue with two narrow aspects of EDI s load forecast, asserting that EDI s growth rates for residential and commercial customers appear to be understated (CG Argument, pp. 1-4). EDI provided the following additional comments in reply to the CG s assertions. The evidence demonstrates that there is no reasonable basis for the CG s recommendations. For example, the CG s recommendation that an average of the 5 and 10-year growth rates shown in PICA-EDI-69 be applied to EDI (CG Argument, p. 1, ll ) is entirely unsupported by, and is in fact completely inconsistent with, the record. Among other things, the EUB data in PICA- EDI-69 is for the whole Province of Alberta and not just for the City of Edmonton. As such, appropriate adjustments must be made to this data to reflect the growth applicable to the City of Edmonton alone, as Dr. Stokes did in providing his evidence. The CG s recommendation also fails to take into account the hazards pointed out by Dr. Stokes with respect to the data (Tr. pp ): A. DR. STOKES: Well, I m not -- it s not safe, for example, using these numbers on a year-to-year basis, because of their construction. One thing the deregulation has done for us is it s destabilized the data collection process. In fact, some of the data that s published by the Board, we had to splice it and fix it up 4 Tr. p EUB Decision (August 13, 2004)

9 because it didn t match once deregulation went into effect. If you check the AEUB data, you ll notice. So we were awfully nervous about putting a lot of weight on it. So that s why I used a longer In recent times it s very dangerous to use this data because of all the changes. The EUB has stopped publishing data the way they used to publish it. There have been switches in the way the data has been reported. If you look at the commercial, industrial numbers, there s huge breaks in that data. So you get very nervous about using data that you don t have a lot of confidence in. EDI noted that the CG used a trend-based approach to test why consumption data in 2003 and 2004 should be different than the trend from 1998 to EDI submitted that the evidence demonstrates that this approach is clearly inappropriate. As EDI s expert witness Dr. Stokes pointed out, the effect of cycles must be considered (Tr. pp ). Yet in its Final Argument, CG mischaracterizes the record in stating that it was EDI that stated it had regard to the trend more than the economic cycle (CG Argument, p. 2, l. 18). This is clearly inconsistent with EDI s evidence, as summarized in EDI s Final Argument. EDI submitted that the CG s recommendation was based on faulty conclusions and invalid assumptions and is unsupported by evidence. The Board should disregard the CG s submissions and approve EDI s load forecast as filed. Views of the Interveners CG Residential The CG noted that EDI has used a growth rate of 0.1% for the Residential class, notwithstanding the fact that the average growth rate for the last 13 years is about %. 5 The CG noted that the more recent 5-year average, growth rate averaged 0.61% and that even taking a longer 10-year average term, a growth rate of 0.35% was indicated. The CG submitted that EDI s rationale for the lower growth rate was as follows: In the forecasts presented below a rate of 0.1 per cent was used for residential energy and per cent for commercial and industrial energy. A smaller positive number for residential than the average of the past 12 years is employed as increases in prices and energy conservation are likely to begin to offset the positive effects of income growth in the future. 6 The CG submitted that EDI s 0.1% growth in Residential energy, for 2004, appeared understated. Not only is it contrary to EDI s own evidence provided in PICA-EDI-69, but it is also based on an assumption that the growth rate in 2003 is about 0.1% for the months of Aug to Dec When the actual growth rates for the first 7 months of 2002 were much higher PICA-EDI-69, Attachment App D, p. 4 Exhibit 50, Appendix p. 6 of 9 EUB Decision (August 13, 2004) 3

10 The CG submitted that EDI s forecast of 0.1% was based in large part on a subjective assessment respecting the impact of prices and energy conservation mitigating the positive impacts of income growth in the future. EDI stated 8 it had regard to the trend more than the economic cycle (which was not defined), where people simply consume more energy when they are doing financially well. The CG submitted that, even using the trend as suggested, EDI s own evidence 9 suggested that the growth rate for the period (13 years) averaged %. EDI made a number of unsupported claims to support using its lower residential growth rate to 0.1%. For example, there was no evidence on the record to support the claim that the federal government, through its Kyoto arrangement, is promoting energy efficiency. 10 Even if EDI s concern was merited, the CG questioned why the initiative would only have the stated impact in 2004, and not in any of the earlier years. Based on the foregoing, the CG submitted that an average of the 5 and 10-year growth percentages should be used for determining the 2004 forecast percent growth rate. Based on PICA-EDI-69, the 5 year rate is 0.614% and the 10-year rate is 0.34%, so that the average rate is 0.47%. In reply CG submitted EDI only examined changes in trend, which suggested that conservation and impacts of higher prices in 2004 offset the impact of income and growth. The CG submitted that EDI s evidence on the impact of Kyoto and higher energy prices was nebulous at best. The CG submitted that, an examination of the growth in the previous 5 and 10-year periods, is a much more stable indicator of what residential sales may be in These longer periods also have the benefit of incorporating trends as well as all other factors. The CG submitted that EDI s distinction between trend and cycle was arbitrary and confused the issue. The more reliable and logical evidence was that the longer term periods, either the 5 or 10-year periods, indicate a growth rate significantly higher than that used by EDI. EDI s own evidence indicated that, based on the period , the average Residential growth was 0.18%, almost two times that forecast by EDI. Notwithstanding energy efficiency programs that have been in place over the last several years, the clear indication from Response PICA-EDI-69 is that the most recent 5 and 10-year periods suggest a positive net growth of an average of 0.47%, as referenced in the CG Argument (p. 5). The CG submitted that these longer-term periods incorporate both the impacts of both trend and cycle, and should be used by the Board in the derivation of the energy sales for the residential customers in EDI has not presented any persuasive evidence that increases in prices and energy conservation will offset or mitigate the historical experienced growth. Commercial The CG noted that EDI forecast commercial sales having regard to growth in commercial/industrial real GDP in Alberta. The CG submitted that EDI s evidence was the analysis of data from 1990 to 2002 which EDI used to argue there is a decline in the energy consumption per unit of industrial/commercial real GDP: Tr. p PICA-EDI-69, Attachment Tr. p EUB Decision (August 13, 2004)

11 The average growth rates in energy per household and energy per real GDP in the commercial and industrial sectors were computed for the period 1990 to The average rate for households was 0.2 per cent per year, while that for commercial and industrial was -0.7 per cent per year. 11 The CG noted that In PICA-EDI-69 Attachment, EDI provided the data used to arrive at the above conclusion and that EDI decided to use a smaller negative value of 0.25% for commercial/industrial energy since some of the decline may reflect the trend away from energyintensive manufacturing in the City towards less energy-intensive sectors and not be representative of pure efficiency effects. The following Table compares growth in normalized sales for EDI s commercial customers (excluding customer specific) with growth in real GDP: Table 1. EDI 2004 Commercial Sales Forecast to 4999 KVA TOU Primary 600, , , , to 4999 KVA (TOU) 1,670,644 1,687,827 1,733,824 1,777, to 149 KVA 510, ,209 53, ,831 <50KVA 688, , , ,528 3,470,210 3,508,555 3,555,965 3,636,221 Growth in Commercial Sales 1.1% 1.4% 2.3% Alberta Real GDP Growth (App. D Table 1) 2.3% 1.7% 3.0% 3.8% The CG indicated that based on EDI s evidence respecting the relationship between GDP and energy sales, a GDP growth rate of 3% would mean a sales growth rate of about 2.75 (3%-.25%). However, the CG noted that EDI s forecast sales growth rate for 2003 was significantly lower at 1.4%. Similarly the CG noted that the sales growth rate for 2004 was only 2.3% whereas the CG submitted that the GDP growth rate would indicate a sales growth rate of about 3.55% (3.8%-.25%) based on EDI s evidence. The CG s took the position that the growth rates in commercial sales were understated and should be revised upwards for 2003 and 2004 to reflect growth rates that are consistent with GDP growth rates forecast by EDI. The CG recommended commercial energy sales growth rates of 2.75% in 2003 and 3.55% in In reply CG noted that EDI stated that its industrial and commercial sales forecast was conservatively biased in favour of customers: Questions were also asked respecting Dr. Stokes report in relation to energy consumption by industrial and commercial customers (commencing at T7:1796). In response, the witnesses confirmed that Dr. Stokes assumptions were, if anything, conservatively biased in favour of customers. (EDI Argument, p. 7) The CG disagreed with EDI s assessment. The CG submitted that, the forecast increase in commercial/industrial sales for 2003 and 2004 was not consistent with EDI s stated assumptions as to the relationship between GDP growth and commercial/industrial sales. 11 Appendix D, p. 4 EUB Decision (August 13, 2004) 5

12 The CG submitted that the growth rates in commercial sales should be revised upwards for 2003 and 2004 to reflect growth rates that are consistent with GDP growth rates forecast by EDI. CG recommended energy sales growth rates of 2.75% in 2003 and 3.55% in Views of the Board The Board notes that the following issues were raised respecting EDI s 2004 load forecast: The forecast energy use per customer for the residential rate class The forecast growth rate in load for the commercial rate class With respect to the 2004 forecast energy use per customer for the residential class, EDI forecast an increase of 0.10% based upon an historical ( ) average increase of 0.17% reduced to 0.10% as increases in price and energy conservation are likely to begin to offset the positive effects of income growth in the future. The CG considered the increase should be 0.47% based upon an average of the experienced 5 and 10-year growth rates. The Board has reviewed the method used by EDI to determine the forecast energy use per residential customer and considers the approach to be reasonable for the purposes of this Decision. The Board recognizes that EDI s adjustment for price and energy conservation is an exercise in judgment into which many factors enter. The Board will accept EDI s forecast based on that judgmental adjustment for the purposes of this Decision. However, the Board directs EDI to monitor energy use per residential customer and report on its forecast track record in this regard at the time of EDI s next GTA. With respect to the forecast growth in energy sales for the commercial class, EDI has forecast a 2.30% increase whereas the CG considered the increase should be 3.55% in 2004 to be more consistent with a forecast GDP growth rate of 3.80%. The Board notes that EDI reduced the actual historical decrease of 0.74% in the energy use per commercial customer to 0.25%. In other words, if the historical data had been used, EDI would have forecast a commercial load increase lower than its 2.30% increase forecast. The Board considers that the overall increase of 2.30% strikes a reasonable balance between the forecast GDP increase of 3.80% and the higher indicated conservation decrease of 0.74%. Accordingly the Board approves a 0.1% increase in the residential average energy use and the 2.30% increase in forecast sales to commercial customers for the purposes of the EDI 2004 load forecast. Further the Board has reviewed and approves the remaining aspects of the 2004 EDI load forecast as set out in Appendix D Billing Determinants Outlook. 3 OPERATING EXPENSES EDI indicated that its GTA cost forecast was based on EDI s budget for EDI s witnesses confirmed that there were no differences between EDI s 2004 cost forecast and its budget (Tr. p. 1721). 6 EUB Decision (August 13, 2004)

13 In response to questions from the Board and various counsel, EDI s witnesses provided a detailed explanation of the Corporation s 2004 budgeting process (see EDI s response to UCA- EDI-7 and Tr. pp , , and Tr. pp , , , , , ). In Argument EDI summarized the process generally followed by EDI for each budget year as follows: In developing its budget, EDI used a combination of a bottom up approach and a cost trend approach to forecasting expenditures based on expected work activity and cost levels during the forecast period. The budget process for 2004 was initiated in March An initial meeting among the EDI management team was held to commence the process. Discussion among the management team included potential areas where forecast costs had the potential to change significantly in Personnel involved in the budgeting process went into that process with the understanding that they were expected to do their best to avoid cost increases and, in fact, to find better ways of doing things to reduce costs, and to build in cost savings and productivity improvements from the outset of the budgeting process. For 2004 budgeting purposes, 2002 actual costs and 2003 reforecast costs (based on seven months of actuals and five months of forecast numbers) were relied on as providing a basis for the budgeting process and for determining cost trends. Known changes and any new information that could affect EDI s costs during 2004 compared to 2002 actuals and 2003 reforecast were considered and, where necessary, were reflected in the 2004 budget. Responsibility centre foremen, managers and supervisors provided the initial input for the budget, and they were involved throughout the budgeting process. That input went to department managers who reviewed it and prepared a detailed budget for their respective area(s) of responsibility. Directors reviewed their respective managers budgets. EDI Finance, including the Controller, reviewed all components of the budget. The budget was first prepared in 2003 dollars on a detailed basis at the activity, general ledger or account level. This level of detail ensured that EDI Finance was able to apply the appropriate inflation factor to each budgeted amount (i.e., at the account level) to arrive at the 2004 budget. Where a specific cost for 2004 was known, the actual cost was used, rather than a forecast amount with the application of an inflation factor. The budget was also reviewed by the President of EDI a number of times through the process and was revised on an iterative basis. Once approved by the President of EDI, the budget was presented to the Finance and Review Council of EPCOR Utilities Inc. (EUI) for review and approval, after which it was presented to the EUI Board of Directors for review and approval. The budget was approved by EUI s Board of Directors on November 27, Neither Edmonton City Council nor City of Edmonton staff had any input into EDI s budgeting process. EUB Decision (August 13, 2004) 7

14 When asked how he, as the President of EDI, assessed whether proposed cost increases in the 2004 budget over previous years were fair and reasonable, Mr. Rowes testified as follows: (Tr. pp ) A. Mr. Rowes: I assess that by going through the various categories with them [i.e., EDI s managers]. For example, distribution operations why did that change? Why did the customer services line change and look for reasonable explanations. Certainly, I would be concerned with any cost increases whatsoever. Q. Were you concerned with that 24 percent increase? A. Mr. Rowes: I was when I first saw it, but I believe that the explanations that I received were reasonable and what was required to run the business. Views of the Applicant EDI noted that it provided extensive and detailed evidence respecting the manner in which its operations and maintenance costs were derived. EDI submitted that the record demonstrates that EDI s cost forecast process for 2004 was logical and appropriate and, further, that it was sufficiently rigorous and contained checks and balances to ensure that the various components of the cost forecast were reasonable. EDI submitted that the evidence also shows that EDI s 2004 forecast costs are just and reasonable and are prudently required to enable EDI to provide service to retailers and end-use customers and satisfy the criteria set out in section 122(1) of the EUA for Board approval. EDI submitted that a comparison of forecast costs with previous years actuals, together with the detailed explanations provided by EDI in areas where its costs are forecast to increase, confirmed that EDI is prudently managing its costs in EDI also submitted that its operating record demonstrates conclusively that EDI is working hard to ensure that system reliability is maintained at the highest level while working in a safe and environmentally sound manner. Views of the Board The Board notes that EDI indicated that its GTA forecasts reflected its budget forecasts. The Board agrees that EDI s overall method for forecasting costs by using budget forecasts is logical and appropriate. The Board will deal with specific concerns in EDI s operating and maintenance expense forecasts in the sections that follow. 3.1 Inflation Related Increases to Operating Expenses EDI indicated that it had retained Dr. Ryan, a Professor in the University of Alberta s Economics Department, who is a highly qualified expert in the area of inflation forecasts and escalators. Dr. Ryan s Report detailing the derivation of the inflation factors used in EDI s budget and cost forecast was included as Appendix C to EDI s DTA. Further detail demonstrating the reasonableness of the inflation factors was provided in EDI s responses to STM-EDI-3 and UCA-EDI-14. EDI noted that Dr. Ryan was not challenged in cross-examination, and no evidence was filed taking issue with his analysis or conclusions. 8 EUB Decision (August 13, 2004)

15 Table 3 on Page 8 of the GTA shown below shows the EDI s inflation forecast for the three categories of general inflation forecasts: Table 2. EDI 2004 Forecast Cost Escalation % from Table 3 of EDI s GTA Category 2004 Salaries and wages 3.4 Materials and contractors 1.4 Other (Note) 2.0 Note: The other category includes those costs not included in the salaries and wages and materials and contractors categories. The Conference Board of Canada forecast of the Consumer Price Index for Alberta was utilized for this category. Views of the Applicant EDI submitted that the record demonstrates that the inflation factors developed by Dr. Ryan and used to derive EDI s 2004 cost forecast are reasonable. EDI submitted that it is incumbent on the Board to assess each cost area having regard for, among other things, the detailed information that EDI has provided in respect of each forecast increase. EDI submitted that its evidence demonstrates that all increases in 2004 forecast costs are justified, and confirms the reasonableness of its 2004 operating cost levels. In Reply EDI noted that despite the facts that no party filed evidence taking issue with EDI s inflation factors or with Dr. Ryan s report and that Dr. Ryan was not asked a single question in cross examination, the CG Argument makes a number of claims with respect to Dr. Ryan s report. EDI submitted that the claims were unsubstantiated and that the CG attempted to lead new evidence in Argument. In regard to CG s positions EDI submitted the following: Forecast inflation rate for wages and salaries EDI submitted that there was no reasonable basis for the CG s argument that the 3.4% inflation factor used for wages and salaries was too high. First, the 3.4% value is from Table 3 of Dr. Ryan s report (EDI Application, Appendix C, p. 5). This figure was based on Conference Board forecasts for 2004 dated July 16, EDI submitted that as EDI is located in Alberta the CG s suggestion, to choose the average of all wage settlements in Canada as the lower bound that applies to EDI, was inappropriate. EDI s remuneration must be competitive with comparable Alberta employers if EDI is to retain its existing workforce and attract new employees. Thus, if ATCO Gas and AE employees received a 3.3% to 3.4% increase, a similar rate of increase would be expected for EDI employees. EDI submitted that the fact that AE and ATCO Gas were investor owned utilities rather than a municipally owned utility has absolutely no effect on the salaries that these utilities must offer. It is ludicrous to expect that a potential employee would accept a lower wage just because the employer is municipally owned rather than investor owned. The CG argument ignored the fact that employees are mobile, especially within provincial boundaries where tax regimes are the same. EUB Decision (August 13, 2004) 9

16 EDI submitted that the CG failed to provide any reasonable basis for its recommended reduction. Instead, the evidence demonstrates that the 3.4% forecast is based on sound logic and is entirely reasonable, and should be approved by the Board. In reply EDI noted that while the CG asserted that EDI had not met its burden of proof of demonstrating that the base plus at-risk components of management salaries are at the median of salaries in the market, none of the interveners proffered any evidence challenging EDI s position. Further, in response to STM-EDI-4, EDI stated that it relied on Towers Perrin market salary surveys and Watson Wyatt Canadian Salary surveys in setting its total target compensation levels for management employees, both of which are proprietary in nature and could not be filed in evidence. EDI submitted that the interveners were not able to proffer any evidence, or to put any document before the witnesses, to suggest that EDI s forecast target total compensation for its management employees was at anything other than median in the market. Forecast inflation rate for materials and contractors EDI noted that the CG accepted EDI s approach and methodology in forecasting the inflation rate for materials and contractors but recommended that the inflation factor should be reduced to reflect a 1% growth in CPI rather than the Conference Board s forecast of 2.0% for growth in CPI. EDI submitted that it was inappropriate on the CG s part to attempt to lead what is essentially new and untested evidence by way of Final Argument under the guise that it is well known and available on a website, and to then argue that EDI s costs should be reduced as a result. EDI has been given no opportunity to test or respond to that evidence with facts and analysis of its own. In addition, EDI submitted that CG s approach flies in the face of the Board s fixed forward test year approach to tariff regulation since EDI s inflation factor forecast, like all other aspects of its cost forecast, was made at the time of its Application based on the best and most current information available. Actuals often prove to differ from forecast, but it is entirely inappropriate for an intervener to cherry pick certain aspects of a forecast and argue that it should be reduced based on an actual that becomes known after the initial forecast was made (and months after the evidentiary portion of the hearing has concluded). EDI submitted that the evidence which was properly on the record of this proceeding (and which continues to be unchallenged in any proper way by the CG or any other party) demonstrated that its forecast inflation rate for materials and contractors is entirely reasonable and should be approved by the Board. The Board should reject the CG s attempt to lead new evidence at this point in the proceeding and disregard its argument completely. Forecast inflation rate for Other EDI submitted that, for the same reasons the CG s requested reduction to EDI s forecast inflation rate to 1.0% for Other should also be denied, and the Board should approve EDI s applied-for rate of 2.0%. 10 EUB Decision (August 13, 2004)

17 Views of the Interveners CG The CG submitted that EDI s inflation forecasts for 2004 are too high and not adequately supported by the evidence for the reasons set out below: Forecast inflation rate for wages and salaries The CG submitted that Part 3 of Appendix C (Dr. Ryan s report) provided several benchmarks against which to compare EDI s inflation forecast of 3.4% for wages and salaries. Of these benchmarks the only one that exceeded 3.4% was the average wage increase in Newfoundland and Labrador for The remaining benchmarks range from 0% for B.C. Hydro s office and technical workers to 3.4% for AE s linemen. 12 The CG submitted that EDI s 3.4% forecast was at the upper end of a range of forecasts that could reasonably be used in EDI s circumstances. A reasonable lower end might be 2.01%, which is the overall average shown in Table 5 of Appendix C. The CG proposes that the midpoint of this range, 2.7%, should be adopted for the purposes of EDI s refiling. The CG submitted that another test of the reasonableness of the proposed 2.7% figure is EDI s forecast of inflation for materials and contractors (1.4%) and for other (2.0%). By comparison, the CG proposal appears more than reasonable. It is also worth noting that EDI s union employees received increases of 4% in each of 2002 and 2003 (S105-EDI-8). As might be the case with some of the benchmarks provided in Table 5, the CG submitted that there was no need for a large increase to make up for inadequate increases in prior years. Further, the CG noted that 3.4% requested by EDI was not supported by any of its actual data arising from negotiated settlements with bargaining unit employees. EDI and other EPCOR employee groups are still in negotiations. The CG also noted that, while EDI placed reliance on settlements involving investor owned utilities, viz. AE and ATCO Gas at 3.4% and 3.3% respectively (also presumably supported by the Conference Board, EDI is a municipally owned utility. The CG submitted that other sources referred to in Table 5 show settlements made with crown corporations, i.e. B.C. Hydro, Hydro Quebec, Toronto Hydro, etc. The CG submitted that, since the average increases demonstrated for these organizations was in the 2% range, 2.7% is generous and 3.4% is much too high. The CG also submitted that, while EDI may believe its At Risk compensation allows its management employees to achieve compensation that is comparable to other companies, neither EDI nor EUI provided further documentation in the form of a market survey or independent special study to substantiate this claim. The CG also submitted that EDI did not provide any reason to support the 3.4% forecast for inflation of wages and salaries, other than the fact that the forecast was originally provided by the Conference Board. To the contrary, the CG noted that Dr. Ryan provided information showing this forecast is equal to the second-highest of the 17 wage settlements in the Canadian utility industry (% increase for 2004) shown in Table 6 of Appendix C of EDI s Application (Dr. Ryan s report). 12 Application, Table 4 of Appendix C EUB Decision (August 13, 2004) 11

18 In reply, the CG submitted that EDI did not provide any reason to support the 3.4% forecast for inflation of wages and salaries, other than the fact that the forecast was originally provided by the Conference Board. To the contrary, the CG noted that Dr. Ryan provided information showing this forecast is equal to the second-highest of the 17 wage settlements in the Canadian utility industry (% increase for 2004) shown in Table 6 of Appendix C of EDI s Application (Dr. Ryan s report). Forecast inflation rate for materials and contractors The CG noted in Appendix C of the Application and in response to STM-EDI-3, EDI provided an explanation of how the forecast inflation rate for materials and contractors was derived. In the end, this forecast is determined by the Conference Board s forecast of the Consumer Price Index and Dr. Ryan s calculations relating the CPI to the Industry Price Index for Industrial Electrical Equipment (IPIIEE). The basis for this determination is that the IPIIEE correlates strongly with the CPI. The CG accepted EDI s approach and methodology in forecasting the inflation rate for materials and contractors. The CG then went on to provide new evidence on the level of CPI that the Board has rejected as being inappropriately provided in Argument. In reply CG submitted that EDI s argument implied that EDI relied solely on Dr. Ryan to develop the inflation forecasts. Whereas, in UCA-EDI-14(e), EDI acknowledged that Dr. Ryan was engaged to provide the historical index, and it was up to EDI to approve and use the index provided. This response was provided in the context of an information request dealing with the Industry Price Index for Industrial Electrical Equipment. The CG indicated that, while it accepted Dr. Ryan s qualifications and his method of using the predicted CPI for forecasting the escalation of costs for materials and contractors, the CG took issue with the level of EDI s inflation forecast. Views of the Board The Board notes that the CG raised concerns regarding the general inflation levels used as well as certain specific expenses as set out in other sections of this Decision. The following table sets out the proposals of EDI and the CG respecting recommended forecast inflation levels for Table 3. EDI and CG Recommended Forecast Inflation % for 2004 EDI CG Category Salaries and wages Materials and contractors Other (Note) Note: The other category includes those costs not included in the salaries and wages and materials and contractors categories. In regard to the general inflation factors, the Board has separated its findings into the three categories used by EDI as follows: Salaries and Wages 12 EUB Decision (August 13, 2004)

19 Materials and Contractors Other The Board also notes that in other sections of this Decision the value of benchmarking is discussed. For comparability purposes, the Board directs EDI in the next GTA, to file its general inflation factors by the following categories: salaries and wages, materials, contractors and other. Forecast inflation rate for salaries and wages The Board notes that EDI has forecast a composite (i.e. management and union) 3.4% increase to salaries and wages based on the Conference Board of Canada forecast as of July 16, 2003 for Alberta across various industries, while the CG suggested the forecast should be reduced to 2.7% to be more consistent with the average of other Canadian utility wage settlements. The Board recognizes that a composite forecast increase in the inflation rate for salaries depends upon the relative proportion of union and management salaries and differences between the Edmonton labour markets and other labour markets in Alberta. The Board notes that the levels of compensation for the CUPE and IBEW members are negotiated between EDI management and the respective unions. Because these are arm s length negotiations, the Board considers the compensation package for these employees to be market based for the purposes of this Application before the application of the 3.4% increase. The Board is satisfied that the Alberta wage increases (actual % for ATCO settlement levels and the 3.4% Conference Board of Canada forecast) provide better forecast indicators than a forecast of Canadian wage increases. The Board does not consider that there is any evidence supporting the CG s speculation that government-owned utility settlements should carry more weight than privately-owned utility settlements, as both types of utilities compete for labour in the same market. On balance, the Board accepts that EDI s forecast 2004 inflationary increase of 3.4% for all salaries and wages is reasonable. To provide better support for future compensation increase forecasts, the Board directs EDI, in its next GTA, to provide an independent testable market-based assessment of the reasonableness of its compensation levels for its management, professional, CUPE, and IBEW employees. The assessment should consider each of the Exempt levels (i.e. Executive, Director, Manager, Supervisor, Non-Management, Corporate Allocated) as well as the two types of Non-Exempt (i.e. CUPE, IBEW). In addition to salaries and wages, the overall compensation packages including pension and other benefits should be assessed for each category. Forecast inflation rate for materials and contractors EDI submitted that CG s approach flies in the face of the Board s fixed forward test year approach to tariff regulation since EDI s inflation factor forecast, like all other aspects of its cost forecast, was made at the time of its Application based on the best and most current information available. While the Board has allowed updates prior to testimony by expert witnesses to reflect changes in general rate expectations for bonds and inflation rates in past proceedings, in this instance the CG s evidence on inflation was provided in its argument. The Board agrees with EDI that the CG s attempt to lead new evidence on CPI levels at the argument stage in the EUB Decision (August 13, 2004) 13

20 proceeding is inappropriate and unfair. Accordingly the Board will disregard the CG s submissions as they relate to updates to the CPI levels. The Board notes that, while the CG objected to the level of the CPI forecast EDI used, the CG accepted Dr. Ryan s method of using the predicted CPI for forecasting the escalation of costs for materials and contractors. The Board has reviewed the detailed information provided by EPC to support the reasonableness of each increase in each area of the Application, and agrees with CG that the method used appears to be appropriate. However, unlike the CG, the Board considers that the record demonstrates that the inflation factors developed by Dr. Ryan from predicted CPI and used to derive EDI s 2004 cost forecasts were logically developed and appear reasonable. Accordingly, the Board accepts the forecast increase of 1.4% that EDI has proposed in its GTA for materials and contractors. Forecast inflation rate for Other For similar reasons, the Board rejects CG s requested reduction to EDI s forecast inflation for Other and the Board approves EDI s applied-for rate of 2.0%. 3.2 Non-Inflation Related Increases in Operating Costs Overall Operating Costs Views of the Applicant EDI noted that EDI s witnesses were questioned on EDI s operating costs which were forecast to increase from 36.3 million in 2002 to $44.9 million in 2004, a 24% increase over a two-year period (Tr. p. 1658). A number of other parties asked questions respecting specific areas in which EDI s costs are forecast to increase from 2001 and 2002 actuals and/or 2003 re-forecast levels. EDI submitted that, during cross-examination, interveners often appeared to seek high-level explanations for forecast cost increases. In responding to questions relating to forecast increases in EDI s overall affiliate transactions costs, Mr. Cowburn emphasized the following: (Tr. pp ) Q. Well, I m just interested, Mr. Cowburn, if you could put in some I was hoping succinct narrative form for the record here. We re trying to understand, Is this a trend that more services are being performed, like more variety of services are being performed and charged as intercompany transactions in the existing services are rising? A. Mr. Cowburn: I don t believe there s any overall characterization that s going to be helpful. When things have to be done differently or when new requirements arise, as, for example, security, the company looks at what is the most effective way of dealing with that, both for the subsidiaries and for the company as a whole. And we consider whether it s most effective for the parent company to undertake a program or for the subs to do their own thing. And it varies, depending on what the circumstances are. So it s really not a matter of providing a high-level directional, Here s-what s-happening explanation, but rather, you have to look at each and every one of the individual services and factors driving those services and assess whether, Is this a reasonable way of delivering this service and a reasonable price or not? 14 EUB Decision (August 13, 2004)

21 So there is no one overall characterization that I think will fairly help to assess what s happening. That s why we provided this detailed information. EDI indicated that its approach in this proceeding was to provide detailed information demonstrating the reasonableness of each increase in each area of the Application. For example, EDI provided a detailed, account-by-account breakdown of its 2004 forecast and 2003 reforecast operating costs in Exhibit EDI also provided detailed explanations of the year over year changes in the various components of its operating costs, including forecast increases in 2004, in its Application, responses to information requests, oral testimony and undertaking responses. In reply EDI noted that while the CG asserts that the level of increases in EDI s operating costs in 2003 and 2004 are excessive having regard to inflation over the 2001 to 2004 period and other regulatory changes, the CG does not assert that the Board should disallow some portion of EDI s overall operating costs on this basis, but instead the CG identified specific reductions it was recommending. EDI submitted that the Board should assess the reasonableness of its cost increases based on the various rationales and drivers provided by EDI in evidence, only one of which is inflationary increases. EDI submitted that, when the Board did so, the Board would conclude that EDI has justified the increases both on an overall and individual basis. Views of the Interveners CG The CG submitted that the increases in O&M expense per customer from 2001 to 2004 should be assessed by the Board having regard to the reasons for the increases. The CG noted that EDI s O&M expenses reflected significant increases in 2003 and 2004, on a per customer basis, as shown below: Table 4. EDI Per Customer O&M Expenses O&M per Customer [AE ED 1 Att] Less Property Tax per customer [AE EDI 1 Att] O&M Excluding property tax per customer Percent increase year over year 3.1% 7.1% 10.1 EDI explained a good portion of the increase was attributable to the advent of EUB regulation in 2004 and the need to comply with load settlement requirements. In the CG s view the year over year increases shown above were high notwithstanding the identified drivers for the increases. An increase of approximately $27 million or 22% from 2001 to 2004 is materially higher than may be attributable to inflation over the three-year period. The CG submitted that the Board must assess the overall reasonableness of the above increases in light of the reasons provided. In the CG s submission the level of increases are excessive having regard to inflation and other regulatory changes. Views of the Board The Board notes CG s view that the year over year increases are high, notwithstanding the identified drivers for the increases (the advent of EUB regulation in 2004 and the need to comply EUB Decision (August 13, 2004) 15

22 with load settlement requirements). The CG submitted that an increase of approximately $27 million, or 22%, from 2001 to 2004 is materially higher than may be attributable to inflation over the three-year period. The Board notes that the overall increases as set out in EDI s evidence were not disputed by interveners aside from specific increases that the Board will deal with in the other sections of this Decision. Specifically the Board will look at EDI s explanations regarding O&M expenses related to: Distribution Operations Customer Services Site, Metering Settlement and Tariff Services, Support Services, Bad Debt and Affiliate Transactions The Board considers that EDI has provided a logical and complete explanation of its requirements for specific increases, aside from those listed above that the Board has dealt with in other sections of this Decision Distribution Operations Views of the Applicant EDI indicated that explanations for increases in EDI s distribution operations costs were provided in EDI s response to BR-EDI-9. There the main reasons for the forecast increases in distribution operations costs from 2002 actual and 2003 reforecast levels to 2004 forecast were set out. EDI indicated that in 2002 and 2003, lower priority work such as underground secondary maintenance, base leveling and cubicle cleaning had to be deferred due to increased levels of capital work requirements, primarily due to work that had to be performed on ETI s underground transmission system and work that was required as a result of the growth in EDI s URD and UID systems. The deferral of maintenance work in favour of capital work was described by EDI s witnesses as follows: (Tr. pp ; see also Tr. pp ) Q. Yes. So I think there s sort of two issues. Okay, the engineering staff, if you can give that split. But then even just your total personnel. Like, what I m getting at is if there are -- if one year you ve got high capital expenditures, then it may be that a lot of capital projects, the field people are going to be charging their time to that, that s the way you ve budgeted for it and everything. But then it may be, then, that the operating side of it is down a little bit in that year. A. MR. BYRON: That s correct. Q. But in another year, the next year, it switches around. Is there any way you can give sort of an indication on that split, just on your operating people as well? A. MR. ROWES: The best that I could add there is that, generally speaking, our capital program is made up of, generally, 50 percent refurbishment of the existing system. I m not talking about IT; I m talking about keep-the-lights-on type capital, and the other half is new-customer connects. Where we get into a problem from time to time is usually 16 EUB Decision (August 13, 2004)

23 when the new customer connects or customer demand goes way high on us. We then look at the priorities on our operating and maintenance accounts, and you go on something that may be a lower priority, and that might not get done in that year because you ve diverted the resources to the capital program. The kind of resources I m talking about diverting are like journeymen-level resources. I mean, we could easily go hire somebody to do what we refer to as utility work or sort of labourer work, but most of the -- most of the capital construction that we do, and as well as our maintenance, the driver behind that is our journeymen-type resources. And if we don t have them available for one, we can t get the work done. Q. All right. What was running through my mind is if -- when you set the revenue requirement, it s based on the operating expense budget, secondary effect through the capital, right? But A. MR. ROWES: That s correct. Q. Can there be a lot of fluctuations in this operating expense budget from year to year that s solely due to the fact you ve got a certain number of journeymen, but, you know, they re just -- this year they re spending a larger percentage of their time on capital, another year less A. MR. ROWES: It does happen from time to time, and we do -- we do get fluctuations from time to time. Q. So can you give me just a rough split for 2003 and 2004 what, on your journeymen, just what the split is between operating and capital? Is that -- would that be hard to do? A. MR. ROWES: We think we have an approximate number here. We believe in 04 it s more like a 50/50 split, and then 03 it would have been 60 percent on capital and 40 percent on operating. And that s just a best guess without looking up the numbers. Distribution operations costs in 2004 are forecast to increase to enable EDI to catch-up on the work that was deferred during 2002 and EDI indicated that other drivers of forecast cost increases in included changes to the method by which EDI cleans switching cubicles (i.e., using dry ice blast cleaning techniques rather than removing the cubicle from the field which resulted in power outages for customers); increased work on the network system driven by the need to increase the use of dissolved gas in oil analysis in EDI s network transformers; remediation of poles based on the results of EDI s pole inspection program; and an increase of three Full Time Equivalents (FTE) to provide 24 by 7 standby capability, 14 and an increase of two FTEs for a contract manager and accounting analyst. 15 In reply, EDI noted that the CG argued that unless EDI is able to provide justification for considering the increase of $0.6 million attributable to facilities for meter installation and repair operations as an ongoing O&M item, this item ought to be disallowed from EDI s 2004 operating cost forecast BR-EDI-8 Tr. pp Exhibits and 68 EUB Decision (August 13, 2004) 17

24 EDI indicated that the cost of operating and maintaining the facilities relating to meter operations was included in the Operations cost category on line 1 of Schedule D-2 to EDI s Application for 2002, 2003 and EDI submitted that, as noted by the CG, prior to 2002 the metering operations were performed by a third party contractor, and EDI was billed for the cost of meter operations, maintenance, repair and overheads, which included the cost of the facilities. As such, for 2001 the costs associated with these facilities were reflected in the metering category on Schedule D-2 as part of the contractors charges to EDI. The $600,000 increase in ongoing distribution operations expense in 2002 referenced by the CG is due to EDI having taken over the metering function from the contractor and becoming responsible for its own metering facilities. The costs associated with these facilities were shown in the distribution operations category. EDI submitted that a review of Schedule D-2 shows that metering costs decreased from $2.7 million in 2001 to $1.7 million in 2002, far more than the $600,000 increase identified by the CG. EDI submitted that the record justified the $600,000 increase questioned in the CG s Argument, and that it should be approved by the Board. In response to CG s argument that EDI s forecast distribution operations costs should be reduced by $200,000 in relation to catch up expenditures on distribution maintenance, asserting that expenditures related to past years are part of the Utility s risk, EDI noted the evidence describing the additional work that has to be done in 2004 in relation to underground secondary maintenance, cubicle cleaning and base leveling relative to previous years. EDI submitted that the evidence demonstrated that it is entirely appropriate that EDI include this work, which must be completed in 2004, in its cost forecast. EDI noted that the CG does not challenge the fact (and appears to concede the fact) that the $200,000 cost relates to work that will be completed in Views of the Interveners CG The CG noted that during examination EDI acknowledged at least $200,000 of increased maintenance reflected in the above summary relates to catch up for maintenance not undertaken in prior years. Q. Can you tell me how much the catchup would be from 2002, A. MR. BYRON: I don t have a specific number. It s -- for such items, I think we ve used as an example in our discussions, cubicle cleaning, switching cubicle cleaning is something that we fell behind on in 2002 and 2003, and we ve put some renewed effort in 2004, and we predict probably in 2005 we ll have additional efforts there as well to get that cubicle cleaning or the switching cubicle cleaning back up to snuff. Q. Can you tell me what portion of the 576 would be related to the catching up. A. MR. BYRON: We estimate that to be in the order of $200, The CG submitted that expenditures that should have been undertaken in prior years and not carried out due to change in circumstances are part of the utility s risk. Accordingly, such 16 Tr. p. 1286, line EUB Decision (August 13, 2004)

25 expenditures should be excluded from the 2004 revenue requirement. The CG submitted that the $200,000 related to catch up expenditures should be disallowed. In reply the CG disagreed with EDI s view that EDI s forecast operating costs for 2004 are reasonable and prudent and should be approved by the Board. The CG noted that EDI goes to great length to justify certain O&M increases in 2004 due to catch up resulting from higher capital activity in the prior year: In 2002 and 2003, lower priority work such as underground secondary maintenance, base leveling and cubicle cleaning had to be deferred due to increased levels of capital work requirements, primarily due to work that had to be performed on the underground ETI s transmission system and work that was required as a result of the growth in EDI s URD and UID systems. (EDI Argument, p. 15) The CG submitted that the labour expense forecast included in revenue requirement would be expected to be based on normalized levels of capital activity. If capital activity in the year is higher than normal on an actual basis, a higher proportion of the labour would be capitalized. Alternatively, if capital activity is lower than normal, a higher expense for labour would be recorded. This is the nature of the risk assumed by the utility. On that basis, the CG submitted that there was no justification for including any catch up expenditures related to 2002 or 2003 in the forecast O&M for This was especially so given the transition to regulation by this Board. The CG also noted that EDI attributed a $0.6 million increase in distribution O&M to facilities for meter installation and repair operations that EDI took over from a contractor in The CG submitted that, if this transaction involved replacement of ongoing contractor costs there did not appear to be any reason for the increase. Further, that it was not clear to the CG whether this item was an ongoing operating expense or a one time cost. CG submitted that, if it was a one time cost for purchase of the facilities from the contractor, then EDI should be directed to treat this item as a capital item. Alternatively, if it was a one-time expenditure in 2003, then it should not be included in the forecast for The CG submitted that, unless EDI is able to provide justification for the proposed treatment of this expenditure as an O&M item, the $600,000 item ought to be disallowed from the distribution O&M forecast for Views of the Board The Board notes that the CG raised two specific concerns with the increases in EDI s distribution O&M. First, the CG questioned the $0.6 million increase in distribution O&M attributable to facilities for meter installation and repair operations that EDI took over from a contractor in The Board notes that EDI explained that the $600,000 increase in distribution operations expense in 2002 referenced by the CG is due to EDI having taken over the metering function from the contractor and becoming responsible for its own metering facilities. 17 BR-EDI-9 EUB Decision (August 13, 2004) 19

26 The Board considers that EDI s explanation of the offsetting decrease in metering costs indicates that more than $600,000 was appropriately removed from metering costs when EDI moved the metering function in-house. The Board notes that the savings exceeded the costs of EDI performing the metering function and considers that the savings were appropriately accounted for. Therefore, the Board sees no need for any other adjustment to EDI s forecasts in regard to this matter. Second, the CG submitted that expenditures that should have been undertaken in prior years but were not carried out due to changes in circumstances should be part of the utility s risk and excluded from the 2004 revenue requirement. CG submitted that the $200,000 related to catch up expenditures should be disallowed. In reply, EDI noted that CG did not claim that this is work that will not or need not be done in While EDI submitted that the work will be and must be done in 2004, the Board does not consider the issue to be whether the work will or needs to be done in The Board considers that EDI s justification of inclusion in 2004 revenue requirement simply because the work will be done in 2004, does not respond to the issue of whether the work has already been paid for by customers. The Board notes that EDI used the term catch-up to refer to maintenance that EDI was not able to get to in 2002 and 2003 due to the load-growth spurt that we experienced. 18 The Board considers that the term catch-up provides a strong indicator that these operating expenditures were planned to be carried out in 2002 and 2003 and would therefore have provided the basis upon which forecast and actual results would have been measured under EDI s performance based regulation (PBR). The Board notes that EDI is kept whole by the fact that the expenditures originally planned to be operating expenses were diverted to capital and therefore EDI will be compensated, after the test period, for these unexpected capital expenditures through rate base. The Board agrees with CG that catch-up type expenditures that have formed part of EDI s prior year maintenance budget forecast should not be allowed in EDI s current year revenue requirement. The Board considers that lower than planned maintenance in 2002 and 2003 would have been rewarded under EDI s PBR. Accordingly, if the Board were to allow such items in EDI s current year revenue requirement, EDI would double recover from customers for the expenses to maintain its facilities. Considering all of the above, the Board is not persuaded that it should allow EDI to charge for catch-up expenses relating to maintenance that should have been performed in prior years. Accordingly, the Board directs EDI, in its refiling, to reduce its revenue requirement for the $200,000 of distribution operations catch-up type expenditures Customer Services Views of the Applicant EDI indicated that it had provided detailed evidence explaining forecast increases in its customer services costs in Section of its Application and in response to IPCAA-EDI-23. EDI submitted that customer services costs were not challenged in cross-examination and no evidence was filed taking issue with these costs. 18 Tr. p EUB Decision (August 13, 2004)

27 Views of the Board Interveners did not specifically challenge these costs. The Board has reviewed the customer services costs and considers them to be reasonable. Accordingly the Board approves EDI s 2004 forecast of customer services costs Site, Metering, Settlement and Tariff Services Views of the Applicant EDI indicated that the main forecast cost increases in the site, metering, settlement and tariff services area related to increases in the forecast number of off-cycle meter reads, increased meter field activity, and changes in the inter-corporate service agreement with EPCOR Water Services Inc. (EWSI). As was noted in EDI s Errata Letter (Exhibit , p. 2), the increased costs of off-cycle meter readings are offset by a revenue offset. As noted at Tr. p. 1292, increases in meter field activity are expected as EDI returns to tasks deferred during the intense construction activities of the past few years, as described in the context of distribution operations expense. Changes in the intercorporate service agreement with EWSI are described in Appendix B-2-3 of EDI s Application, and their justification is explained in the BearingPoint report (Appendix B-7, section , p. 37). EDI indicated that these changes are based on an analysis of costs actually incurred, and represent a fair sharing of the costs of meter reading with EWSI, to the benefit of EDI s electric service customers. In reply, EDI noted that the CG argued that EDI s metering services forecast should be reduced by $0.25 million in relation to catch up expenditures, asserting that expenditures related to past years are part of the Utility s risk. DEI submitted that for the reasons provided in respect of the catch up distribution maintenance work, the costs associated with catch up work relating to metering services is justified and should be approved (Tr. pp ). EDI noted that the CG did not claim that this is work that will not or need not be done in Views of the Interveners CG The CG submitted that meter maintenance and meter verification expenditures that should have been undertaken in prior years and were not carried out due to changing circumstances are part of the utility s risk. In the CG s view such deferred expenditures should be excluded from the 2004 revenue requirement. The CG submitted the $250,000 related to catch up expenditures should be disallowed. Views of the Board The Board considers that the circumstances of the catch-up work on meter maintenance are similar to those of the other catch-up expenses dealt with earlier in this Decision. For similar reasons as for the other catch-up expenses dealt with earlier, the Board directs EDI, in its refiling, to reduce its revenue requirement for the $250,000 of metering O&M catch-up type expenditures. EUB Decision (August 13, 2004) 21

28 3.2.5 Support Services EDI provided extensive information relating to support services. There are two broad categories of support services: services provided internally by EDI personnel, and services provided by EUI personnel. This section deals with the costs of services provided internally by EDI personnel. Views of the Applicant EDI noted that the CG asserted that EDI s forecast increase in internal administrative costs was unwarranted, and claimed that the Board should reduce EDI s applied-for costs by $0.25 million in 2004 to reflect a fair level of increase in administrative expenses for 2004 consistent with the change to EUB regulation. EDI submitted that the CG provided no reasonable basis, either in evidence or compelling argument, for the recommended decrease. By contrast, EDI provided evidence explaining its forecast increase in administrative costs (e.g., BR-EDI-8(a) and UCA-EDI-21(a)). Furthermore, the BearingPoint reports demonstrate the reasonableness of EDI s 2004 forecast costs vis-à-vis the services provided in the four categories identified by the CG. EDI submitted that the evidence shows that these cost increases are reasonable and justified and should be approved by the Board. The record demonstrates that EDI s forecast increases in support services costs for 2004 are justified and should be approved by the Board. Views of the Interveners CG EDI s support services costs are made up as follows (in Millions of dollars): Table 5. EDI Support Services Costs 2001 Actual 2002 Actual 2003 Re-Forecast 2004 Forecast EDI Costs EUI to EDI Operating EUI to EDI Capital Usage Fee EDI to ETI ETI to EDI EDI to ETECH EDI to EESI -0.1 Total Support Services O&M Source: Exhibit The above table shows EDI s costs increasing by $0.3 million from 2002 actual and by a further $0.6 million from 2003 to The major portion of the increase relates to the following accounts: Table 6. EDI Accounts with Major Support Services Cost Increases Code 2003 ($000) 2004 ($000) General Admin , ,059 Legal ,000 36,720 Executive , ,681 Space Rental/Maintenance , ,654 TOTAL 890,908 1,193, EUB Decision (August 13, 2004)

29 With respect to EDI s internal support services costs, the CG submitted that EDI's proposed 34% increase (or $302,206) in administrative O&M is unwarranted. The CG recommended a reduction in EDI s administrative O&M of $250,000 in 2004 to reflect a fair level of increase in administrative expenses for 2004 consistent with the change to EUB regulation. The CG noted that EDI stated the major factors contributing to increase in overall cost of internal support services from 2001 to 2004 relate to additional costs associated with implementation of the code of conduct and the transition to EUB regulation totaling $1.6 million, higher charges for the use of EUI-owned assets in the amount of $1.5 million and inflation in the amount of $0.9 million. 19 The CG submitted that those explanations do not appear to explain why EDI s administrative expenses included in the above noted accounts should increase so significantly from 2003 to While the CG conceded that there might be some administrative cost increases associated with the administration of the code of conduct and advent of EUB regulation, the CG submitted that a 34% increase in the above internal administrative expense seems unwarranted. The CG recommended the requested increase from 2003 to 2004 for the above noted accounts be reduced by at least $250,000 to reflect a fair level of increase for 2004 consistent with the change to EUB regulation. Views of the Board The Board has dealt with EDI s forecast of corporate costs from EUI in a separate section of this Decision. In regard to EDI s $302,206 increase in internal support services costs, the Board notes that the CG questioned Exhibit indications on an account level. In reply to CG, EDI referenced UCA-EDI-21(a), BR-EDI-8 and the BearingPoint Study. The Board notes that the bulk of the $302,006 increase was due to an increase in General Administration (7001) as explained by EDI when questioned in cross-examination. The Board notes the increase of 52% or $255,000 in that account was due to EDI s forecast that the amount of 2004 vacation and overtime banked would be increased markedly due to the increased workload related to the transition to EUB regulation ($200,000) and inflation. 20 The Board is persuaded by the explanations provided by EDI respecting reasons why the EDI internal administration costs are forecast to increase by $302,206 and the Board will not accept the CG s Argument that a reduction of $250,000 is warranted Bad Debt Views of the Applicant EDI noted that the CG recommended a reduction to EDI s forecast bad debt expense for 2004 based on an assessment of aged account balances. The CG also asked the Board to direct EDI to review whether the amounts identified as bad debts should be treated through the SIR account or, alternative, be regarded as repairs BR-EDI-8 Tr. pp EUB Decision (August 13, 2004) 23

30 EDI submitted that the CG had not provided a reasonable basis for reducing EDI s forecast bad debt expense. EDI submitted that its forecast of $216,000 is appropriate and should be approved. EDI also submitted that the record demonstrated that the costs in question do not qualify as costs which the self-insurance reserve is intended to capture (see EDI-BR-05) and would not conform to the criteria outlined on pages 30 and 31 of EDI s DTA. Nor are they appropriately dealt with as repair expenses. As such, EDI submitted that there would be little value in undertaking the recommended review. Views of the Interveners The CG submitted that EDI s forecast of bad debt expense for 2004 is out of line with that experienced in prior years. The 2002 actual amount appears to be an anomaly since it reflects a general clean up of accounts that had not previously been written off. CG also submitted that as a percent of revenue offset amounts, the 2004 bad debt expense appears excessive. Based on an assessment of aged account balances, the bad debt expense should not be in excess of $100,000 for However, if the 2001 actual experienced bad debt expense is used, and escalated to 2004 using inflation, the reduction to the 2004 forecast would be $162,110. The CG recommended that the Board direct EDI to review, for purposes of its next GRA, whether the amounts identified, as bad debts should really be treated through the SIR account or, alternatively, be regarded as repairs. The CG noted that EDI confirmed 21 that its bad debt expense relates primarily to damage claims and that it has not had any bad debts expense related to retailers in large part because it has prudential requirements in place. As such, these bad debt expenses are related to the Revenue Offsets forecast of EDI. 22 The following table shows the amount of bad debts and related amounts of Revenue Offsets: Table 7. EDI Bad Debts Related to Revenue Offsets Bad Debts Revenue Forecast Ratio 2001 Actual Note 1 116,648 2,500, % 2002 Actual 331,087 2,500, FC 216,500 2,600, % 2004 FC 286,110 2,100, % Note 1: The FC of Revenue Offset is from Exhibit , Appendix B-2-3, and Exhibit The 2001 FC of Revenue Offset is an estimate based on the actual revenues from At Tr. pp , EDI stated that its forecast is based on a review of the history or past experience and a review of its aged accounts receivables. The CG submitted that review of the aged receivables 23 suggests the over 90 days receivables at the end of 2002 are only $44,000, compared to $447,000 in At Tr. p. 2443, EDI explained that in 2002, it had cleared up an number of prior years accounts, which would Tr. p Tr. p Exhibit EUB Decision (August 13, 2004)

31 indicate that its 2002 experience of bad debts (of $331,087 per Exhibit ) was an anomaly, and that a more normal forecast should be about the same level as 2001 of $116,648. Also, if one examines the aged receivables, 24 it is noted that the over 90 days accounts in 2002 are about the tenth of the amount in Even if one assumes accounts over 60 days as becoming potentially bad, the maximum of the bad debt forecast should not be over $100,000 if it is based on an aging assessment of EDI s accounts. On that basis the CG s submitted that the 2001 actual result of $116,648, escalated for inflation (assumed average of 2% per annum), should be the appropriate forecast for This would suggest an appropriate 2004 forecast is $124,000. The CG recommended that a reduction of $162,110 be effected to the 2004 forecast of $286,110. This would include the correction of the $70,000 error noted at Tr. p by EDI, which revised the 2004 bad debt forecast from $286,110 to $216,000. Views of the Board The Board notes CG s submission that EDI s revised forecast of bad debt expense for 2004 of $216,000 is not consistent with that experienced in prior years. The Board agrees that the 2002 actual amount should be considered to be an anomaly since it reflects a general clean up of accounts that had not previously been written off. The Board also agrees with CG s submission that the 2001 actual result of $116,648, escalated for inflation (assumed average of 2% per annum), should be the appropriate forecast for The Board agrees with the CG that this would suggest that an appropriate 2004 forecast is $124,000. According, the Board directs EDI, in its refiling, to reduce bad debt expense for 2004 by $92,000. In regard to the CG s recommendation that the Board direct EDI, for purposes of its next GTA, to review whether the amounts identified as bad debts should be treated through the SIR account or, alternatively, be regarded as repairs, the Board notes that it has set out the criteria for EDI s SIR in another section of this Decision. The Board has reviewed the policy approved for EDI s SIR account and considers that bad debts would not normally be eligible for the SIR if EDI follows its policy. EDI has confirmed 25 that its bad debt expense relates primarily to damage claims and that it has not had any bad debt expense related to retailers in large part because it has prudential requirements in place. As such, these bad debt expenses are related to the Revenue Offsets forecast of EDI. 26 The Board considers that EDI s current approach for accounting for bad debt is acceptable. Therefore, the Board sees no need to direct EDI to conduct the review recommended by CG. As for EDI s approach to bad debt matters prior to 2004, the Board has no persuasive evidence that EDI s past treatments will impact customers in 2004 or subsequent years Provided in Exhibit Tr. p Tr. p EUB Decision (August 13, 2004) 25

32 3.3 Employee Numbers and Compensation FTEs Views of the Applicant EDI indicated that it had provided extensive information respecting its historical and forecast FTEs (including a breakdown by union vs. management and by cost category) in its responses to information requests (e.g., EDI s responses to CCA-EDI-6, IPCAA-EDI-8(b), UCA-EDI-21, PICA-EDI-64). During the Hearing, EDI also provided a detailed breakdown and reconciliation of its FTEs for 2001 and 2002 actuals, 2003 reforecast and 2004 forecast, along with explanations for each increase in FTEs from 2002 actual to 2003 reforecast, and 2003 reforecast to 2004 forecast (Exhibits and 68). Additional detailed information was provided by the witnesses during oral testimony. (see Tr. pp ; Tr. pp ; Tr. pp , , , , ; Tr. pp ; Tr. pp ) A number of questions were asked respecting the reasons for the increases in FTEs shown in the table included in EDI s response to UCA-EDI-21(e)(ii) entitled Change in Operating FTEs 2003 Re-forecast to 2004 Forecast. In response to these questions, EDI provided the following evidence: The 7 additional FTEs for IT support in relation to the Work Management System consist of new hires within EDI in 2004 which replace 7 FTEs that were allocated to EDI from EUI to fulfill this function. The number of IT support FTEs allocated to EDI from EUI in 2004 was reduced by the 7 FTE new hires within EDI, and there is no incremental increase in cost to EDI as a result of the addition of these FTEs. Four of these FTEs relate to the AIMMS system component of EDI s overall work management systems, and were contemplated in the business case originally prepared when that system was put in place in 2002 (Exhibit ). The other three FTEs relate to the provision of IT support to other components of EDI s work management systems. The need for 7 FTEs to fulfill this function was determined in conjunction with EDI s IT group, based on professional judgment and experience, having regard to, for example, the complexity of the application area and what is required to support the application. The 3 additional FTEs (i.e., the increases from 12 to 15 FTEs) in the area of standby staff to respond to customer outages relate to the addition of stand-by system restoration capability on a 24 by 7 basis. EDI currently has staff on stand-by who will respond to outages, but does not have stand-by personnel available off-hours or during statutory holidays with the skill-sets necessary to restore power in all circumstances. The purpose of these additional 3 FTEs is to add this capability. Mr. Rowes testified that adding this stand-by capability is something the Corporation has been looking at for a number of years, and it is consistent with the practices of other utilities in the Province (Tr. pp ). Mr. Byron confirmed that EDI anticipates that the requirement to pay for this additional stand-by capability will be reflected in the collective agreement that is currently being negotiated with the union (Tr. pp ). The 2 additional FTEs for a contract manager and accounting analyst relate to new hires to fulfill functions, which are key to EDI s business operations. The contract manager will work in EDI s customer engineering services area, fulfilling such tasks as assisting larger customers in determining the tariff structure that applies to them, which assets would be appropriate for them to be responsible for, interfacing between customers and 26 EUB Decision (August 13, 2004)

33 the AESO in respect of a customer s nomination of contract minimums, and general contract management relating to such things as demand levels and other aspects of the customer s contractual relationship with EDI. A posting for this position was issued by EDI on the weekend prior to the commencement of the Hearing. The accounting analyst will provide additional reporting and record-keeping functions that are now required by EDI to support, for example, the Corporation s regulatory filings. EDI s witnesses testified that this position has been filled. The 1 additional FTE to address increased training demands relates to the addition of a clerical position to assist with the development of training programs, the ongoing improvement of those programs and the documentation of hazard registry information (Exhibit ). Mr. Byron explained that the hazard registry function will involve field people working with EDI s training people to identify and register hazards as they are encountered in their daily work program, assigning values to those hazards using formulas, and then designing the appropriate means of preventing those hazards from adversely impacting employees who are performing the relevant work duties. Mr. Rowes and Mr. Byron confirmed that the hazard registry is intended to improve the safety of the Corporation s employees in their daily work activities. The 3 additional FTEs to address growth and aging infrastructure relate to staff necessary to deal with expansion of EDI s system to meet load growth, as well as additional work that is required to deal with EDI s existing infrastructure which continues to age from year to year. The 2 additional FTEs for meter readers to address Alberta Settlement System Code meter data manager performance standards relates to EDI s anticipation that its regulated rate provider will be requesting a higher number of off-cycle meter reads. Mr. Cowburn confirmed, however, that there is a corresponding increase in EDI s forecast of revenue offsets to reflect the fact that its regulated rate provider will be billed for the anticipated increase in off-cycle reads. As a result, on a forecast basis, customers will not bear any additional costs in 2004 for these 2 additional FTEs. The 4 additional FTEs for IT support for the WISE system consist of two data-based administrator positions that previously resided in EUI and were allocated to EDI, and which have been moved into EDI for 2004, and two new positions to fulfill functions required to support the WISE system. The first of the two new positions relates to data testing to ensure the accuracy of EDI s bills. This function has been carried out by an external consultant in the past, and the FTE will provide this function within EDI at reduced cost. The second of the two new positions will provide necessary additional overall IT production support in the new RDS environment, as discussed at Tr. p. 1210, and will enable EDI to ensure appropriate IT support coverage in the event that key IT people leave the Corporation which often occurs. EDI s witnesses provided the status of each additional FTE shown in its response to UCA-EDI- 21(e)(ii), demonstrating that they are real and are required to enable EDI to properly carry on its business operations (Tr. pp ). The witnesses also provided evidence which explained differences between FTEs and full-time positions, and the difference between the terms labour and salary as used in EDI s filings (Tr. pp ). EDI also provided a detailed explanation of its forecast increase of 11 contractor FTEs from 2003 reforecast to 2004 forecast (Exhibit ). Questions were asked with respect to EDI s EUB Decision (August 13, 2004) 27

34 forecast of approximately 20 additional FTEs (a combination of internal FTEs and FTEs allocated from EUI) required as a result of the transfer of regulatory authority from Edmonton City Council to the Board. In response, EDI s witnesses provided a detailed description of the functions of each of these 20 additional FTEs, demonstrating that they are reasonably required to enable EDI to properly function in its new regulatory environment (Tr. pp ; see also Exhibit ). Questions were asked with respect to the increase in FTEs allocated to EDI from EUI from 41 in the 2003 re-forecast to 49 in EDI s 2004 forecast. EDI s witnesses testified that the increase (net of the shift of 7 IT FTEs from EUI to EDI described above) were the result of a number of areas that demand higher levels of service in 2004 compared to 2003, including such areas as regulatory assistance and code of conduct matters. EDI submitted that, with EDI moving to EUB regulation, the impacts of regulatory decisions for other participants within the electric industry have a greater impact on EDI than when EDI was regulated by the City of Edmonton. As a result, an increased focus in tracking regulatory activities is required. It was determined that the EPCOR group could most efficiently achieve this through a shared corporate function where their expertise and advice could be shared throughout the organization resulting in cost efficiencies to customers (DTA, Appendix B-7, section 3.1.2; Exhibit ; Tr. pp and 1463). Further, the change in the Code of Conduct and the additional requirements of the Alberta Personal Information Protection Act, effective January 1, 2004, have driven the need for a dedicated corporate function to ensure all business units of EPCOR are compliant with the legislation. EDI submitted that having the role at the corporate rather than business unit level will ensure consistency in the application of the legislation and will allow for cost efficiencies that will flow through to customers. EDI submitted that the evidence demonstrated that EDI s cost forecast reflects an appropriate and reasonable number of FTEs, all of which are prudently required to allow EDI to properly fulfill its role as the owner of an electric distribution system (including its role as an LSA, MDM, etc.). In reply EDI noted that the CG argued that EDI s forecast operating costs for the 2004 test year should be reduced to reflect a reduction of 11 FTEs. EDI submitted that EDI s evidence in the proceeding was that EDI does not use FTEs as a tool for budgeting purposes and EDI had provided FTE numbers based on a mathematical calculation to assist the Board and interested parties who expressed an interest in these numbers. In spite of this, the CG spends a large portion of its Argument tracing through and summarizing EDI s evidence relating to FTEs and then attempts to rely on that exercise as a basis for accusing EDI of having provided apparently ad hoc explanations for increased staffing ; of making numerous updates and changes in O&M and other areas during the hearing; and of having a poor forecasting record. EDI submitted that the CG then uses this as its basis for arguing for the 11 FTE decrease in operating costs. EDI submitted that it had provided a detailed discussion of the extensive evidence on the record demonstrating the reasonableness of its FTE forecast for Further, that the CG s summary of the evidence demonstrated that EDI has provided full explanations for its forecast operating costs, not only from the perspective of the manner in which those costs were forecast by EDI, but also when those costs are translated into FTEs. EDI submitted that the evolution in the evidence of facts surrounding its FTEs is to be expected given the uncontested fact that EDI does not use FTEs in the manner in which interveners are apparently used to in respect of utilities that have 28 EUB Decision (August 13, 2004)

35 historically been regulated by the Board. EDI submitted that, in spite of this, EDI has demonstrated the reasonableness of its operating costs from the perspective of FTE count. In regard to CG s comment that EDI made numerous updates and changes in O&M and other areas during the hearing, EDI notes that while many of its revisions related to its efforts to provide the Board and parties with information from an FTE perspective, its overall operating cost forecast increased by only $0.1 million from $50.1 million in its original filing to $50.2 million in its errata filing. EDI submitted that a review of the evidence shows that EDI has provided compelling evidence demonstrating the reasonableness of each increase included a detailed description demonstrating the reasonableness of the increases in FTEs over previous years. Contrary to the CG s assertions, it is a gross mischaracterization of EDI s evidence to describe it as being ad hoc in any sense. EDI submitted that the CG s reference to EDI s forecasting record with significant regulatory staff in place was unclear. However, irrespective of what the CG happens to be attempting to refer to as EDI s forecasting record, the CG provided no rational basis in either the evidence or reasoned argument to support its comment. In regard to the CG s specific claims in support of its assertion that EDI s forecast operating costs should be reduced to reflect an 11 FTE reduction, EDI submitted that CG provided no reasonable basis for this reduction and has failed to provide any compelling reasons as to why EDI s evidence demonstrating the reasonableness of its forecast FTEs should be rejected. EDI provided submissions on each FTE reduction the CCA recommended: While the CG argued for a 2 FTE reduction in re-forecast staff that it says were not hired as of March 1, 2004, EDI noted that these 2 FTEs relate to the implementation of its invoice system in EDI submitted that Exhibit , Table 4 makes it clear that these 2 FTEs were not included in EDI s 2004 forecast. That is, there was a 2 FTE reduction in EDI s 2004 forecast to reflect the fact that the invoicing system had been completed in 2003, and these two staff were not required in Accordingly, there is no basis for reducing EDI s 2004 FTE count by what would effectively be an additional 2 FTEs. While the CG asserted that the addition of 1 FTE for staff to manage increased training requirements does not appear justified, the CG acknowledged that the requirement for additional training and documentation always exists, but stated that it cannot understand why this needs to be done in 2004 versus doing it in 2003 or EDI submitted that the basis for the CG s argued reduction is entirely unpersuasive. As the CG concedes, the need exists and the failure on the part of the CG to understand why it has to be implemented in 2004 does not provide any basis for disallowing the cost. EDI submitted that the need for and sound rationales behind this expenditure were summarized beginning on page 21 of EDI s Final Argument (see also Exhibit ) and that the forecast cost associated with this FTE should be approved. The CG argued that the 2 FTEs for staff due to growth and aging infrastructure should be disallowed on the basis that they appear to simply be another way of adding stand-by staff from the previous versions of evidence. EDI submitted, that CG s argument made little sense since EDI s evidence was clear that these FTEs relate to cubicle cleaning and EUB Decision (August 13, 2004) 29

36 pole maintenance (BR-EDI-9, p. 3), and have nothing to do with stand-by charges (Exhibit , p. 2). EDI submitted that the CG s argument for a 5 FTE reduction in costs in relation to 5 notional FTEs that will be assigned on an as-required basis demonstrated a misunderstanding on the CGs part of the difference between people, or noses as that term was used by EDI s witnesses, and FTEs. EDI s witnesses made it clear that the additional notional FTEs were not noses but represented a mathematical calculation of additional full-time equivalents that EDI is forecasting will be required to enable the Corporation to function under EUB regulation (Tr. p. 1686). The 5 FTEs will be made up of portions of numerous employees time, and those portions of time happen to equate mathematically to 5 FTEs. EDI submitted that it is ludicrous on the CG s part to suggest the 5 notional FTEs somehow meant that EDI is intending to have 5 specific staff members who will interchangeably carry out such functions as clerical work, senior financial management work and project management work. The CG s basis for suggesting a decrease has no merit. On that basis, EDI submitted that the CG has failed to provide any reasonable or compelling basis for any of the recommended FTE-related disallowances. To the contrary, the record clearly demonstrated that the FTEs in question are justified based on sound and uncontradicted evidence, and that the costs associated with those FTEs are justified and should be approved by the Board. In regard to the CG s recommendations for future proceedings, EDI submitted that it intended to prepare its next GTA in a manner that reflects the type and form of information requested of and prepared by EDI throughout the course of the proceeding that the Board indicated that it found helpful. EDI submitted that the CG has provided no basis in either the evidence or persuasive argument as to why this information is required. In regard to the FTE breakdown requested by the CG, EDI submitted that EDI s charges from affiliates, as shown by CCA-25-EDI Attachment, are not calculated in a manner that would allow for a breakdown between union and management staff. EDI submitted that the CG demonstrated any need for the recommended directions, much less that the requested information would be of assistance to the Board or that the costs associated with producing it would be worthwhile. EDI submitted that the Board should decline to make the requested directions. Views of the Interveners CG The CG noted that after a number of iterations and changes to its numbers, EDI finalized its forecast 2004 net FTE count at 330, as shown in revised Exhibit This topic was also canvassed by Board staff with the resulting number of FTEs for 2004 suggested at 372 FTEs. 27 The CG submitted that this differential was not reconciled. 27 Tr. pp EUB Decision (August 13, 2004)

37 For purposes of its Argument, the CG used the FTE count of 330 noted in Exhibit In presenting the FTE numbers, EDI noted at the bottom of page 3 of revised Exhibit that the FTE count is based on the mathematical derivation arising from the forecast adjusted base compensation in Table 2 and dividing it by the average salary. However, in cross-examination with UCA counsel, EDI also admitted that the industry...uses FTEs as a way of gauging the quantum of labour required in order to deliver services. 28 The CG agreed with this last viewpoint. The CG submitted that the FTE count should be more than a mathematical exercise since, the Board and Interveners have in the past examined the issue of FTEs in every proceeding and the FTE count was a relevant consideration and benchmark. The CG submitted that, while EDI may choose not to budget in that manner, the FTE count is another form of benchmarking that the Board has used to measure utilities O&M costs. The UCA conducted extensive cross-examination to determine the basis for the derivation of EDI s FTE count for 2004 and previous years. 29 Other parties, including the Board and Board staff also had a number of questions on this issue. The CG submitted that it was established through cross-examination that: (i) The original response to UCA-EDI-21(e)(ii) proposed a total change in FTEs from 2003 Re-forecast to 2004 forecast of 23 FTEs. The response UCA-EDI-21(e) changed again during the course of the hearing. The total change in FTEs from 2003 Re-forecast to 2004 forecast was updated to 22. The noteworthy change was the deletion of the 1 FTE for Addition of staff due to Growth and the deletion of the 2 Support Services staff from the previous version of UCA-EDI-21(e)(ii). There was an addition of 1 FTE for Meter Readers compared to the previous version. The final change in FTEs was made in Exhibit where the change in Operating FTEs net of transfers to Capital and Affiliate s became 11. The notable changes were the elimination of the 7 FTEs for IT support for the Work Management System, the elimination of the 2 Standby staff FTEs, the reduction of IT support for the WISE system from 4 FTEs to 2 FTEs, the addition of 2 FTEs for a new category growth and aging infrastructure, the addition of 2 Regulatory FTEs (who had been eliminated in the second version off UCA-EDI-21(e)(ii)) and a new reduction of 2 FTEs for reduced support due to completion of invoicing system in 2003 ; (ii) In contrast to the original UCA-EDI-21(e)(ii), the original forecast increase in FTEs from 2003 re-forecast to 2004 was 17 as shown in IPCAA-EDI-8(f). This was ultimately changed to 11 (excluding management) as shown in Table 3 of Revised X ; (iii) 2 additional FTEs forecast to be hired in the 2003 Re-forecast compared to the 2003 original forecast had still not been hired as of March 1, 2004; Tr. p Tr. pp and other references Tr. pp EUB Decision (August 13, 2004) 31

38 (iv) When comparing forecast to actual FTEs for 2001 to 2003, there is a consistent tendency to overforecast (i.e. forecast is always greater than actual). 31 For example, the 2001 Forecast of FTEs shown in UCA-EDI-21(f) was 352. The actual FTEs for 2001 were 263 as shown in IPCAA-EDI-8. The 2002 forecast of FTEs was 315. The 2002 actual FTEs were 301. The 2003 Original Forecast FTEs were 348 while the 2003 Re-forecast FTEs were 314. The CG submitted that, in further detailed cross-examination on the specific rationale for increases in FTEs from 2003 Re-forecast to 2004, it was also established that: (i) the addition of 3 FTE stand-by staff to respond to customer outages (see UCA-EDI- 21(e)(ii)) is a new category for 2004 that adds to the existing 12 staff used to respond to customer outages. Yet, there were no difficulties in past years without the stand-by staff. 32 This category was eliminated and the FTE change became 0 in Exhibit ; (ii) the addition of 1 FTE for increased training demands is to...assist with the development of training programs and the documentation of the hazard registry information. 33 Finally, in response to an undertaking to the Chairman 34 to explain the breakdown of 20 employees added because of regulatory requirements, EDI explained in the response 35 at page 4 there were an additional 5 Notional FTE to be assigned on a regular basis. These additional 5 FTEs (9 separate jobs, 14 positions in total) had a range of skill sets including Clerical Administrative Support, Regulatory Librarian, Engineering Manager, Business Analysis Manager, Senior Manager, Pricing and Cost of Service and Senior Financial Manager to name some. The CG submitted that these skill sets were not easily interchangeable. The CG concluded from the above that EDI had no good excuse for the poor forecasting record, numerous updates and changes in O&M and other areas during the hearing and apparent ad hoc explanations for increased staffing: all done with significant additional regulatory staff in place. On that basis, the CG submitted that the Board should reduce the number of FTEs over and above reductions recommended in the CG s Vacant Position Allowance argument. The CG recommended that the reductions should include the following: (i) 2 FTEs for the 2003 Re-forecast staff that were still not hired as of March 1, 2004; (ii) 1 FTE for the new IT Relationship Manager. The requirement for this new FTE was introduced with Exhibit There is no proper explanation for this new FTE; (iii) The addition of 1 FTE for staff to manage increased training requirements does not appear justified. The requirement for additional training and documentation will IPCAA-EDI-8(f) compared to UCA-EDI-21(d) Tr. pp Exhibit Tr. p Exhibit EUB Decision (August 13, 2004)

39 likely always exist. Why this needs to be done in 2004 versus not doing in 2003 or doing in 2005 was not explained; (iv) The addition of 2 FTEs for staff due to growth and aging infrastructure was introduced with Exhibit and appears to simply be another way of adding stand-by staff from the previous versions of evidence; (v) 5 Notional FTEs to be assigned on an As Required Basis simply because the range of job positions and type of staff requirement are not directly interchangeable. You cannot hire a person to do clerical work and substitute them for a Project Manager or Senior Manger. Neither can you hire a person to be a Senior Financial Manager and substitute them for an Engineering Manager. EDI s shopping list of additions is without proper justification. CG recommended these total reductions in FTEs of eleven. While the exact salaries and benefits of the 11 FTEs is not known, the CG noted that a dollar reduction of $74,028/FTE was derived using the simple method set out in its argument for a reduction in O&M for Vacant Position Allowance. Based on the $74,028/FTE and 11 FTEs proposed reduction, the CG recommended a reduction in O&M of approximately $800,000 in Further, in order to reduce the confusion in future hearings about the definition and determination of FTEs and their link to O&M and Capital labour dollars, the CG recommended that the Board direct EDI as part of its initial filing in its next GTA to derive an appropriate definition and determination of the FTE count and provide a reconciliation to the total head count. This reconciliation should include the split between O&M and Capital FTEs as well as the Corporate FTEs moving to and from EDI. CG recommended that Exhibit , adapted to show FTE counts, including capital assignments, could be used as a template for EDI to show its FTE count in a simple tabular form. The FTE count could then be easily reconciled with a similar table showing O&M and capital costs as demonstrated in Exhibit The CG indicated that, with the exception of the forecast inflation costs and At Risk compensation amounts for 2004, the CG did not object to EDI s 2004 forecast cost per FTE. The CG submitted that EDI should be directed to provide further details of the cost per FTE for Union and Management employees whose costs are passed-down from EDI Affiliates to EDI, as part of EDI s next GTA filing. EDI provided its cost per FTE in response to UCA-EDI-21(f) and (g) for the years 2001 to For 2004, Union employees average Base compensation is shown as $53,100/year plus Fringe Benefits while Management Employees average Base and At Risk compensation is shown as $95,700 plus Fringe Benefits. The CG were unsure whether pass-down costs from Affiliates are included in these averages and thus restricts its comments to EDI staff. In reply the CG submitted certain sections of the CG Argument required revisitation to demonstrate the lack of clarity that EDI has shown with respect to the number of FTEs it requests for EDI s Argument demonstrates the confusion that arose throughout the hearing on the topic of FTEs. CG firstly noted that while EDI has provided reference to its evidence, a number of transcript pages and information responses, it failed to provide a single number in Argument that represents EDI s forecast number of FTEs for 2004 and the increase in FTEs from 2003 re-forecast to 2004 forecast. CG submitted that it appears the number of FTEs is either 330, 372, 371 or perhaps some other number. EUB Decision (August 13, 2004) 33

40 The CG submitted that even EDI itself might not fully understand the total FTE number for This may be in part based on EDI s view, the number of FTEs is simply a mathematical derivation or because EDI itself simply does not know the exact number of FTEs it is forecasting. The CG submitted that the forecast increase in the number of FTEs for 2004 is equally cloudy. Views of the Board The Board notes that the CG has attempted to support a reduction of EDI s labour contingent using FTEs. Whereas EDI in cross-examination with UCA counsel agreed that the industry uses FTEs as a way of gauging the quantum of labour required to deliver services, 36 EDI had not prepared its labour forecasts on that basis. The Board notes that EDI also indicated that many of its revisions related to its efforts to provide the Board and parties with information from an FTE perspective. As a result the Board has some sympathy for EDI in regard to its difficulties in conversion to FTE calculations and maintaining consistency in its explanations. However, the Board does note that EDI was in agreement that its future filings should be prepared in a manner that reflects the type and form of FTE information requested of and prepared by EDI throughout the course of the proceeding, which the Board indicated that it found helpful. The Board considers that a consistent approach to forecasting labour costs should be used by the utilities that the Board regulates. Accordingly, the Board directs EDI, in its next GTA, to include a comprehensive explanation, including calculations, of the derivation of the number of FTEs and cost per FTE for each of the functions of EDI s DT service. The Board notes from revised Exhibit that compared to 2002 actual, EDI forecast a 3.2% increase in FTEs for 2003 re-forecast and a further 3.4% increase over the 2003 re-forecast for 2004, for a total increase of 21 FTEs over the two-year period from 2002 to The CG pointed out significant differences between forecasts and actual FTEs over the period The Board recognizes that the FTEs are derived from the underlying forecast dollars. However, this fact suggests that the same over-forecasting would also manifest in the underlying forecast dollars. EDI made no attempt to refute its apparent tendency to over-forecast. The Board notes that the minimum over-forecast in the 2001 to 2003 period is 14 FTEs. While the Board does not necessarily agree that the specific position reductions CG suggested to arrive at its recommended 11 FTE reduction are warranted, the Board does consider that an overall 11 FTE reduction is warranted considering EDI s forecasting track record. However, the Board notes that EDI disputed that the reduction of the FTE count by a total of 11 FTEs would equate to approximately $800,000 for EDI indicated that CG s calculation of a cost of $74,028 per FTE was inaccurate, and that the amount should be $70,500, being the average salary of $60,000 noted in Exhibit (pg. 3) with a 17.5% fringe benefit allowance. The application of a 31.5% fringe benefit allowance to labour employees is not required as the 36 Tr. p EUB Decision (August 13, 2004)

41 average salary amount includes an adjustment for a 14% fringe differential for labour employees related to paid vacation and statutory holidays. (Exhibit ) The Board accepts EDI s calculation of an average cost of $70,500 per employee and finds, on that basis, that a reduction of 11 FTEs will result in a $776,000 reduction. Accordingly, the Board directs EDI, in its refiling, to reduce its labor costs by $776, At Risk Compensation Views of the Applicant EDI provided a detailed explanation of its overall compensation program in section 2.4 of its Application, in its responses to PICA-EDI-64 and during oral testimony. 37 EDI stated that its structure for compensating its employees has three components: base compensation (including benefits), at risk compensation and incentive compensation. The base compensation and at risk compensation (collectively referred to as an employee s target total compensation ) are designed to bring employee total compensation to a level which is at par with comparable positions in the electrical utility industry and other similar sized companies in Alberta and Western Canada (i.e., market value). The base compensation component is equivalent to approximately 80% to 90% of an employee s target total compensation, depending on the employee s position and level within the Corporation. Employee target total compensation is factored into EDI s cost forecast. At risk compensation is paid to employees when EDI s annual targets and EUI s overall annual corporate targets are realized. EDI s forecast of at risk compensation for the 2004 Test Year was $0.5 million. The incentive component of employee compensation was designed to compensate for employee performance that meets or exceeds stretch objectives beyond annual targets. As a result, incentive compensation is funded from savings achieved through outstanding performance and, accordingly, is not included in EDI s cost forecast. Parties asked questions relating to the at-risk component of EDI s compensation program. In response, EDI s witnesses confirmed that the at-risk component is limited to management level employees and that its purpose is to bring their target total compensation to the median of salaries in the market. (Tr. pp ) The evidence shows that EDI s forecast of at-risk compensation for 2004 is consistent with 2001 to 2003 levels (PICA-EDI-64). EDI s witnesses provided a detailed explanation of how the at-risk component of employee compensation operates (e.g., Tr. pp ), including a breakdown of the at-risk compensation performance targets for 2004 (although the targets had yet to receive final Board of Director approval) (Exhibit ). The breakdown shows that 60% of at-risk compensation is tied to meeting performance targets that include such things as system reliability, customer satisfaction (which is now linked to the EUB s performance measures and standards), environmental stewardship and safety. 40% of at-risk compensation relates to meeting net income targets. The witnesses also provided details respecting the various targets and how they 37 Tr. pp ; Tr. pp ; Tr. pp ; Tr. pp ; Tr. pp ; Exhibits , 19, 24 and 33 EUB Decision (August 13, 2004) 35

42 are established (e.g. Tr. pp ; Tr. pp ; Tr. pp ), and confirmed that the performance targets are reviewed and approved by the Board of Directors annually. The UCA asked how customers benefit from 40% of the at-risk compensation component of employee salaries being tied to meeting net income targets. In response, Mr. Cowburn testified as follows (Tr. p. 1180): A. Mr. Cowburn: I m informed that the incentive pay is paid out when we reach 100 per cent of net income; i.e., the net income target allowed by the Board. So what happens, then, is that EPCOR management gets paid the median of market, if it reaches the target which is allowed by the Board. That seems to be a totally consistent package in that if the utility achieves the results that the Board has contemplated, then management gets paid the salaries which median of the industry would imply. If the company underachieves, then management gets paid less. But what the customer is seeing is essentially the framework that the Board has set out, and that seems to be a reasonable and prudent approach to compensating management. Q. The Chairman: So, Mr. Cowburn, if the company underachieves, then this money that s in the revenue requirement for the at-risk compensation, that still goes to the shareholders and the customers still pay that. A. Mr. Cowburn: Yes. Q. The Chairman: It s just that the management employees do not get that. A. Mr. Cowburn: Right. And so then the view that the customer is seeing is that he s paying, in effect, the median of the industry for the salary, and he s incenting employees through that to achieve the Board-allowed return on equity. And then the disposition inside the company depends on whether we achieve targets or not. EDI submitted that including 100% of its forecast at-risk compensation in its applied-for revenue requirement and tying 40% of that compensation to net income targets was reasonable and appropriate. Among other things, it ensures that employees are appropriately and reasonably incented to, at a minimum, control EDI s cost of providing service to the level approved by the Board, which is of benefit to customers because the Corporation s actual results for 2004 will eventually be used for comparison purposes in future GTAs. Further, at the end of the day, customers are paying no more than Board-approved, market salaries for the employees, irrespective of whether all or only a portion of the 40% of at-risk compensation that is related to net income is paid out. Mr. Grimes confirmed that during 2001 and 2002, 100% of at-risk compensation was paid out to employees (Tr. p. 1669). On this basis, EDI submitted that the evidence demonstrated that EDI s compensation program, including its forecast of at-risk compensation included in its revenue requirement, was reasonable and prudent and should be approved by the Board. 36 EUB Decision (August 13, 2004)

43 Views of the Interveners CG The CG submitted that EDI has not provided adequate justification for the At Risk compensation of its management employees. The CG submitted that the Board should disallow the Net Income component of the At Risk for EDI (i.e. 40% of total At Risk compensation) resulting in removal of $320,000 from EDI s revenue requirement. EDI s compensation for management includes three constituents: base compensation, at risk compensation and incentive compensation. In addition to base compensation, EDI requested $0.8 million of at risk compensation for 2004, which was split between $500,000 for EDI 38 and $296,000 as part of the pass-down costs from EUI. 39 EDI did not request in its revenue requirement, any amount for incentive compensation, the third constituent of management compensation. EDI s base and At Risk compensation are designed to compensate employees...to a level which is at par with comparable positions in the electrical utility industry and other similar sized companies in Alberta and Western Canada (i.e., market value). 40 EDI s At Risk compensation is only paid to management employees and was based on several factors including net income, safety, environment, reliability and customer service. 41 UCA questioned EDI on its At Risk compensation. 42 In response to an undertaking to split out the components of At Risk compensation amongst the various EDI 2004 performance targets, 43 EDI provided Exhibit , which showed that 40% of EDI s At Risk compensation was based on net income. The $296,000 of EDI s At Risk compensation passed down from EUI was also composed of a number of components, similar to those of EDI. 44 It also included other components such as operational excellence and reputation. 45 The CG submitted that, while EDI may believe its At Risk compensation allows its management employees to achieve compensation that is comparable to other companies, neither EDI nor EUI provided further documentation in the form of a market survey or independent special study to substantiate this claim. Further, Exhibit which shows the various EDI Performance Targets included in the At Risk compensation, has a note related to Net Income. This note states that the amount of net income included in the target (i.e. $14.8 million)...will be adjusted to reflect the net income ultimately approved by the Board. The CG noted cross-examination regarding the validity for EDI of the Board s ruling on the inclusion of incentive compensation for AltaLink s management employees in Decision The CG submitted the comparison is valid since the AltaLink disallowance was related to earnings. 47 The CG submitted that the incentive plan components referenced in the AltaLink case are the same as the At Risk compensation included in EDI s revenue requirement PICA-EDI-64(b) Schedule B-3, p. 18 Section 2.4, p. 9 of Application UCA-EDI-11(c) Tr. pp Tr. p Tr. p Exhibit Tr. pp Tr. pp EUB Decision (August 13, 2004) 37

44 The CG further submitted that at least the EDI related Net Income component of At Risk compensation, was a moving performance target that would only be known when the Board releases its Decision in mid to late The CG questioned how management would reasonably achieve any cost savings to meet their target Net Income at that point. Further, it was unclear to the CG how this determination of At Risk compensation after the fact will meld with the concept of paying management employees at market. The CG submitted that determination of the component of At Risk compensation related to EUI was equally unclear for similar reasons. In addition, the CG submitted that the operational excellence and reputation of an Affiliate of EDI is not of sufficient importance or benefit to the customers of EDI to include as a component of revenue requirement of EDI. The CG submitted that with respect to the Net Income component of At Risk compensation for EDI (i.e. 40% of total At Risk compensation), the Board should disallow this amount of compensation. On a base of $500,000, this amount is $200,000. With respect to the At Risk component of the EUI pass-down costs of $296,000, the CG submits it is likely that a similar percentage is used to compensate the management employees. The CG submitted that a similar percentage reduction should be used. Using the 40% reduction applied to $296,000, a further reduction of approximately $120,000 is appropriate. The CG submitted that the Board should reduce EDI s revenue requirement by $320,000 to reflect the removal of the Net Income component related to the At Risk compensation for management employees. In Reply CG submitted that focusing on Net Income related goals may create a perverse incentive since it may provide an incentive for the utility to take undesirable risks in terms of reliability and security of supply. Views of the Board While the Board notes that EDI attempted to shift the burden of proof to interveners by indicating that interveners have not provided evidence to suggest that EDI s management compensation is at appropriate levels, the Board agrees with CG that the onus of proof is on EDI to show that these levels and types of compensation are appropriate. In the Board s view, proprietary studies such as Towers Perrin market salary surveys and Watson Wyatt Canadian Salary surveys do not provide the testable evidence required to support EDI s prima face case that EDI s management compensation is at appropriate levels. The Board notes that AltaLink provided an independent testable study to substantiate the levels of management compensation that were requested. 48 However, CG only challenged the At Risk compensation of EDI s management employees. In that regard, the Board agrees with CG about the validity of comparing the Board s ruling on the inclusion of incentive compensation for AltaLink s management employees contained in Decision to EDI s. 49 The disallowance by the Board in that Decision due to a component of compensation that was based on the earnings of AltaLink is, in the Board s view, essentially the same as the disallowance proposed by the CG in this case, where a component of compensation is related to the net income of EDI and EUI See Decision Tr. pp EUB Decision (August 13, 2004)

45 As in the case of AltaLink, the Board considers that the expenses related to the portion of benefit gained by the shareholders should not be borne by the customers. In this case, the Net Income component would appear to be all to the benefit of shareholders. However, the Board recognizes that a portion of the net income gains may arise from cost reductions that would flow through to customers in subsequent GTAs. Therefore, the Board will require customers to fund only 50% of the Net Income component related to the At Risk compensation for management employees in this GTA. Accordingly, the Board directs EDI, in its refiling, to reduce its forecast revenue requirement by the amount of $160,000, which is 50% of the Net Income component related to the At Risk compensation for management employees. The Board also agrees with CG with respect to the need to record the amounts of incentive plans that are paid and the reasons the payments occur, to facilitate future proper justification of costs to be charged customers by future assessment of benefits that have the potential to flow through to customers. Accordingly, the Board directs EDI to provide a reconciliation clearly showing the amounts forecast to be paid out in 2004 and the actual amounts paid out in 2004, as part of its next GTA, by level of employee and including details of how the incentive compensation was calculated Pension Funding The Board notes that there was little specific information provided on EDI s pension funding and pension plan. Again the Board has some difficulty accepting, without this information, that there is sufficient evidence that EDI s employee compensation is necessarily at market levels. Accordingly, the Board has directed that EDI s pension benefits should form a part of the overall industry employee compensation studies that EDI files in its next GTA Vacant Position Allowance Views of the Applicant When parties asked questions on the topic of vacancy rates or vacant position allowances, EDI s witnesses indicated that EDI does not track specific position vacancies on an ongoing basis. With respect to hourly employees, which make up approximately 60% of EDI s labour costs, Mr. Byron confirmed the following: (Tr. pp ) A. Mr. Byron: Our labour budget is built up on the labour tasks that we budget for. So we budget for maintenance tasks, and out of that will fall, then, a labour dollar, and those labour dollars are then are then budgeted. We don t budget, then, for particular positions per se. Q. I see. So for the linemen and so on, it s just built up based on your man-hour requirement? A. Mr. Byron: That s correct. Q. So that would explain, then, why, for the hourly employees, there s no need to worry about vacancy rates, because you re actually just budgeting how many man-hours of EUB Decision (August 13, 2004) 39

46 labour you need, not how many people you need times a wage, times a one minus a vacancy rate? A. Mr. Byron: That s correct, sir. In an exchange with counsel for AE with respect to vacancy rates where the company is adding new salaried positions in 2004, Mr. Cowburn testified that (T6: ): A. Mr. Cowburn: The way we put together our salaries where we were adding new positions was to attempt to assess when in the year we thought we would bring the person on. If it was a half a year, we would have put a half a year of salaries in. So given that we believe we have already incorporated the vacancy and the specific positions involved, we feel we ve pretty fairly approximated what a vacancy rate would accomplish. If we were going to apply a vacancy rate, then we would have to restate the budget on a basis of 100 percent occupancy, and then take a vacancy rate off. So it would be a different forecast number than the one that we provided, if you were going to use a vacancy rate. There s obviously two different ways of getting to the same place. One is to assume 100 percent occupation and then take a vacancy rate. Another approach, which we think is reasonable, is to say. We ll forecast partial occupancy where we expect partial occupancy, and that will incorporate the result into the forecast. And they are different means of getting to a similar objective. Mr. Byron confirmed that the base level of salaried positions going into the year are assumed in EDI s budgeting process to be 100% filled throughout the year. (Tr. pp ) However, in Exhibit , EDI provided a detailed explanation of its labour and salary cost forecast process, explaining, among other things, that EDI s base level of personnel in any given year will never exceed the required level needed to address the collective work load between the capital and operating programs. EDI submitted that its budgeting process adequately addressed position vacancies and its 2004 cost forecast was reasonable insofar as it reflects labour costs. Further, that there was no need for the Board either to impose a vacancy rate on EDI in respect of any component of its labour costs, or to require EDI to begin tracking position vacancies. In reply EDI noted that the CG argued that EDI s forecast operating costs should be reduced to reflect a 5% vacancy rate in FTEs, since among other things, the CG asserts that there are unknown vacancies such as terminations, medical leave and special assignments that are not forecast. The CG asserted that 5% was appropriate as this was the most recent reflection of a vacancy rate used for a comparable utility (AE). AE argued that an appropriate vacancy rate would be the average of that approved by the Board for other utilities. EDI submitted that the detailed overview of the evidence provided in its Argument demonstrated that imposing a vacancy rate on EDI s applied-for operating costs was unnecessary and would be inappropriate based on the manner in which the costs associated with both EDI s hourly and management employees are budgeted (Tr. pp ; Tr. pp ). The evidence demonstrated that EDI effectively builds a vacancy rate into its labour forecast by budgeting for 40 EUB Decision (August 13, 2004)

47 specific tasks for hourly employees and by budgeting for known vacancies for its salaried employees. EDI submitted that the CG provided no substantiation for its assertion that unknown vacancies would occur and impact EDI s actuals. EDI submitted that since it budgets on work that needs to be done, the work will be done by some employee irrespective of whether an employee (or a nose ) happens to be terminated, ill or on special assignment. If the work is not done, then it will show up in EDI s actual financial and for operating results. EDI submitted that the CG s argument demonstrated that it misunderstands the difference between FTEs and noses in the context of EDI. EDI also submitted that no basis was provided for concluding that AE or other utilities were comparable to EDI. There was no evidence any other utility budgets in the same manner as EDI, and even the CG conceded that EDI does not use the concept of FTEs for budgeting and forecasting purposes in the same way that other utilities regulated by the Board do. Given these circumstances, EDI submitted that acceding to the CG s or AE s recommendations would be arbitrary and inappropriate. EDI also noted that the CG s calculation of a cost of $74,028 per FTE was inaccurate. EDI submitted that the amount should be $70,500, being the average salary of $60,000 noted in Exhibit (pg. 3) with a 17.5% fringe benefit allowance. The application of a 31.5% fringe benefit allowance to labour employees is not required as the average salary amount includes an adjustment for a 14% fringe differential for labour employees related to paid vacation and statutory holidays (Exhibit ). Views of the Interveners AE AE submitted that EDI admitted that its application did not include a vacant position allowance, but EDI suggested that no vacancy rate was required, as it had not budgeted based on 100% occupancy throughout the year, but rather had attempted to forecast salaries for positions on the basis of when they were to be added during the year. Nevertheless, EDI acknowledged that vacancy rates are used to adjust historic variances. (Tr. p. 1488) AE submitted that was expected that utilities would attempt to forecast the costs related to salaries as accurately as possible; however, the application of a vacancy rate was necessary to account for the fact that the forecast will almost certainly be different from the actual costs incurred. The fact that EDI forecast its salaried positions on an FTE basis does not in any way alter the fact that this forecast will likely vary from what actually occurs. AE submitted that, given the difficulty associated with testing EDI s forecasting for the years in which it was regulated by its sole owner, the Board should impose a vacancy rate equivalent to the average vacancy rates imposed on other EUB-regulated distribution utilities until EDI can demonstrate through experience that it reasonably requires a lower rate. In AE s view, there was little question that the vacancy rate would not be equal to zero; therefore, the assumption that EDI s employment positions will be fully staffed, as forecast was not reasonable In Decision , the Board directed ATCO to revise its vacancy rate forecast from 4% to 5% in each of 2003 and 2004 and to reduce its operating forecasts accordingly. EUB Decision (August 13, 2004) 41

48 AE agreed with the CG that EDI has not properly reflected the treatment of vacancy rates in its application. AE submitted that the application of a 5% rate per the CG to all employees, hourly and salaried, would be a step towards the goal of leveling the playing field among EUBregulated electric utilities. CG CG submitted that EDI did not properly reflect the treatment of vacancy rates and use 5% as this is the most recent reflection of a vacancy rate used for a comparable electric utility (AE). Applying this vacancy rate to the forecast net 330 FTEs in O&M results in a reduction of 16.5 FTEs. The 16.5 FTEs have average salaries and benefits of $74,028, resulting in a recommended reduction in EDI s O&M of $1.221 million for The CG further recommends that EDI be directed to commence tracking vacancy rates, planned and unplanned, commencing in the 2004 test year, for use in future GRAs. UCA examined EDI 51 on the vacancy allowance reflected in their FTE forecast. IPCAA-EDI- 8(g) requested the number of vacant positions reflected in the historical and forecast FTEs. The response stated that Vacant positions are not tracked on a historical or forecast basis. EDI stated during cross-examination that it was not meaningful to forecast vacancies in respect of FTEs because of the method of budgeting that EDI uses. 52 EDI also stated that it had no intention in the future of tracking vacancy rates as it applies to FTEs. 53 EDI indicated however, that it did not think that AE built up their forecast exactly the same way that EDI did their forecast. 54 The CG submitted that EDI did not indicate that the AE process was significantly different from that used by EDI to render a comparison of vacancy rates to FTEs invalid. Further discussion on the issue of vacancy rates was canvassed by AE counsel and by the Chairman. 55 An undertaking was provided to further explain EDI s budgeting process. 56 The CG submitted that, while the undertaking response provided some detail about the budgeting process, it did clear up the issue of the use of the vacancy rate. Further, additional issues arose. At page 3 of the undertaking, EDI stated that the concept that no vacancy factor was considered was...somewhat mitigated with some duplication or overlap of positions where known vacancies are anticipated (personnel will be hired to fill the position prior to it being vacated). Other methods to mitigate vacancies are to back fill with temporary employees or supplement with contracted resources such as consulting engineers. (emphasis added) The CG submitted that even if one accepted that EDI can perfectly forecast the workload and resulting FTEs required, including known vacancies, (and the CG did not accept that premise) there are also unknown vacancies such as terminations, medical leave and special assignments that are not being forecast. Backfilling by use of existing resources only moves the vacancy down the salary chain. A vacancy will result at some level Tr. pp Tr. pp Tr. p Tr. pp Tr. pp Exhibit EUB Decision (August 13, 2004)

49 Finally, in an exchange with Board staff, 57 EDI opined that there was no need to worry about vacancy rates for hourly employees because of the budgeting process. EDI, however, did confirm that for salaried employees who represent 42% of the labour force for EDI, 58 there was no vacancy rate assumed. 59 The CG submitted that the Board should worry about vacancy rates for hourly employees. The CG submitted that, while the work may be budgeted and the workforce requirements and number of FTEs derived from the number of hours, if salaried employees leave because of termination, medical leave or special assignment, a period of time elapses before the employees are replaced. The CG submitted that the time frame could be as short as several days to as long as several months, whereas the revenue requirement forecast assumes that all employees are present 100% of the time. Further, the cost savings associated with not immediately filling the vacated hourly or salaried employee position accrues to EDI s shareholder. Since EDI has no historical information on the turnover rate for hourly or salaried employees and thus the extent of this cost savings accruing to the shareholder is unknown to all parties. CG submitted that EDI has not shown it has properly reflected the treatment of vacancy rates. The CG submitted that EDI s forecast number of FTEs should be reduced by 5% as this was the most recent reflection of a vacancy rate used for a comparable electric utility (AE). Further, that, even if the Board does not agree with the submission that there should be vacancy rate applied to hourly employees, the same 5% rate should be applied to 42% of the forecast FTEs (i.e. salaried employees). The CG submitted that, while the number of FTEs forecast by EDI was an elusive number that changed several times over the course of the hearing, the final number of FTEs, net of transfers to Capital and Affiliates now appeared 330 FTEs as shown in revised Exhibit , Table 3. Applying the 5% vacancy rate to the 330 FTEs, the CG submitted that 16.5 FTEs should be removed from the net 330 FTEs requested. Based on the average salary of $60,000/FTE 60 and applying a loading factor for benefits of 31.5% for salaried employees and 17% for hourly employees 61 results in an average cost per FTE for salaried employees of $78,900 and $70,500 for hourly employees. Using the weighting of 42% for salaried employees and 58% for hourly employees 62 results in an average salary of $74,028/FTE. Applying the average FTE cost to the 16.5 FTEs, the CG submitted that the Board should reduce EDI s O&M by $1.221 million to reflect an appropriate vacancy allowance. Further, the CG submitted that the Board should direct EDI to commence tracking vacancy rates, planned and unplanned, on a going forward basis commencing with the 2004 test year, for use in future GRAs. In reply CG submitted that EDI s Argument does not refute any of CG s points made in its Argument. The CG reiterated its recommendation that the Board should adopt CG s recommended reduction of 16.5 FTEs to recognize a vacant position allowance for 2004 ($1.21 million) as noted at pp of CG s Argument. Alternatively, even if the Board accepts there s no need to worry about vacancy rates for hourly employees as EDI suggests, there is still 40% of EDI s labour costs that are not hourly employees (p. 26 EDI Argument). As noted at p. 20 of the CG Argument, the CG also submits the Board should also direct EDI to commence Tr. pp Exhibit Tr. pp Revised Exhibit , Table 2 Exhibit , Tr. pp Exhibit EUB Decision (August 13, 2004) 43

50 tracking vacancy rates, planned and unplanned, on a going forward basis commencing with the 2004 test year. This would be helpful and enable a comparison of vacancy rates amongst utilities. Views of the Board The Board agrees with the interveners that a revenue requirement forecast that assumes that all salaried employees are present 100% of the time is not reasonable. Under that assumption, the cost savings associated with not immediately filling a vacated employee position accrues to EDI s shareholder. Having reviewed EDI s approach to budgeting for hourly and salaried employees as set out in Exhibit , the Board considers that there would be little chance of a vacancy requirement for hourly employees. However, the Board considers that for salaried employees, unexpected vacancies may still arise due to terminations, medical leave and special assignments that are not forecast. The Board notes that EDI has not tracked historical vacancies. However, the Board would prefer to create a more uniform basis for accounting for vacancies for the utilities it regulates. The Board notes EPC s attempt to harmonize its labour forecasts to those of other utilities regulated by the Board by introducing a method that accounted for vacancies in The Board considers that EDI should attempt similar harmonization. Accordingly, the Board directs EDI to commence tracking vacancy rates, commencing in the 2004 test year, for use in future GTAs. In addition, the Board directs EDI to provide, in its refiling, the forecast level of hourly and salaried FTEs for 2004, reflecting the Board s findings in this Decision. For the purposes of this GTA, the Board can accept that EDI s budgeting process for salaried employees would likely lead to a lower vacancy rate than that of AE which is the 5% rate on the record in this proceeding. The Board considers that on balance, without a historical record, a vacancy rate of 2.5%, or one half that of AE, applied to 42% of the forecast FTEs would be fair to both customers and EDI and result in a reduction of EDI s labour forecast of 8.5 FTEs. However, the Board notes that, in another section of this Decision, it has applied an 11 FTE reduction due to EDI s history of over-forecasting its labour component. The Board considers that the effect of the historic vacancy rate being greater than 0 would form part or all of the historic FTE over-forecasts. Accordingly, the Board considers that no further reduction is necessary. 3.4 Executive Compensation Views of the Applicant In Reply EDI submitted that before the Board accedes to any request to direct EDI to provide further or additional information in its next DTA, the Board must satisfy itself that the information is relevant and material, that it would be of assistance to the Board and that the benefits to be gained by having the information provided outweigh the added time and cost burden associated with producing, assembling and/or providing the information. Further, EDI submitted that the Board should satisfy itself that the intervener has provided some basis in the evidence or persuasive argument, which demonstrates that there is a need for the information to be produced in the first place. 44 EUB Decision (August 13, 2004)

51 EDI submitted that neither the CG nor AE in the case of executive compensation had provided a basis in either the evidence or persuasive argument as to why this information is required. The CG states that it does not take issue with EDI s applied-for costs, and provides no basis for suggesting that the Board should have any concerns. Further, the reasonableness of its costs from affiliates (including executive costs from affiliates) was addressed, and will continue to be addressed, by way of the evidence EDI provides to demonstrate the reasonableness of its affiliate transactions (e.g., in this proceeding, the BearingPoint and Hemisphere Engineering reports), and the requested additional information was unnecessary as a result. Further, in the case of the FTE breakdown requested by the CG, as shown by CCA- 25-EDI Attachment, EDI s charges from affiliates are not calculated in a manner that would allow for a breakdown between union and management staff. EDI submitted that neither the CG nor AE has demonstrated any need for the recommended directions, much less that the requested information would be of assistance to the Board or that the costs associated with producing it would be worthwhile. EDI submitted that the Board should decline to make the requested directions. Views of the Interveners AE AE noted that the AE utilities were required to conduct a market-based assessment of the reasonableness of its executive compensation levels and submitted that in order to ensure that a level playing field exists, the Board should expressly direct EDI to conduct a similar assessment for AE submitted that there was no reasonable distinction that can be made between its utility business and EDI's that would justify AE being subjected to a separate executive compensation module involving detailed scrutiny of the related costs and EDI being permitted to file a general tariff application that did not even provide, as a separate amount, the compensation paid to its executive or Affiliate executive compensation paid as part of the Affiliate pass-down costs from EDI's Affiliates. As noted by the CG, EDI did not provide any support for amounts of executive costs claimed by it in its application. AE submitted that, in order to establish a level playing field, such arbitrary differences in treatment must be eliminated. If anything, AE expected EDI's costs to be subject to more scrutiny, given that this was EDI's first tariff application before the EUB and the fact that the only previous scrutiny of EDI's costs was that of its owner. AE agreed with the CG that the onus of proof is on EDI to show that these levels and types of compensation are appropriate. CG The CG submitted that EDI did not provide, as a separate amount, the compensation paid to its executives or Affiliate executive compensation paid as part of the Affiliate pass-down costs from EDI s Affiliates. EDI did not provide any support for amounts of executive costs claimed by it in EDI s application. While AE has recently undergone an executive compensation hearing on the reasonableness of its executive compensation, the CG did not consider at this time that a similar exercise was required for EDI. The CG submitted the Board should direct EDI in its next GTA to provide further substantiation of the executive compensation amounts requested for EDI and for EUB Decision (August 13, 2004) 45

52 executive compensation amounts included in costs passed down from EDI Affiliates to EDI and included in EDI s revenue requirement. This may include an independent analysis conducted to determine the reasonableness of the requested amount of executive compensation. Views of the Board The Board recognizes that for consistency between utilities, EDI should file an executive compensation study similar to that to be filed by ATCO in its next GTA, as directed by the Board in Decision However, in the case of EDI, the Board is not presently persuaded that the benefits derived from an executive compensation study would outweigh the costs of such a study. Accordingly, the Board will not direct that an executive compensation study be prepared at this time. The Board will review the need for an executive compensation study in EDI s next GTA, considering the estimated cost of such a study in relation to the expected benefits. Therefore, the Board directs EDI, at the time of its next GTA, to provide the estimated cost of preparing an executive compensation study, similar to that to be filed by ATCO in its next GTA. 3.5 Hearing Costs EDI has applied for implementation of a Hearing Cost Account (HCA). EDI provided a detailed breakdown and explanation of its $2 million forecast amount to be included in its HCA for 2004 (CCA-EDI-11). The $2 million of hearing costs (Schedule D-20) was made up of $1.3 million for intervener and $0.7 million for EDI costs. The amounts included were in accordance with the Board s cost recovery guidelines. EDI included $0.3 million in the operating expenses category of its revenue requirement for its 2004 EUB Cost Recovery Assessment. EDI based its forecast on discussions with EUB staff during the summer of Views of the Applicant EDI submitted that its hearing cost forecast and 2004 EUB Cost Recovery Assessment were reasonable and should be approved by the Board. EDI indicated that, while it had not applied to include amounts assessed for EUB cost recovery in the HCR account or any other deferral account, EDI would not object to such treatment. Views of the Interveners CG The CG submitted that the EUB assessment fees, forecast in the amount of $0.3 million for 2004, should be considered to be part of the hearing cost account as for other utilities. Views of the Board In Decision , the Board approved the establishment of a Hearing Cost Reserve (HCR) for EDI consistent with those established for other utilities the Board regulates. The Board considers it appropriate to approve an annual provision to the HCR sufficient to cover average annual charges to the reserve rather than trying to accurately forecast each year s hearing costs. 63 Decision , p EUB Decision (August 13, 2004)

53 The annual provision would form part of the revenue requirement and hence be funded from customer revenues each year. The annual provision can be adjusted from time to time as required to keep the average HCR balance as close to zero as possible, except when reflecting hearing costs that are to be recovered over multiple years. The forecast of the timing of each year s provision to, and Board approved payments from, the HCR will still have a small working capital impact due to its effect on the mid-year HCR balance. The Board directs EDI, in its refiling, to provide a schedule indicating the forecast opening and closing HRC balances using the provision and forecast of costs to be paid out of the HRC. EDI should provide a schedule in the same form for subsequent GTAs. The forecast midyear balance should be used in EDI s necessary working capital calculation. The Board agrees that its annual assessments pursuant to its General Assessment Orders under section 22 of the Public Utilities Board Act (EUB Assessment) should be included in the HCR since the level may not always be known in advance of EDI s filing. However, EDI has not been assessed an amount for 2004 in the Board s most recent General Assessment Order for the Fiscal Year , 64 meaning that EDI will not be assessed until sometime in In the Board s view, therefore, it is unnecessary to include in the HCR any amount for EUB Assessment for Further, the Board considers that EDI s forecast for 2004 EUB Assessment should be removed from operating expenses. The Board notes that the level of EDI s other costs for inclusion in the HCR were not questioned by any intervener and that the Board has approved a deferral account treatment for EDI s hearing costs in this Decision. The Board also notes that EDI s total hearing cost forecasts are lower than those approved for EPC ($2.7 million), for whom interveners undertook a more detailed examination. In the circumstances, other than the $0.3 million for EUB Assessment included as operating expenses in EDI s Application, the Board finds that EDI s forecast of hearing costs is not unreasonable and the Board approves a hearing cost provision of $2.0 million to be included in EDI s 2004 revenue requirement. Accordingly, the Board directs EDI in its refiling, to reduce operating expenses by $0.3 million and to include the approved provision of $2.0 million for the HCR. The Board directs EDI, in its next GTA, to include the forecast for EUB Assessment as part of the HCR. The Board also directs EDI, at its next GTA, to separately forecast its expected claims and expected recoveries from the hearing cost reserve accounts of other utilities and include as a separate line item in its revenue requirement. 3.6 Donations and Community Support EDI indicated that its DTA includes $273,000 for community investments and donations as part of EUI s affiliate charges to EDI relating to public and government relations. 64 AR 120/2004 EUB Decision (August 13, 2004) 47

54 Mr. Rowes testified as follows (Tr. p. 1374): a general observation would be that the community, from a historical point of view, has expected contributions from the major companies within the Edmonton service area and have benefited over the years from those types of donations. So in a general sense, it s something that basically has been a historical thing that has gone on in the City of Edmonton. In its Report entitled Affiliate Transaction Review Addendum (Exhibit ), BearingPoint stated the following with respect to such costs at pp. 5 and 6: Ratepayers make substantial requests for EPCOR s community involvement. EPCOR has chosen to address this through a corporate policy for community investment. EPCOR s policy is to invest one per cent of the average consolidated Business Unit net income for the current year and the prior two years back into the community. It should be noted that the current year net income needs to be estimated when calculating the three-year average as the current year is not over when the budget for this investment is prepared. The amount calculated is reinvested in the community to promote, among other things, youth and science education, health and well being, community life and employee volunteerism. EPCOR selects opportunities to make these investments when the investment is based in a community where EPCOR operates, is of prime importance to the community, meets a recognized community need, makes a significant and unique contribution to community life, benefits the greatest possible number of people and is of long term significance to the community. Based on information provided by EPCOR resources all Business Units, including EDI, are allocated a portion of these investment dollars based on their proportionate contribution to EPCOR s consolidated Business Unit net income. EDI s 2004 forecast net income as a percentage of EPCOR s consolidated 2004 forecast Business Unit net income is approximately 12%. Therefore EDI is allocated approximately 12% of the 2004 community investment pool, which is approximately $275,000. BearingPoint notes the dollar value a utility invests in the community is a matter of corporate choice. However, given EDI s size and importance in the community, BearingPoint considers an investment back into the community of one percent of EDI s prior three years average net income to be reasonable based on similar commitments among other Canadian corporations. Based on information provided by EPCOR resources this amount is approximately $250,000. Therefore, BearingPoint considers approximately $250,000 of EDI s allocated amount of community investment dollars to be reasonable based on the one percent formula, its general acceptance in the Canadian business community and the methodology by which EPCOR contributes these community investment dollars back into the community. The various types of organizations that were beneficiaries of EDI s donations and community support were shown in CCA-EDI-25. Views of the Applicant EDI submitted that its forecast costs for donations and community support were reasonable and justified on the basis that they generally benefit customers within EDI s service area by contributing to community life and generating significant economic benefits or spin-offs. EDI submitted that the costs should be approved for inclusion in EDI s revenue requirement. 48 EUB Decision (August 13, 2004)

55 Views of the Interveners AE AE noted that, in the past, AE had requested recovery of costs associated with corporate donations and had not been permitted to recover such costs. In Decision U97065, the Board held that it was inappropriate to include charitable or political donations in the revenue requirements of electric utilities and stated that they should remain a shareholders' expense. AE submitted that the Board should treat the EUB-regulated electric utilities in a consistent manner in this regard. There is no reasonable distinction between the business of AE and that of the municipal utility that would justify any different treatment in respect of such costs. AE requested that the Board treat all EUB-regulated utilities consistently in respect of the recoverability of donations and community support. CG The UCA examined EDI 65 on the amount and types of donations, sponsorships and community support costs that EDI proposed to include in its 2004 revenue requirement. EDI agreed that the amount shown in IPCAA-EDI-2(b) of $272,312 represented the amount requested by EDI in this application for donations, sponsorships and community support. This amount was part of the allocated charges from its parent EPCOR. 66 The CG did not disagree that these types of costs are a part of doing business in the community. The CG submitted that these costs should not be included in EDI s 2004 utility revenue requirement and paid for by EDI s customers in their rates. This is based on the consideration that the Board has previously disallowed charitable or political donations as part of a utility revenue requirement. 67 Most recently in Decision at p. 104 the Board wrote: The Board is not persuaded, however, that it is appropriate to include community related sponsorships in the allowed revenue requirement. The Board considers that such sponsorships are not necessary or appropriate for the provision of DRT or RRT services. (ii) these types of costs may not be what all customers want or desire to pay as part of their customer rates; 68 and (iii) customers have not given express nor even implied approval to include these costs in the customer rates of EDI, 69 On that basis the CG submitted that the amount of $273,312 should be excluded from EDI s 2004 revenue requirement. Further, while there is no evidence there are donations and community support costs included in the direct EDI costs (as opposed to corporate passdown costs from EPCOR), the CG submitted that EDI should also be directed to separate out and exclude direct donations and community support costs in its next GTA filing Tr. pp IPCAA-EDI-2(b) Tr. pp ; Decisions , p.98 and Decision U97065 CCA-EDI-25(h)(iii) Exhibit EUB Decision (August 13, 2004) 49

56 The CG noted that these types of costs might not be what all customers want or desire to pay as part of EDI s rates. Customers have not given specific or implied approval to include these costs in their rates. Further, EDI should be directed to exclude direct donation and community support costs in their next GTA filing. In reply CG submitted that EDI s argument tends to rely on comments from the BearingPoint report to suggest it is appropriate to include donations and community support costs in EDI s revenue requirement. The CG submitted BearingPoint s comments were only in relation to whether EPCOR as a corporate organization, not EDI as a regulated utility, should contribute to the community. BearingPoint did not take into consideration or address past Board decisions that have disallowed donations and community sponsorship or whether in a generic sense, it was appropriate for utility customers to pay for donations and community sponsorship (without even benefiting from applicable tax deductions). The CG submitted the BearingPoint comments were argued out of context and had no bearing on whether utility customers should be forced to pay these costs. EDI also references the various agencies that EPCOR, not EDI, supported in The CG submitted that an examination of the various agencies clearly bears on the point that these types of costs may not be what all customers want or desire to pay as part of their customer rates. Many of the agencies listed (i.e. United Way, Edmonton International Street Performers Festival, Salvation Army, Edmonton Oilers, Citadel Theatre, Edmonton Eskimo Football Club, Canadian Finals Rodeo, K-Days Chuckwagon Derby, and the Odyssium) may be supported either through individual separate donations or even attendance by EDI s customers. Customers may view an additional charge on their utility bill to support these agencies as a form of double charging and may choose to reduce or eliminate their support for the agencies. A separate line item on the customer bill for each sponsorship donation would certainly invite customer feedback. Other agencies may provide services that are never used by some customers (i.e. University of Alberta, BOMA, AUMA, NAIT). Finally, some of the agencies might provide support or services (i.e. United Way) to organizations that customers do not believe in for religious (i.e. Catholic Social Services) or moral (Planned Parenthood) reasons. The CG submitted that these customers should not be forced to contribute to something they do not believe in. Views of the Board As the Board has recently held in Decision and previously in Decision U97065, the Board considers that neither sponsorships nor donations (charitable or political) should be included in a utility s revenue requirement. The Board recognizes that ratepayers may not desire to support the same organizations that utility management or shareholders would support. Therefore, Board considers it inappropriate for ratepayers to bear such costs and considers that all donations or sponsorships should remain as a shareholder expense. As AE suggests, this approach has been consistently applied by the Board to the utilities it regulates for a number of years. Accordingly, the Board directs EDI, in its refiling, to remove the $273,312 total of sponsorships and charitable donations from its 2004 revenue requirement. Further, while there is no evidence that there are donations and community support costs included in the direct EDI costs (as opposed to corporate pass-down costs from EUI), the 50 EUB Decision (August 13, 2004)

57 Board directs, in its next GTA, to separate out and exclude direct donations and community support costs. 3.7 Corporate Affiliate Transactions Views of the Applicant EDI submitted that EDI has structured its business operations to reasonably and prudently take advantage of economies of scale and scope through the appropriate use of affiliate transactions for the benefit of customers (e.g., Tr. p ). In section 2.5 and the various parts of Appendix B to EDI s Application, EDI provided a detailed description of its affiliate transactions, demonstrating that its costs and revenues associated with those transactions have been fairly and efficiently set through well-established, rational and reasonable cost allocation methodologies that reflect such principles as cost causation and the level of benefit provided and received. EDI s material affiliate transactions are subject to inter-corporate service agreements among the affiliates involved (included as Appendix B-2 to EDI s Application) and meet the applicable requirements of the EUB Code of Conduct recently approved for the EPCOR Group (EDI Application, section 2.6). BearingPoint LP provided three reports relating to EDI s affiliate transactions, all of which were included in Appendix B-7 to EDI s Application (see Exhibit and Appendix F). BearingPoint conducted a thorough and extensive review of 28 affiliate transactions having a total annual value of $14.9 million representing approximately 80% of the total affiliate transactions. EDI s witnesses confirmed that EDI chose the transactions to be assessed, based on the materiality of the transaction in terms of dollars, and the time constraints EDI had in preparing its first DT Application to the Board (Tr. p ). Mr. Peterson elaborated on BearingPoint s approach and work in conducting its review during his testimony (Tr. p , (relating specifically to human resources costs)) Mr. Peterson also stated that BearingPoint personnel were not limited in terms of who within the EPCOR group they could speak with in completing their review, and confirmed that BearingPoint interviewed senior and mid-level personnel from EDI, EUI, ETI and EPCOR Technologies (Tr. p ). BearingPoint concluded that EDI s 2004 costs and revenues associated with the transactions reviewed were fair and reasonable, were based on sound and rational allocation methodologies, were stable over time, were supportable and, where applicable, were reasonable in light of the cost to EDI of obtaining those services in the market or the cost of procuring those services internally on a stand-alone basis, and were consistent with appropriate transfer pricing principles. Mr. Peterson also testified that based on his review, the allocation drivers and the process used to determine EDI s affiliate costs were very good (Tr. p. 2113). Hemisphere Engineering Inc. provided a market assessment of the charges relating to maintenance and engineering services provided by EDI to other members of the EPCOR group and by EPCOR Transmission Inc. (ETI) to EDI (Appendix B-8 to EDI s Application). Mr. Mantai elaborated on Hemisphere s approach commencing at (Tr. p. 1991). Between the BearingPoint reports and the Hemisphere market assessment, a total of $9.7 million, or approximately 80 % of the affiliate transactions reflected in EDI s Application were assessed for reasonableness (Appendix B-1 to EDI s Application). EUB Decision (August 13, 2004) 51

58 Extensive additional information was provided in EDI s evidence, including: Summaries and detailed breakdowns of total costs and revenues associated with affiliate transactions involving EDI for the period 2001 through 2004, along with detailed explanations of significant changes year over year. A summary of allocations of corporate services costs from EUI to regulated and unregulated affiliates (BR-EDI-10, 11). Additional details respecting the allocation methodologies used to determine affiliate transaction costs (CCA-EDI-25, 29, Exhibits , 76, 77, 90, 91). Additional detailed breakdowns and reconciliations of affiliate costs and revenues (CCA- EDI-20, 25, UCA-EDI-25, Exhibits , 78, 83, 84, 85; Tr. pp ). EDI s witnesses (both its Main and Affiliate Transactions Panels) were asked a number of questions in cross-examination respecting EDI s affiliate transactions. EDI submitted that its witnesses responses were cogent and compelling, and thoroughly addressed each issue or concern raised. EDI summarized EDI s responses regarding the areas that were canvassed by parties during the Hearing. In response to questions respecting the process used to determine the level of corporate charges that would be allocated to EDI, Mr. Rowes testified (Tr. p ): Q. When you see charges being allocated from EUI to EDI that include an FTE increase from the equivalent of 41 to 58, had those transfers not taken place again, my quick arithmetic was that s over a 40 percent increase in the allocation from EUI do you negotiate this on behalf of EDI s customers? How does this process work? Do you just accept that? A. Mr. Rowes: In terms of corporate charges, we meet as business unit heads, and we meet with the corporate executive, and we review the corporate allocations and charges and, in fact, the services that are being provided from corporate. In addition to that, each of the each of the corporate areas, they all arrive and land in my office and go over their budget with me, the services they are providing, and they show me what the costs are and any changes going up or down or whatever. And so I have the opportunity to review it with each of the EUI senior management people of that area. For example, the head of IT would come to my office and say, Here s my budget. And they d go over it with me, look at what our allocations are and what we re getting for the service. Later, in the transcript, Mr. Rowes added (Tr. p. 2111): Q. So is there a kind of a group meeting of all the of EUI and all of the parties to which all of the subsidiaries that they provide services to and they say, Okay, here s our here s our budget for 2004, and this is what you re going to get, and is there sort of a discussion on whether somebody s getting too much and somebody s getting too little? 52 EUB Decision (August 13, 2004)

59 A. Mr. Rowes: Yes, sir. There s a fairly heated discussion that goes on that every year. As a business unit, I want the costs lowered as much as possible, and we have major discussion with the senior executive in the company and all the heads who are providing these particular services. In addition to that, the heads of these particular areas come and see me with their laid-out budget and what their services are, and we discuss whether I feel I m getting value and that type of thing. Mr. Rowes stated that if he could demonstrate that he could procure services in a more economical manner, the independence would be available to him to procure the services in that manner. (Tr. p. 2110) A number of cross examiners asked questions relating to whether, based on the Board s decision respecting EDI s DTA, EDI could go back to the counterparties and have the inter-corporate service agreements changed to reflect any Board disallowances of affiliate costs. EDI s witnesses stated that such changes could not be made (e.g., Tr. pp ; , ). In this context, cross examiners pointed out that revisions had been made to EDI s inter-corporate services agreement with EUI to correct two errors that had been made in that agreement, appearing to question the validity of the agreement on that basis. EDI s witnesses responded that it was fair and reasonable to make changes to the agreement where obvious errors had occurred, but that it would not be fair or reasonable to expect that revisions could be made to change what had actually been agreed to between the parties. EDI considered this approach to be consistent with the law of contract in Alberta. EDI submitted that the record demonstrates that the costs associated with EDI s affiliate transactions in 2004 are consistent, reasonable, and prudent, and should be approved by the Board. In reply, EDI submitted that it was important to note that neither the CG nor AE challenged the prudence of the manner in which EDI has chosen to procure the various services necessary to enable it to carry out its functions and obligations as an owner of an electric distribution system. That is, neither party challenged EDI s position (confirmed by the BearingPoint reports in respect of the services reviewed by BearingPoint) that the affiliate transactions reflected in its Application are required to enable EDI to carry out its various functions and obligations. Finally, while AE commented on the BearingPoint reports, it did not comment on, and did not express any concern with, the evidence of Hemisphere Engineering. The CG expressed essentially one concern with the evidence Hemisphere Engineering, which was addressed in EDI s Final Argument. EDI submitted that comments were, in substance, directed at the reasonableness of the costs associated with EDI s affiliate transactions. While AE did not make any specific recommendations as to the levels of EDI s affiliate costs, the CG argued that the Board should order a general and arbitrary reduction of $0.85 million to EDI s applied-for affiliate costs. EDI noted that both AE and the CG took issue with the approach EDI used to demonstrate that the forecast costs associated with its affiliate transactions were reasonable. EDI submitted that when the claims of AE and the CG are examined in light of both the evidentiary record and logic, they do not withstand scrutiny. EUB Decision (August 13, 2004) 53

60 AE claimed that EDI should have provided an assessment of the reasonableness of the cost pools from which costs were allocated to EDI: (AE Argument, p. 5) ATCO submits that the reasonableness of the costs must be assessed prior to the allocation, otherwise it will be difficult to determine whether an allocated cost is unreasonable as a result of the allocation methodology or the original cost charged. The CG asserts that EDI does not undertake any testing of the 2004 forecast amounts of EUI costs, and claims that: there is or at least should be a fair expectation that any independent expert would at least make some comment or pass judgment on whether the costs emanating from EUI are truly disciplined in some fashion. There is a fair expectation that BP would make enquiries about the EUI forecasts to ensure that the numbers the parent company is asking its subsidiaries (sic) are reasonable in the first instance. EDI noted that much of the CG s final argument respecting affiliate transactions is simply a repetition of this assertion. EDI submitted that, contrary to the assertions of AE and the CG, the approach EDI took to demonstrating the reasonableness of its affiliate transactions was entirely reasonable and appropriate. EDI submitted that there was no reasonable basis for arguing that the Board either needs to, or should, embark on an examination of the cost pools from which EDI is allocated costs for the purpose of determining whether the costs being allocated to EDI for any particular service are reasonable. To begin with, it was made abundantly clear in the BearingPoint reports that they were provided, in part, to demonstrate that the allocation methodologies used by the EPCOR group were sound and rational, consistent with past cost allocation practices previously approved by the Board, and stable and supportable. This aspect of BearingPoint s work was undertaken to provide the Board with comfort that the allocation methodologies being used within the EPCOR group are reasonable and appropriate and are consistent with the determination of affiliate costs on a cost recovery basis as that term is used in the EPCOR Affiliate Relationships Code of Conduct. The other main aspect of the BearingPoint reports (as well as the report provided by Hemisphere Engineering) was to provide an assessment demonstrating that the costs relating to each affiliate transaction analyzed were reasonable. To provide this assessment, BearingPoint first conducted interviews with EPCOR personnel to ensure that BearingPoint had a detailed understanding of the specific services, which make up each affiliate transaction that involves EDI. The depth of understanding that BearingPoint had of the services was shown by the descriptions provided for each affiliate transaction in its report. For its part, Hemisphere Engineering was provided with detailed descriptions of the specific tasks that had to be performed and the forecast volumes of those tasks (Application, Appendix B-8 of Main Filing). Each consultant then performed an analysis for the purpose of determining whether the allocated costs associated with the services were reasonable. For example, BearingPoint used its own extensive experience and professional judgment, as well as certain third party (Appendix A to Appendices B-7 of EDI s Application) and internal benchmarks (Tr. p. 2035, Appendix B-7, p. 4 section 3.1.3) to assess the reasonableness of the costs on the basis of what it would cost, for 54 EUB Decision (August 13, 2004)

61 example, EDI to procure the services internally by hiring its own staff to provide the services and/or to procure the services from a third-party service provider in the marketplace, where that alternative would be reasonably possible. Hemisphere Engineering provided an assessment of the range of market rates that would be applicable to the types and volumes of tasks reflected in EDI s affiliate transactions (Application, Appendix B-8). EDI submitted that this approach to demonstrating the reasonableness of its affiliate transaction costs was both logical and reliable. Further, that it obviated the need for the Board to embark on what would in all likelihood be a lengthy and costly process of analyzing the reasonableness of cost pools. In addition, EDI noted that the vast majority of the businesses carried on by the EPCOR group of corporations are not subject to financial regulatory oversight by the Board. As shown in the corporate organization chart filed during the proceeding (Exhibit ), only 4 of the 18 subsidiaries of EUI are subject to financial regulation by the Board. Consequently, embarking on a path of examining EUI s corporate cost pools, for example, would in all likelihood require that the Board also analyze the operating requirements of numerous businesses that it does not regulate. EDI noted that the Board has, in the past, resisted the urging of some parties to assess the operations and costs of businesses that it does not regulate. EDI submitted that the Board should act consistently with that approach in the present circumstances, particularly since there is ample reliable evidence on the record with respect to the reasonableness of EDI s affiliate transactions costs. EDI submitted that it is also important to note that both AE and the CG neglect to address clear evidence on the record which demonstrates the substantial discipline which is present, for example, with respect to corporate costs. In this regard, Mr. Rowes testified to the rigour that is applied during the corporate budgeting and allocation process (see pp. 33 and 34 of EDI s Final Argument). Further, in response to questions from AE s counsel, Mr. Cowburn testified as follows: (Tr. pp ) Q. Yes. I m going back to the base cost and saying, Is the base cost I mean, I m asking whether or not you would agree with me that there are two steps here. One is you go back and look at the costs you re being you re allocating, and second is you look at the allocation procedure. And I didn t see the first step there being addressed. You ve addressed the second step, which is the allocation down. A. Mr. Cowburn: Right. So the first criteria is, of course that the costs have some relation to the services that are actually being provided. The end result of the reasonableness of those costs is then tested, but the process, to my knowledge, doesn t include a specific assessment of all of the costs and all the organizations that are driving in. Rather, as the document [i.e., Appendix B-3 to EDI s Application] lays out, it s first assessed whether these costs are allocable, assignable, and so on. But there is no specific step identified in here that says we look at the total pool of costs and assess its reasonableness. Rather, the method points out that at the end, when all is said and done, we check and see that the results themselves are reasonable. If they didn t pass that criteria, we d have to loop around and say, All right, well, there s something wrong here. Maybe we ve EUB Decision (August 13, 2004) 55

62 mischaracterized the services; maybe we ve got too high a cost pool; maybe they re just not relevant to the business. But it would be an iterative test in which the confirmation of reasonableness, as it s stated here, is the final step. Q. Okay. So your approach is to have a cost that s an allocable cost, and you come up with an appropriate allocator to say X percent should go to EDI, and then once you get that percent, you take a look at the end result and say, Is that reasonable for the service? A. Mr. Cowburn: Correct. And if it fails, it goes back through the loop; if it passes that reasonableness test, it goes forward. EDI submitted that, coupled with the fact that EDI s allocation methodologies are sound and rational, are consistent with past cost allocation practices previously approved by the Board, and are stable and supportable, the EPCOR group s rigorous approach to budgeting and allocating costs provides additional compelling evidence as to the reasonableness of EDI s affiliate costs. EDI submitted that given these circumstances, there was no need to ask BearingPoint to review cost pools prior to their allocation among EPCOR affiliates to demonstrate the reasonableness and prudence of EDI s affiliate transaction costs. Contrary to the assertions of the CG, it was also not necessary for BearingPoint to have a detailed understanding of the various functions or businesses of EUI or of other EUI subsidiaries to make that assessment. The central issue is whether the costs to EDI are reasonable and, to make that assessment, BearingPoint required (and obtained) a detailed understanding of the specific services being provided to or by, as the case may be, EDI. EDI submitted that its approach was logical and clearly demonstrates the reasonableness of its affiliate transaction costs. EDI noted that AE argued further that a determination of the reasonableness of cost pools was necessary to effectively prevent cross-subsidization of unregulated utilities by regulated utilities. EDI submitted that this argument was clearly without merit. Taking EUI corporate costs as an example, it is clear that if the cost allocation methodologies are reasonable and appropriate (as demonstrated in this case by BearingPoint s review and the methodologies consistency with previous Board decisions), then there can be no concern over cross-subsidization. This is because the appropriate allocation methodologies ensure that each subsidiary bears its fair share of the cost pool being allocated, which by definition precludes the possibility of cross subsidization. AE also appeared to argue that EDI should have conducted a benchmarking study, asserting that some of the transactions analyzed by BearingPoint (specifically the Human Resources category of costs) were simply justified on the basis that there existed economies of scale and scope as a result of engaging in the affiliate transactions. EDI indicated that it was not aware that the Board has determined that the only approach that a utility can take to demonstrating the reasonableness of its affiliate transaction costs is to commission benchmarking studies. Based on Mr. Peterson s testimony at (Tr. pp ), it is clear that such a study would entail significant additional effort and cost, and EDI submitted that it would provide no meaningful benefit. EDI submitted that, while such studies may be useful to the Board in certain contexts, the approach taken by BearingPoint is eminently reasonable and entirely appropriate for the purposes of this proceeding. In this regard, 56 EUB Decision (August 13, 2004)

63 Mr. Peterson confirmed that, where appropriate, BearingPoint referred to external and internal benchmarks. (Tr. pp ) EDI submitted that, although AE seeks to discredit the validity of the external benchmarks referenced by BearingPoint, the sources are both independent and reputable (e.g., KPMG LLP, Wyatt Watson Worldwide, Canadian Lawyers Magazine and the EUB s guidelines). EDI submitted that AE s attempt to characterize certain transactions as having been simply justified by BearingPoint does not comport with the record in EDI s view. As explained in detail in the BearingPoint reports, BearingPoint looked at a number of criteria in assessing the reasonableness of the costs associated with EDI s affiliate transactions (including such factors as whether the ratepayer receives a benefit from the transaction, consistent with the Board s findings in Decisions , p. 83 and , p. 45; see section of BearingPoint s September 26, 2003 Report, Appendix B-7 to EDI s Application). With respect to the Human Resources services specifically, Mr. Peterson described BearingPoint s analysis in more detail in his discussion on the record with AE s counsel (Tr. pp ) and further with Board staff.(tr. pp ) Mr. Peterson also indicated that other analyses were performed by BearingPoint (and were included in its working papers for each transaction) for the purposes of confirming its conclusions stated in its reports with respect to the reasonableness of EDI s affiliate costs. The BearingPoint reports provided independent and compelling evidence that the costs associated with EDI s affiliate transactions are reasonable and prudent. The CG makes the very serious, yet completely unfounded, accusation that BearingPoint was somehow not independent in performing its analysis and preparing its reports (CG Argument, section 2.4(i) to (iii)). In making this assertion, the CG tries to characterize BearingPoint as being related to KPMG LLP. EDI submitted that there was no basis for the CG s assertions. EDI submitted that the fact that the CG would even attempt to spin such unsupported accusations should lead the Board to seriously question the quality and credibility of the CG s submissions in Final Argument. The facts are these. It is a matter of public record that in conjunction with an initial public offering on February 8, 2001 (two years before BearingPoint was retained to provide expert evidence in this proceeding), KPMG Consulting, Inc. was formed as a separate and independent entity from KPMG LLP. The name of KPMG Consulting, Inc. was subsequently changed to BearingPoint, Inc. Counsel for the CCA indicated on the record that he had reviewed one or more websites respecting KPMG/BearingPoint (Tr. p. 1905), and EDI notes that this information has been on BearingPoint s website at all times that are material to this proceeding (see under Investors tab, SEC Filings). Specifically, the website states after the closing of this offering we [KPMG Consulting, Inc.] will not be a member of KPMG International, the worldwide association of independent professional services firms which share the KPMG name. Further, in addition to the fact that BearingPoint is independent from KPMG LLP, KPMG LLP is the external auditor of EUI (Tr. p. 1901), a fact that the CG neglects to point out. As such, KPMG LLP is independent of EUI and EDI in accordance with the strict accounting rules that are applicable to external auditors. EUB Decision (August 13, 2004) 57

64 It is clear that the fact that BearingPoint was at one time in its history related to KPMG LLP and the fact that KPMG LLP is the external auditor of EUI are completely irrelevant to BearingPoint s independence, and the CG s attempt to mischaracterize the facts and assert otherwise should be entirely rejected. The CG also attempted to point to BearingPoint s reliance on a 2002 KPMG LLP report and the Watson Wyatt Worldwide 34th Canadian Salary Survey (2002/2003) as evidence of a lack of independence. EDI submitted that it is important to note that the CG does not take any issue with the content of these reports per se, it simply attempts to rely on the identity of the firms that prepared the reports as an indication of a lack of independence on BearingPoint s part. For the reasons cited above, the CG s assertions are without any rational basis and should be rejected. As BearingPoint is independent of KPMG LLP, there can be no argument that BearingPoint s reliance on either report somehow tainted BearingPoint s independence. To the contrary, it demonstrates that BearingPoint was willing to rely on independent benchmark information prepared by well-known and well-accepted sources for the purposes of conducting its analysis. Views of the Interveners AE AE submitted that while EDI suggested that it was not requesting the Board's approval of its proforma affiliate agreements, the Board should be satisfied that the pro-forma addresses matters of concern that arise from such agreements. Otherwise, the Board could be taken to have implicitly approved the agreements. Furthermore, the fact that this was EDI s first appearance before the Board should not prevent the Board from applying the same standards to EDI in terms of its affiliate transactions as applied to the ATCO Group. AE noted that EDI acknowledged that the reports submitted by BearingPoint and Hemisphere, plus the cross-examination, which occurred during the proceedings, constituted the totality of the justification, put before the Board to support its affiliate transactions. 70 AE submitted that the BearingPoint review is inadequate for the purposes it was intended to serve, i.e., to evaluate and justify EPCOR s affiliate transactions. The BearingPoint consultant admitted that BearingPoint s review was not a benchmarking study and that BearingPoint would have required a far greater understanding of the EPCOR operations in order to perform a proper benchmarking. AE submitted that, several of the transactions BearingPoint evaluated, such as the Corporate Personnel, Human Resources category, were simply justified on the basis that there existed economies of scale as a result of engaging in the affiliate transactions. While BearingPoint indicated that it had a full set of working papers that outlined the information that it had relied upon, the source of that information, and the sort of analysis performed, none of this information was filed with the Board and BearingPoint admitted that it had outlined in its report the most compelling reasons for its conclusions. 71 In respect of the costs associated with executive charges to EDI, BearingPoint referenced sources of comparative data. However, BearingPoint admitted that it had not done an assessment or 70 Tr. p Tr. pp EUB Decision (August 13, 2004)

65 examination of the comparator group discussed in these reports; nor had BearingPoint examined the peer group and job descriptions used in these reports to ensure that they were valid. 72 AE submitted that it was noteworthy that EDI admitted that it operated on the expectation that when it obtains corporate services, economies of scale and scope will exist and that it was possible that EDI may be receiving services at greater than fair market value. (Tr. p. 1930) With respect to the allocation methodology employed by EDI, AE was concerned that, in EDI s submissions and throughout the proceedings, EDI only assessed the allocation and not the reasonableness of the associated costs. AE submitted that, while Mr. Cowburn attempted to explain at pages 2015 to 2017 of the transcript a somewhat nebulous, post-allocation reasonableness test, the reasonableness of the costs must be assessed prior to the allocation, otherwise it will be difficult to determine whether an allocated cost is unreasonable as a result of the allocation methodology or the original cost charged. Such a determination is necessary to effectively prevent cross-subsidization of the unregulated utilities by regulated utilities. AE submitted that the justification for EDI s affiliate transactions paled in comparison to that which the Board has demanded of other utilities. Further, that, if the Board does not require EDI to remedy its affiliate transaction analysis in the context of the 2004 DT application, gaps in the review of EDI s affiliate transactions should be addressed in its 2005 application. In reply AE questioned EDI claims that it has provided a detailed description of its affiliate transactions, demonstrating that its costs and revenues associated with those transactions have been fairly and efficiently set through well-established, rational and reasonable cost allocation methodologies that reflect such principles as cost causation and the level of benefit provided and received. AE s submitted that EDI had not met the requisite standard. The CG referenced the standard that was applied to AE in the affiliate proceedings. There is little question that the EUB has previously expressed substantial concern about maintaining the transparency of affiliate transactions and that EDI would have been aware of this concern well before its application was filed. AE submitted that notwithstanding the significant emphasis the EUB has placed on affiliate transactions and code of conduct issues, EDI provided little in the way of justification of the charges between EDI and various EDI affiliates. While, as noted by the CG, BearingPoint was to assess the reasonableness of the costs of the related services, this assessment was extremely limited; relying in large part on the assumption that economies of scope and scale would always exist among affiliates and provide a sufficient justification for the transaction. AE submitted that, while EDI noted that the transactions that BearingPoint assessed were chosen based on the materiality in terms of dollars and the time constraints EDI had, no such materiality threshold was accepted during the analysis of AE s affiliate transactions and that the issue of time constraints has rarely, if ever, been accepted as justification for failing to provide adequate evidence to demonstrate that the claimed costs are just and reasonable, prudent and in the public interest. AE submitted that, unless the Board is reconsidering the level of scrutiny to be applied to affiliate transactions of all regulated utilities in Alberta, the level of justification EDI has 72 Tr. pp EUB Decision (August 13, 2004) 59

66 provided in relation to its affiliate transactions is unacceptable in a regulatory environment aimed at establishing and maintaining a level playing field. CG The CG noted that EDI proposed approval of an amount slightly in excess of $17 million 73 for the total costs or charges associated with Inter-Corporate Services or what has often been termed affiliate transactions. The CG submitted that the evidence that EDI put forward to support the reasonableness of the costs was not sufficient to support the costs as claimed and proposed that the Board order a general reduction of $0.85 million to the amounts forecast by EDI. EDI s affiliate transactions are documented in the many Service Level Agreements between EDI and various EPCOR companies (appendices B-2-1 to B-2-9). The CG submitted that these set out the mechanics of the relationships and provide little in the way of justification of the charges under the agreements. EDI attempts to justify and support the amounts charged under the affiliate transactions with the BearingPoint reports Appendix B-7 and Appendix B-7 addendum 1 and 2. The BP reports are therefore an integral part of the case of the applicant. BP provided the following as its objectives: in October 2003, BearingPoint was retained by Fraser Milner Casgrain LLP on behalf of EDI, in June 2003, to review certain transactions between EDI and its affiliates. Specifically, BearingPoint was retained to review certain of EDI s affiliate transactions, which involved the allocation of costs between EDI, EPCOR Utilities Inc. ( EUI or the Corporate Services Group ) and/or other regulated and unregulated affiliates in order to: Determine whether cost allocation methodologies between EDI and EUI, and EDI and other affiliates are generally consistent with the cost allocation methodologies approved by the AEUB in Decision U99099 and other pertinent AEUB decisions. Assess the reasonableness of the cost of the related services. 74 Based on the work done, BP found it was satisfied with the methods used to allocate costs and the reasonableness of such costs: Methodology To Allocate Costs for the transactions assessed, BearingPoint determined the methodologies used to allocate costs to be generally consistent with the cost allocation methodologies approved by the AEUB in Decision U99099 and other pertinent AEUB decisions. Reasonableness of the Costs Allocated BearingPoint determined that the costs associated with the transactions assessed, between EDI and EUI, are reasonable based on the analysis completed, our experience, knowledge, the chosen methodologies and the services provided. Furthermore, BearingPoint determined that the charges associated with the transactions assessed, between EDI and EDI s regulated affiliates, specifically ETI and EWSI, are reasonable based on the analysis completed, our experience, knowledge, the chosen methodologies and the services provided Response CCA-EDI-16 (Revised) Exhibit , Appendix B-7, p EUB Decision (August 13, 2004)

67 Finally, BearingPoint determined that the charges associated with the transactions assessed, between EDI and EDI s unregulated affiliate, are reasonable based on the analysis completed, our experience, knowledge, the chosen methodologies and the services provided. 75 The CG had a number of concerns about the level and nature of the intercorporate costs and the review undertaken by experts hired by EDI: BearingPoint was KPMG consulting 76 and KPMG is the auditor of EUI; 77 BearingPoint s reliance on two reports, one 2002 KPMG Comparing costs in North America, Europe and Japan and Watson Wyatt Worldwide 34 th Canadian Salary Survey 2002 / 2003; 78 Limited testing of any EUI numbers and understanding of function of EUI; Limited understanding of function of EDI affiliates; Uncertainty around the scope of the work of BP and what information was verified by BP as opposed to what was taken at face value; and No valid explanation for retainer by counsel as opposed to EDI. BP was KPMG consulting and KPMG is the auditor of EUI The CG suggested the independence of the Bearing Point (BP) reports could be questioned since it was not disclosed in the report that BP was the consulting arm of KPMG and KPMG is the auditor of EUI. BP s reliance on two reports The CG noted BP s reliance on two reports, one 2002 KPMG Comparing costs in North America, Europe and Japan and Watson Wyatt Worldwide 34 th Canadian Salary Survey 2002 / The CG submitted that using the resources of KPMG or of companies that are relying on the intellectual capital of KPMG seriously eroded the independence of the BP reports. In the CG s view there is or at least should be a fair expectation that information relied upon in utility hearings will have a measure of independence from the utility or its auditor and this was not the case here. Limited testing of any EUI forecast and understanding of the function of EUI The CG submitted that EDI did not undertake any testing of the 2004 forecast amounts of EUI costs. These costs are essentially frozen as noted in response to the Chairman: Q. Now, on the intercorporate agreements -- and you can just, again, look at that BR-11 just for an illustration -- are the amounts that are shown there that you get charged by EUI, are they frozen? In other words, no matter what happens in 2004, that's what you're going to get charged? A. MR. ROWES: My understanding is that that's the charges that we will incur Exhibit , Appendix 7, p. 4-5 Tr. p lines 6-10 Tr. p lines 7-16 Tr. p line 3 to 1907 line 17 Tr. p EUB Decision (August 13, 2004) 61

68 However, if EUI wanted to charge another activity to EDI, it would be able to do so and that is part of the business risks that EDI faces. 80 The CG also submitted that it would appear that if one or more activities forecast by EUI did not occur, EDI would still have to pay since the forecast is essentially frozen. But if the Board decided to reduce a portion of the inter-corporate costs, EDI would still have to pay the disallowed costs to EUI. 81 This appeared to be a one-way street with the only beneficiary being EUI. The CG also submitted that there is or at least should be a fair expectation that any independent expert retained would at least make some comment or pass judgment whether the costs emanating from EUI are disciplined in some fashion. While acknowledging that there is no regulatory review of EUI costs, the BP witness only offers some vague explanation as to the basis for his reliance on the EUI 2004 forecast costs: Q. And so what is it that disciplines the costs at the EUI level? A. MR. PETERSON: The governance; the policies and procedures; the way the organization is set up. 82 The CG submitted that the governance, policies, procedures and the way EUI is set up does not, in and of itself, render the 2004 EUI forecast reasonable. Further, while these policies and procedures were touted as indicative of the discipline that ensures that the EUI forecast costs are reasonable, or prudent, response to questioning made it patently clear that the expert had made no such review. 83 The CG submitted that, it was one thing to assess if the costs are allocated properly but another matter entirely to assess if the costs are themselves prudent or reasonable and that a comprehensive assessment to verify if the costs are themselves prudent or reasonable is required. The BP witness is candid stating any review of the prudence of costs at the EUI level was not part of my scope. The BP expert also appeared to have little or no familiarity with the nature of the business on whose costs he was asked to make an assessment. 84 In order to assess if the costs are themselves prudent or reasonable one would expect some detailed knowledge of what functions are performed by the parent corporation. Limited understanding of function of EDI affiliates As with the nature of the business of the parent company EUI, the BP expert appeared to have very little familiarity with some of the EDI affiliates, particularly the unregulated affiliates. 85 The CG submitted that, in order to assess if the costs allocated among affiliated companies are prudent or reasonable one would expect a certain level of knowledge about the affiliates Tr. p Tr. p Tr. p Tr. p Tr. p Tr. p EUB Decision (August 13, 2004)

69 Uncertainty around the scope of the work of BP and what information was verified by BP as opposed to what was taken at face value The CG submitted that in order to assess if the costs allocated among affiliated companies are prudent or reasonable one would expect a certain level of independent verification of amounts allocated. BP s focus was not really centered on determining the reasonableness of specific intercompany charges. 86 The CG submitted that affiliate transactions by their very nature raise the suspicions of interveners and regulators. The interrelationship between the regulated businesses of a utility is of general concern, but the extension to the unregulated businesses of an affiliate or parent is of significant concern. The CG submitted that this is applicable to revenue requirement costs or charges as well as revenue offsets earned by EDI. As the EUB pointed out in the ATCO affiliates proceeding: Board Findings The Board observes that there is a legitimate concern of parties with respect to the potential to adjust or otherwise manipulate allocated amounts between divisions, functions, and other regulated entities, particularly when non-aligned test years, negotiated settlements, and other jurisdictions are involved. The Board needs to ensure that safeguards and tracking measures are in place in order to monitor all relationships and transactions to confirm appropriate transparency of allocations among the respective regulated utilities. The Board believes that utilities should be prepared to justify all revenues and expenses included in their revenue requirement and ultimately in their rates, regardless where they originate or how they occur. 87 Generally the BP reports were premised on the retainer to review affiliate transactions, which involved the allocation of cost between EDI and EUI. 88 The CG submitted that the BP reports come up short, in the detailed assessment of the reasonableness of the costs associated with the transactions assessed. There was little, if any, evidence in the BP reports to support the reasonableness of the costs. Further, the BP reports do not provide the requisite transparency to the transactions. On that basis the CG submitted that EDI had not justified all of the revenues and expenses that it proposed to include in its revenue requirement. The CG submitted that EDI would have to do more in the future. There is evidence in these proceedings that the experts retained by EDI were not required to comment on the reasonableness or prudence of these costs. If EDI continues to utilize the services of its unregulated parent or affiliates, it will have to find a way to fully substantiate and prove the reasonableness or prudence of the costs it incurs since the quantum of costs or charges from EUI are not disciplined or governed by EUB regulatory oversight. The CG submitted that if the EUI costs had been vetted in a regulatory process similar to this proceeding there is little doubt the 2004 EUI forecast costs would have seen some level of reduction and that a global adjustment to these costs is in order. The CG submitted that, to determine an adjustment, it was reasonable to review the adjustments approved by the Board in recent rate cases. The CG selected adjustments approved by the Board with respect to the most recent ETI TFO rate application for the test years 2003 and At page 3 of that Tr. p Decision , p. 87 Appendix B-7 Executive Summary EUB Decision (August 13, 2004) 63

70 Decision the Board identified that there was a reduction of $3.12 million in 2003 and $3.11 million in 2004, both in reference to the applied-for amounts. In the absence of more specific evidence, these reductions amount to a reduction of 8.85% in 2003 ($3.12/35.24 million) and 8.70% in 2004 ($3.11/$35.66 million). These reductions provide a reasonable yardstick of the adjustments that should be applied to the EUI 2004 forecast costs. On that basis the CG recommended that the EUI costs in the amount of $9.748 million, provided in Exhibit , Appendix B-2-7, should be reduced by $0.85 million 89 in In reply CG stated that EDI relied on the BearingPoint conclusion that the costs are fair and reasonable. The CG submitted that it is up to the Board to decide what is fair and reasonable. The CG submitted that, while EDI argued it cannot go back to the counterparties and have intercorporate service agreements changed to reflect any disallowance s of affiliate costs, EDI s argument should not be accepted by the EUB for several reasons: First, a regulated utility should not enter into contracts where the costs are expected to be included in its revenue requirement over which the regulator has authority, without the explicit caveat that the contract is subject to regulatory approval. Second, the counterparties to these affiliate transactions are non-arms length parties and are fully aware that EDI and its revenue requirement is regulated by the EUB. Third, to accept the logic of EDI would bind the hands of the regulator in all instances where contracts are finalized by acceptance between regulated entities and affiliates. This is inappropriate, improper and cannot be what EDI realistically expects. The CG submitted that, even if EDI s argument were accepted as advanced, the EUB could still adjust or change the amount of affiliate costs borne by customers by disallowing recovery in the EDI revenue requirement. This would result in a denial of certain amounts in EDI s revenue requirement deemed inappropriate for recovery through EDI under the inter-corporate service agreements. In so doing, only the regulated entity EDI bears the risk of not recovering costs it has incurred. The CG submitted that, an inability of EDI to reopen contracts, has potentially undesirable consequences. Any non-recovery of costs at the EDI level with a corresponding full recovery for an affiliate may jeopardize the EDI operations (safety, reliability or service levels) and hence harm its customers. The CG submitted that since these contracts and consequent costs are not between arms length unregulated corporations, they should be subject to the unique treatment of allowing for reopening after regulatory review. The CG also recommended a $424,000 reduction in the IT O&M allocation from EUI to EDI in 2004 to reflect the consistent application of the principle that direct IT O&M comprised of shared services should be allocated directly based on usage. IT indirect O&M, including disaster recovery and management and oversight, should be allocated as part of the corporate IT pool. The CG submitted that one of the major components of support services is comprised of allocated costs to EDI from EUI. The EUI allocation to EDI includes O&M charges for IT services as follows (in millions of dollars): 89 $9.748 million times ( ) 64 EUB Decision (August 13, 2004)

71 Table 8. EUI Allocation to EDI 2001 Actual 2002 Actual 2003 Re-Forecast 2004 Forecast Shared services, Management and oversight, disaster recovery support Corporate application support Total IT O&M Allocation EUI to EDI Source: PICA-EDI-66 Attachment For 2004 EDI proposes to change the method of allocation of IT expense. As a result of this change, EUI s IT expenses that are considered directly related to EDI are directly allocated to EDI and are included in the $1.851 million shown above. Those IT expenses considered part of corporate application support are initially allocated to a corporate application support pool and this pool is then reallocated to EDI and other EUI affiliates based on a corporate services allocator. CCA-EDI-25 Attachment sets out the proposed allocations: Table 9. EDI Allocation of IT Expense Direct Recovery Distribution Estimates 2004 Total Amounts Estimates Corporate IS Estimates Shared Services $1,419,601 $2,058,924 $9,301,693 Disaster Recovery 135,547 86, ,120 Corporate IS 1,321,922 1,321,922 Direct Recovery Total $1,851,224 $3,896,978 $13,259,723 Indirect Allocation % Average before Incentive, Space Rental and Facility Operations (with capital allocation) 12.15% EDI Allocation of Corporate 473,483 The above table shows shared services are allocated directly to EDI based on usage. A portion of disaster recovery and management & oversight are also proposed to be allocated to EDI as direct costs. The CG disagreed with the allocation of any portion of disaster recovery and management and oversight as direct costs to distribution. The CG submitted that, while shared services, a category that includes equipment such as desktops and associated servers, is appropriately allocated directly to distribution based on usage, disaster recovery and management and oversight are not of the nature directly allocable costs. 90 Rather, these are general costs, that should be included entirely in the corporate IS pool and then reallocated. The CG submitted that EDI was not being consistent in the application of the proposed allocation method. The CG s submitted that only those costs directly attributable to EDI based on usage should be allocated directly. All other costs including disaster recovery and management & oversight should be included entirely in the corporate pool and then reallocated. In other words the $135,547 for disaster recovery and $296,076 for management and oversight shown in the above table should be included in the corporate IS pool of costs and then reallocated. 90 Ref Exhibit for list of shared services EUB Decision (August 13, 2004) 65

72 On that basis, the CG recommended the IT O&M allocation to EDI for 2004 be revised as noted below: Table 10. CG Recommended IT O&M Allocation Amount ($000) Percent EDI Share ($000) Direct 9, % 1,419 Corporate: Disaster recovery 696 Management Oversight 1,940 Corporate IS 1,322 Corporate sub total 3, % 481 Total 13,260 1,900 Views of the Board Considerable argument was devoted to the issue of the appropriate method of determining just and reasonable costs for services provided by EUI to EDI. In the Board s view, its approach to corporate service cost allocation should be consistent with its approach in Decision respecting ATCO Group Affiliate Transactions and Decision respecting ATCO Executive Compensation (which stemmed from Decision ). The Board has dealt with executive compensation elsewhere in this Decision. The Board agrees with the CG that the allocation method and assessment of the quantum of allocated costs are two essential but different processes. The Board notes that the BP Study carried out a review of 28 affiliate transactions having a total annual value of $14.9 million. The transactions assessed were based on the materiality of the transaction in terms of dollars. The Board notes that BP not only examined the allocation method but also provided market testing and independent verification of the allocated amounts as being fair or reasonable. Given the evidence of the BP Study, the Board is satisfied that the level of corporate costs being allocated to EDI from EUI for 2004 is reasonable. 3.8 Other Affiliate Transactions BP reviewed a number of EDI s other affiliate transactions, which were included in the three BP Reports. Hemisphere Engineering Inc. provided a market assessment of the charges relating to maintenance and engineering services provided by EDI to other members of the EPCOR group and by ETI to EDI (Appendix B-8 to EDI s Application). Views of the Applicant The Hemisphere assessment demonstrates that the inter-corporate charges associated with these services reflected in EDI s Application are reasonable (see Appendix B-9 to EDI s Application). Mr. Mantai stated the following during cross-examination: Q. Now, if you take the midpoint of the Hemisphere Engineering hourly billing rate that is the last column in Table 5, the rates for ETI and EDI appear higher than average for all of the categories but one. 66 EUB Decision (August 13, 2004)

73 who could provide the comment on why Hemisphere Engineering would consider the EDI or ETI rates to be reasonable if they are consistently higher than the Hemisphere Engineering averages. A. Mr. Byron: Perhaps I can comment first. They are shown to be reasonable within the range that was provided by Hemisphere. And we feel that as long as we re within that range, there s reasonableness in the numbers we have provided, or were using for our calculations. A. Mr. Mantai: One of the things that might be part of the equation is that we have identified the range there in terms of what the industry would charge for those services. You need to keep in mind that that range is more functional, more based on the amount of man-hours that would be involved in a specific job. So if you, as an industry, if a client came to use and said We have a job that requires 4,000 hours for you, they re going to be at the bottom end of the range. If they turn around and say they have a job that requires 50 hours, then the chargeout rate is going to be at the upper end of the range. And I think without getting into detail, one of the one of the issues here is that EDI is providing engineering support, and their staff are involved in a lot a lot of projects which are minimal amount of hours. So on a purely cost-competitive basis, you need to look at the upper end of the range, based on the fact that they re doing very small, very small tasks in terms of specific tasks that require a small amount of man-hours. 91 Mr. Mantai so testified that what he saw through conducting the Hemisphere assessment was that EDI s approach to the processes relating to the tasks and activities reviewed by Hemisphere was consistent with those of other major utility players. 92 Based on BearingPoint s review of EDI and his previous experience on an analogous assignment where unregulated and regulated businesses were being operated by a corporate group under code of conduct provisions, the only improvement that Mr. Peterson suggested could be made to EDI s approach to affiliate costs was better record keeping of time spent by staff in providing affiliate services (with the exception of EUI personnel who already maintain such records). (Tr. p ) Views of the Interveners The CG submitted the following comments respecting the Hemisphere Engineering Incorporated (HEI) reports. EDI attempted to support the requested amounts for Maintenance and Engineering Rates with the HEI reports Appendix B-8 Maintenance and Engineering Rates Review Update. The CCA counsel questioned the EDI and HEI representatives. The CG submitted that neither interveners nor the Board should be satisfied with the response 93 that equates the full time efforts Tr. p Tr. pp Tr. pp EUB Decision (August 13, 2004) 67

74 of the EDI staff to procurement of the same services on a piece by piece basis in the market. Clearly any economies of scope and scale gained by having a full time fully staffed engineering department could be explained away in a similar fashion. This is of concern to interveners as the comparison must be more reasonable, that is comparison ought to be made to the cost of FTEs in the market, not piece by piece contracts. Views of the Board The Board notes that Mr. Peterson, of BP, suggested EDI could implement a better system of record keeping of time spent by staff in providing affiliate services. The Board directs EDI to implement a better system of recording time spent on affiliate transactions using time sheets or more frequent time estimates and report on the progress in its next GTA. In the Board s view, its approach to corporate service cost allocation should be consistent with its approach in Decision respecting ATCO Group Affiliate Transactions. The Board notes that EDI provided a summary of its other affiliate transactions in Exhibit (revised). The Board has reviewed these affiliate transactions considering the principles set out in Decision respecting ATCO Group Affiliate Transactions. On that basis the Board accepts them as reasonable for the purposes of this Decision and for the purposes of determining EDI s 2004 revenue requirement. 3.9 Affiliate Code of Conduct In Decision , the Board considered that it would be appropriate for EPC to file with the Board, for information, a copy of EPC s filings with the MSA under the Code of Conduct Regulation. The Board considers that it would also be appropriate for EDI to make similar filings with the Board. Accordingly, the Board directs EDI, in its refiling, to provide a copy of all filings with the MSA under the Code of Conduct Regulation to date in 2004 and to provide a copy of all future Code of Conduct filings with the MSA on a going forward basis Benchmarking and Uniform System of Accounts Views of the Applicant In Reply EDI noted IPCAA s submission that the Board should direct owners of electric distribution systems respecting the development of a uniform system of accounts similar to that made by the Board in the context of TFOs in Decision EDI had a twofold comment respecting this request. Firstly, the Board and interested parties do not currently have sufficient information upon which to determine whether the benefits to be achieved through the adoption of a uniform system of accounts will significantly outweigh the associated implementation and maintenance costs. As all parties will agree, there are in all likelihood substantial differences among owners in Alberta in terms of the systems of accounts they currently use. These differences could be far more extensive in nature than those reflected among TFOs. EDI submitted that if the Board believes there may be merit in moving to a uniform system of accounts for owners of electric distribution systems, the Board should first convene an appropriate process (whether through a working 68 EUB Decision (August 13, 2004)

75 group approach or some other approach) to gather sufficient information to determine whether it is in the public interest to do so. Secondly, EDI believes that there may also be merit in the Board allowing the work on the TFO side to progress further before actively taking steps on the distribution side. EDI is of the view that the results of efforts on the TFO side may provide helpful assistance on the distribution side, ultimately leading to a more efficient transition process. Views of the Interveners IPCAA IPCAA indicated that in most rate cases, the Board is assisted in evaluating utility forecasts by the provision of actual results for a number of prior years. However, in recent cases, the filing of actual results has arguably been of lesser utility due to changes in industry structure, company structure, or new financial systems. IPCAA submitted that additional assistance in evaluating utility forecasts could come from the comparison of similar utilities or the comparison of similar functions within other utilities. For example, the Canadian Electricity Association (the CEA ) tabulates benchmarking information from various utilities by function: transmission, distribution, corporate and customer service. EPCOR refers in its application to benchmarking of its operations, stating: 94 EDI carries out its distribution operations responsibilities in a manner consistent with sound industry practices and procedures. EDI s practices are assessed and improved on an ongoing basis having regard for: Customer requirements; Industry-wide reliability performance measurements; Industry best practices and benchmarks; Changes in specific reliability measures such as worst performing circuits, specific material failure rates, specifically identified reliability issues, etc.; Industry-wide safety performance indices; and Environmental requirements. Although EPCOR references industry best practices and benchmarks, EPCOR did not elect to present any of these practices or benchmarks in this proceeding. Knowing that ENMAX was a participant in the CEA COPE program, IPCAA inquired of EPCOR as to whether they participated in the program. EPCOR responded: 95 EDI does not participate in the CEA COPE process because EDI believes it has focused on the key areas critical for measuring operating performance. These can be found, with recent results for EDI, in EDI s response to AE-EDI-003. AE-EDI-003 focuses, as EPCOR indicated, on operating performance specifically outage statistics. AE-EDI-003 does not focus on costs or efficiency of operational performance. IPCAA submits that the use of appropriate benchmarks of both operating and corporate costs would be Exhibit p. 18, underlining added Exhibit , IPCAA-EDI-035 EUB Decision (August 13, 2004) 69

76 helpful to interveners, the Board and applicant utilities in establishing whether applied for costs are just and reasonable. ENMAX attempted to benchmark itself against Ontario municipal electric utilities (MEUs) however, in order to do so, ENMAX found the need to make certain adjustments to compensate for the differing definitions of distribution service in Ontario versus Alberta. In addition, ENMAX found the need to restate its costs in a manner that was comparable to the Ontario MEUs. Importantly, none of the financial results of the Ontario MEUs had to be restated to be comparable to each other, as all Ontario MEUs are required to report on the basis of the Ontario Energy Board Uniform System of Accounts. Now that both EPCOR and ENMAX DFOs will be subject to Board regulation, there is a unique opportunity to implement reporting procedures that would facilitate benchmarking of operations and/or specific functions between these two utilities and between these two and other DFOs. Given the similarity between EPCOR and ENMAX, it is only logical that they should, to some extent, be benchmarked against each other. The following measures highlight how similar the two are. The following table compares EPCOR and ENMAX Distribution only: 96 Table 11. Benchmarking of EDI and EPC EDI EPC Overhead Line (km) 2,415 2,370 Underground Line (km) 3,567 4,040 Total Line (km) 5,982 6,410 Percent OH/UG 40%/60% 37%/63% Number of Customers 295, ,070 While the physical similarity of the two entities can be compared in this manner, the financial similarities (or disparities) between the two utilities defy comparison. A cursory review shows that while, at a high level, the direct operating costs and the wholesale services costs of EPCOR and ENMAX may be broadly comparable, the discrete methods employed by EPCOR and ENMAX in defining and reporting corporate costs foreclose any effective opportunity to compare the two. For example, most of EPCOR s corporate costs are included under Support Services. Support Services are defined as follows: 97 Support Services costs, which are comprised of the cost of services such as finance, information systems, human resources, regulatory and legal to support the above three areas. ENMAX, on the other hand includes human resources and legal together, finance together with supply management, and IT is separate. Further, ENMAX proposes to capitalize a significant portion of its operating costs ($10.3 million), including a significant level of overhead costs. EPCOR, on the other hand, has proposed to capitalize $2.8 million of overhead Sources EPCOR km of line: Ex IPCAA-EDI-4 b) and d); EPCOR (no of customers); Exhibit Schedule DAS-11; ENMAX (km of line); Exhibit p. 12; ENMAX (no of customers); Exhibit Schedule (number of sites) Exhibit Supporting Material, p. 17 Exhibit EUB Decision (August 13, 2004)

77 In the end result, IPCAA was of the view that the Board was faced with two companies who should logically be compared against each other and no effective means to make the comparison. What would be useful, and, indeed, what is essential to a comparison of EPCOR and ENMAX, and to a comparison of all DFOs in Alberta, is a uniform set of accounts for DFOs. In the context of Alberta TFOs, the Board stated in the recent AltaLink decision: 99 The Board believes that some process efficiency could be realized if applicants were to use a uniform system of accounts such as those used by the OEB and FERC for their filings. In the Board s view, the improved ability to compare information from year to year and across utilities that would result from the adoption and use of a uniform system of accounts would be an asset to all parties including the applicant when testing the reasonableness of the utilities filings and budgets. Accordingly, the Board directs AltaLink to collabourate with the other TFOs for the purposes of forming a small working group consisting of TFO and stakeholder representatives to determine what would be required to develop and implement a TFO uniform system of accounts that could be used for regulatory filings. By December 31, 2003, AltaLink and the other TFOs should file an initial report with the Board on the results of study group s efforts in this regard setting out how this matter can be progressed. IPCAA submitted that a similar need exists and that a similar direction should be made in the present Application. Therefore, IPCAA requested that a direction similar to that made by the Board in Decision should be made by the Board to DFOs to permit the Board and parties to similarly test the reasonableness of the DFOs filings and budgets. CG The CG agreed that reporting procedures should be implemented to facilitate comparability amongst DFOs. The CG supported IPCAA s recommendation that a uniform system of accounts needs to be implemented to facilitate this comparability. The CG recommended that a uniform system of accounts for DFOs be developed and implemented as soon as reasonably practicable and preferably prior to the next GTA. EPCOR IG EPCOR IG stated that the most important issue associated with the reduction of costs was the underlying accounting structure. EPCOR IG stated that in the United States, basically all energy utilities followed the Uniform System of Accounts as promulgated by the Federal Energy Regulatory Commission (FERC), but in Alberta, each utility seemed to have its own accounting system. EPCOR IG stated that such a situation added unnecessary complexity to the monitoring, review and analysis of a utility s request. While conversion to a consistent uniform system of accounts for all utilities in Alberta will be more costly in the short run, EPCOR IG submitted that in the long run, it would result in lower costs and better regulation. Views of the Board The Board considers that it might be reasonable to assess the usefulness of implementing a DISCO uniform system of accounts at some point in the future, but at this time concludes that 99 Decision , p. 137 EUB Decision (August 13, 2004) 71

78 this proceeding is not the best forum to evaluate that matter. There are many characteristics of the various DISCOs in Alberta which the Board considers will require a more fulsome process. In light of the ongoing process involving TFOs initiated by the Board in Decision and Decision , the Board will provide further direction to all stakeholders in due course. However, the Board considers that there may be value in benchmarking studies that compare EDI and EPC, since the two utilities are both large, urban electric distribution systems under the Board s jurisdiction. The Board considers that there is work that EDI and EPC can do to harmonize their methods of presenting their respective revenue requirements in a manner that would facilitate benchmarking studies. Accordingly the Board directs EDI to initiate and collaborate with EPC to work on approaches that would allow reasonable and appropriate benchmarking studies and to include a high level benchmarking study with the types of benchmarking data included in Exhibit at the time of the next GTA. 4 REVENUE OFFSETS 4.1 Water Meter Reading Services provided to EWSI The water meter reading service provided to Edmonton Water Services Inc. (EWSI) by EDI includes activities associated with meter reading. Approximately two meter reading supervisors, one route planner, four field office clerks and approximately 42 permanent employees conduct activities associated with monthly or bi-monthly reads of electric and water meters according to EDI s meter reading schedule. This service includes meter readers physically walking to residential and commercial locations and reading meters. The allocation of all meter-reading costs (payroll and non-payroll) from EDI to EWSI is based on the proportionate number of electric and water meters. For 2004, EDI estimated the number of electric meters to be approximately 286,000 and the number of water meters to be approximately 207,000, which results in proportions of approximately 58% and 42% respectively. These percentages were based on the total count of electric and water meters taken on June 1, The forecast transaction charge from EDI to EWSI was approximately $2,118,000, which was based on a charge of $2,050,000 plus 3.4% due to inflation. Of this total cost approximately $45,000 related to a direct allocation to EWSI for the costs associated with services provided specifically for EWSI. The balance of this charge, approximately $2,005,000, related to the allocation of costs associated with the meter reading function. BearingPoint reviewed the transaction from EDI to EWSI and commented as follows: Objective Based on BearingPoint s review, there is no indication that the process of developing the proportionate water meter counts methodology, and the use of the allocation driver, results in an un-objective allocation amount Reasonable price Within their service territory, EDI is required to read the electric meters of their ratepayers. EDI ratepayers must bear the fixed costs associated with completing this task regardless of any sharing arrangement with an affiliate. In this case, EDI has agreed to have their meter readers complete water meter reads as part of the electric meter reads 72 EUB Decision (August 13, 2004)

79 already being completed. As a result EDI and EWSI create economies of scale in the execution of the meter reading function. EWSI pays for the costs associated with the provision of this service based on the proportionate number of meters. EDI s incremental costs are covered and they receive a contribution toward their fixed costs. Based on information provided by EPCOR resources the total number of meters is 493,000. EDI requires 286,000 meters (58% of the total meters) and EWSI requires 207,000 meters (42% of the total meters). EPCOR resources indicate the total pool of allocable meter reading costs is approximately $3,641,000. EWSI receives the benefit of approximately 42% of the meter reads completed therefore they receive 42% of the costs ($3,641,000 x 42% = approximately $1,530,000). EDI applies a 46% overhead factor to the direct labour portion of this allocation amount in an effort to recover the overhead costs associated with the provision of the meter reading function. Approximately 68% of this allocated cost relates to direct labour costs. Therefore EWSI is approximately charged an additional $475,000 (($1,530,000 x 68%)) x 46% = approximately $475,000). As a result the total allocated charge to EWSI is approximately $2,005,000. A direct charge to EWSI associated with the cost of services provided specifically to EWSI must be added to this figure to arrive at the total forecast charge of approximately $2,050,000. Currently, EWSI is allocated the efforts of approximately 21 EDI FTEs (49 employees x 42% = 21 FTEs). EDI s current allocation methodology allows for an average fully loaded salary of approximately $49,000 for these 21 employees (($1,530,000 x 68%)/21 FTEs). In our opinion it is reasonable to consider EWSI, on a stand-alone basis, would pay similar average salary amounts for meter reading personnel. Notwithstanding this sharing arrangement with EWSI, BearingPoint considers EDI would need to incur substantially similar costs to perform this meter reading function. As a result of this sharing arrangement EDI receives payment for any incremental costs associated with providing EWSI this service as well a contribution towards fixed costs that would otherwise be borne by the rate payer. Therefore, BearingPoint has determined the charge to EWSI for this service is reasonable based on the services provided, the chosen allocation methodology, and the total cost to EDI for the provision of the meter reading function. The benefits, associated with EDI providing meter reading services to EWSI and charging the Business Unit for a portion of the costs for activities EDI is already engaged in benefits the ratepayer through reduced operational costs. The electric meter reader is already engaged in reading meters at residential and commercial locations therefore the additional time required to locate and read the water meter is insignificant compared with the additional benefits associated with a reduction in costs. The costs allocated to EWSI represent the average cost of reading a meter and not the incremental cost of reading a water meter. 100 EDI indicated that the main forecast cost increases in the site, metering, settlement and tariff services area related to increases in the forecast number of off-cycle meter reads, increased meter field activity, and changes in the inter-corporate service agreement with EWSI. As was noted in EDI s Errata Letter (Exhibit , p. 2), the increased costs of off-cycle meter readings are offset by a revenue offset. EDI noted that increases in meter field activity are expected as EDI returns to tasks deferred during the intense construction activities of the past few years. Changes in the inter-corporate service agreement with EWSI are described in Appendix B-2-3 of EDI s Application. 100 Appendix B-7, pp EUB Decision (August 13, 2004) 73

80 Views of the Applicant EDI submitted that these charges are based on an analysis of costs actually incurred, and represent a fair sharing of the costs of meter reading with EWSI, to the benefit of EDI s electric service customers. EDI submitted that their justification is explained in the BearingPoint report. In reply, EDI noted that the CG claimed that EDI s forecast reduction in relation to revenue offsets from meter reading services provided to EWSI should be denied with the result that EDI s forecast should be increased by $0.5 million. EDI submitted that, while the CG asserted that the change in the applicable allocation methodology for these costs is not supported by the evidence, the change in meter reading costing methodology is based on an analysis of costs actually incurred, and represents a fair and rational sharing of the costs of meter reading with EWSI, to the benefit of EDI s electric service customers EDI submitted that the CG mischaracterized the evidence by stating that it would have assumed that the change in method would have affected the revenues or cost-recovery from all types of meter reads rather than selectively from one source [i.e., high density] meter reads. EDI noted that the table provided by the CG in its Argument showed, in fact, that each category of meter reads was affected by the change. Further, that nowhere does the CG provide any rational connection (either in evidence or compelling argument) between its observation and the reasonableness of the allocation method reflected in EDI s revenue offset forecast. EDI submitted that the evidence provided sound reasons for the change in methodology, and EDI s forecast revenue offset for these services should be approved as filed. Views of the Interveners CG The CG noted that as indicated in Schedule A of Exhibit , Appendix B-2-3, EDI provides services to EWSI with respect to water meter reading and remote verification. For 2004, EDI has forecast revenues of $2.1 million; which represented a decrease in payments received in 2002 of $2.5 million and $2.6 million in The CG provided the following comparison of the revenues received with respect to each service: Table 12. Revenues Received from Edmonton Water Services Inc Actual $M 2003 Reforecast $M 2004 Forecast $M High Density Meter Read Revenue Low Density Meter Read Revenue Off-Cycle Meter Read Revenue Management Services Fee* Total * Prior to 2004, cost for Management Services was included in the base charges for Meter Reads and not charged separately. 101 Exhibit EUB Decision (August 13, 2004)

81 The CG noted the most significant decrease in 2004 is in the High Density meter reads for which EDI provided the following explanation: Essentially, what we did is went out and looked at the actual number of meter reads taken in respect of water services and the ones taken in respect of electricity and did a cost analysis of that to derive the new unit rates. The previous unit rates were not derived on this type of cost analysis. And then when we examined those unit rates, we discovered there was a substantial difference, which I think is the roughly half million dollar or $600,000 amount that you ve identified here. So that s how it rolls out. 102 The BearingPoint Report 103 noted that for 2004, the estimated number of meters was based on a count as at June 1, 2003 of 286,000 electric meters and 207,000 water meters. The CG submitted that, while EDI notes the change in costing methodology that resulted in a reduction in revenues from EWSI in 2004, it is interesting to note that this change in methodology only appears to affect the high-density meter reads. The CG submitted that it would have assumed that the change in method would have affected the revenues or cost-recovery from all types of meter reads rather than selectively from one source of meter reads, but no explanation or evidence to this end was provided. Also of note is that EDI waited until the 2004 test year, the first time its accounts are subject to public review, to effect a reduction in revenues from an affiliate. The CG noted in both 2002 and 2003, the revenues from EWSI are about the same. The CG submitted that, there was inadequate evidence to support a change in the forecast revenues from EWSI. The CG recommended that the 2004 forecast revenues from EWSI be increased by $0.5 million to the same level as in the prior two years for which evidence is available, that is, to $2.6 million. The CG summarized its position by stating that the reduction in revenues expected from EWSI of $0.5 million in 2004, relative to the prior years 2002 and 2003, is not supported in evidence. The number of meters read is the same as that in 2003 since the 2004 forecast was based on the actual meter count as at June 1, EDI s evidence suggesting a change in costing methodology resulting in revised unit rates is not persuasive. This revision only affects the revenues from high-density meter reads, revenues from other types of meter reads is not affected in any significant manner. No evidence has been presented why a change in methodology affects only one out of the three types of meter reads. CG submitted the 2004 forecast of revenues from EWSI be set at the same level as that for 2002 and 2003, that is, $2.6 million, an increase of $0.5 million. Views of the Board The Board notes that EDI has changed the methodology used to determine a sharing of the costs of meter reading with EWSI. The Board does not agree with the CG submission that the reduction in revenues expected from EWSI of $0.5 million in 2004, relative to the prior years 2002 and 2003, is not supported in evidence. The Board notes that EDI s charge to EWSI for reading water meters was reviewed by BearingPoint and found to be reasonable based on the services provided, the chosen allocation methodology, and the total cost to EDI for the provision of the meter reading function Tr. pp Exhibit , Appendix B-7, p. 36 EUB Decision (August 13, 2004) 75

82 The Board has reviewed the allocation methodology and considers the resulting price to be reasonable and fair. Further, the Board notes that the costs allocated to EWSI represent the fully allocated average cost of reading a meter and not the incremental cost of reading a water meter. In this respect, EDI s Application is distinguishable from that of EPC in which the Board determined that the EPC s revenue offset should be increased to reflect fully allocated costs. 104 The Board observes that the EDI $2.12 million fully allocated cost to read 207,000 water meters is virtually identical on a per meter basis to the EPC $2.17 million fully allocated cost to read 210,000 water meters determined by the Board in Decision For all of the above reasons the Board approves EDI s proposed revenue offset of $2.12 million for water meter reading. The Board also approves the application of the $2.12 million revenue offset to the Site, Metering, Settlement and Tariff cost category. 4.2 Service Connections, Jobbing, Material Sales EDI s DTA reflected $2.0 million in revenue offsets as a line item in EDI s revenue requirement. The sources of these revenue offsets are described in section 6.1 of EDI s DTA. 105 EDI provided further information respecting its revenue offsets forecast, including year-over-year trends, in its written materials and oral testimony. 106 Views of the Applicant EDI submitted that EDI s forecast of revenue offsets is consistent with previous years levels. The major changes in 2004 relating to revenue offsets were: a forecast reduction in material sales, which is consistent with the forecast reduction in housing starts and general downturn in the economy reflected in EDI s Application, Appendix C; a forecast $0.6 million increase in service connection fees charged to retailers; and a reduction of $0.4 million due to decreased work loads in respect of services provided to ETI. 107 EDI noted that the CG argued that EDI s revenue offset forecast should be reduced by $0.6 million due to the omission of Service Connection Fees. EDI submitted that no such adjustment is required, as it was fully addressed in EDI s February 23, 2004 errata filing. The errata filing shows revenue offsets of $2.0 million for the 2004 forecast (see Schedule D-1), whereas the amount shown in the October 1, 2003 originally filed version of Schedule D-1 was $1.4 million. EDI submitted that EDI s revised forecast of revenue offsets for 2004 was reasonable and appropriate and should be approved by the Board See Decision Exhibit CCA-EDI-9, UCA-EDI-22, BR-EDI-8; T6: , ; T11: Tr. pp EUB Decision (August 13, 2004)

83 Views of the Interveners CG The CG noted that EDI initially forecast a revenue offset amount of $1.4 million. 108 The CG noted that EDI increased this forecast by $0.6 million in a letter dated Feb 23, 2004, 109 which stated: due to the inadvertent omission of Service Connection Fees. EDI understands that its Regulated Rate provider will be requesting an increased volume of off-cycle meter readings when customers move out. The costs of providing this service were already contained in the Site, Metering and Tariff activity, to which this is an offsetting revenue account. The CG therefore submitted that EDI s filed-for revenue requirement should be reduced by $0.6 million in 2004 due to the omission of Service Connection Fees. Views of the Board The CG expressed concerns regarding the accounting for EDI s $0.6 million increase in its revenue offset forecast. The Board notes that in the version of Schedule D-1 originally filed on October 1, 2003, EDI showed revenue offsets of $1.4 million. However, EDI s February 23, 2004 errata filing shows revenue offsets of $2.0 million for revenue offsets, reflecting an increase of $0.6 million. The Board considers that EDI has appropriately accounted for the increase. The Board has reviewed EDI s $2.0 million forecast of revenue offsets for Service Connections, Jobbing, and Material Sales & Contracting and finds EDI s forecast to be reasonable. Accordingly, the Board approves EDI s $2.0 million forecast of revenue offsets for Service Connections, Jobbing, and Material Sales & Contracting for DEFERRAL ACCOUNTS EDI requested that the Board approve the following reserve and deferral accounts for the 2004 Test Year: Transmission Access Charge Deferral Account AESO Charge Deferral Account Hearing Cost Reserve Account Self-Insurance Reserve Account. 5.1 Transmission Access Charge Deferral Account Views of the Applicant Application. EDI is applying for the account on the basis that the standard, province-wide transmission tariff should flow through to retailers as transparently as possible (thereby accurately communicating the price signals which the Board has determined to be appropriate), and due to EDI s inability to control the AESO s charges related to System Access Service or to GRA Filing, Exhibit , p. 27, Table 12 Exhibit EUB Decision (August 13, 2004) 77

84 forecast them on a reasonably accurate basis. EDI s witnesses provided additional comments on the need for the deferral account at Tr. pp EDI is proposing a 12-month amortization period for balances in the account, but indicated that it would have no objection if the Board wished to impose a shorter period. If a shorter period were to be adopted, EDI has recommended that the Board also impose a materiality threshold (BR- EDI-1). In response to questions from the CCA during the interim rate Hearing, EDI indicated that a $10 million materiality threshold would be appropriate (Tr. p. 165). Further details respecting the mechanics of the deferral account were provided by EDI s witnesses. (Tr. pp ) Parties asked questions respecting EDI s proposal to include volume as well as price in the deferral account. EDI provided the following evidence as to why it would be unreasonable for the Board to approve a deferral account which includes price only (BR-EDI-1(b)). The concept of a for-profit Transmission Administrator has now been replaced by the AESO s non-profit oversight of both the commodity energy market and the transmission system. Under this structure, the AESO will develop the volume forecasts required for the provincial system access tariffs and will bring these forecasts forward to the Board as part of its general tariff applications. In this legislative framework, it is difficult to see how customers would benefit from the addition of a distribution owner s forecast of system access volumes. In EDI s view, its proposed deferral treatment of both transmission prices and volumes is appropriate given that: neither transmission costs nor volumes are controllable by EDI; and the Board s stated approach is to set all transmission costs at a 100% revenue to cost ratio (Decision , p.117). EDI s flow-through approach seeks to provide customers with consistent and transparent treatment of Board-approved transmission charges. EDI has designed its System Access Service rates to match the AESO s rates and charges as closely as possible. EDI submits that the additional layer of a distribution owner s transmission volume forecast would not achieve this objective. Mr. Cowburn elaborated further at Tr. pp EDI also confirmed that its proposal to include both volume and price was made clear in its evidence in the Generic Cost of Capital Hearing, and that the evidence of EDI s expert witness Dr. Evans was premised on the deferral account being approved on the basis reflected in EDI s Application (Tr. pp ). EDI s historical practice has been to make every effort to manage transmission POD peaks through seasonal switching where reasonably possible (CCA-EDI-10(a); Exhibit lists specific examples of these activities; Tr. pp ). As such, there is no need to attempt to incent EDI to undertake these activities through the use of a price-only Transmission Charge Deferral Account. Mr. Cowburn commented further on the inappropriateness of such an incentive (Tr. pp ): Q. Sir, if there were financial incentives in place, and by that I m thinking of a fairly general statement of a sharing mechanism, whereby a reduction in the forecast peak demand were subject to a cost-sharing mechanism, would this be something that would be of interest to EDI? 78 EUB Decision (August 13, 2004)

85 A. Mr. Cowburn: No. Perverse incentives are probably not a good idea. And what that would amount to would be providing an incentive for the utility to take risks in terms of security of supply. I m just not on the page that that s a really effective way of managing a system. I think what more is what does make more sense is to have a look at the actual concrete situations. We re quite happy to provide the Board with any information around what the options are and, more importantly, to work with the AESO in terms of its planning and managing of substation capacity. The AESO is the party who is properly charged with optimizing the transmission system, and I d be concerned that if we have a whole number of parties putting their oar in the water on different and unconnected plans that we re not going to have an integrated system that operates well for customers. So I would submit that the party in the key role of managing substation costs optimally is the AESO, and we will work closely with them to do that. I think adding financial incentives would definitely not help the AESO fulfill that mandate. Q. And these substations you re speaking of, these are am I correct, in these are EDI substations, but A. Mr. Cowburn: ETI. Q. These are the ETI substations? A. Mr. Cowburn: Correct, which are managed and controlled by the AESO under the jurisdiction of this Board. EDI suggested that any balances in the deferral account could be disposed of on an energy charge basis (IPCAA-EDI-20), and that tracking separate balances for energy and demand would be problematic and is unwarranted (PICA-EDI-2). However, EDI s witnesses indicated that EDI is not seeking Board approval at this time of the method by which a balance in the account would be dealt with. (Tr. p ) The evidence demonstrates that EDI s Transmission Charge Deferral Account is just and reasonable as applied-for and should be approved by the Board. In reply EDI noted that PICA and the CG object to EDI s proposal to include volume as well as price in the transmission charge deferral account. The University of Alberta (UA) makes a number of claims respecting the manner in which future balances in the account should be disposed of. More specifically, the CG argues that the deferral account should apply to price only (and not volume). In the alternative, the CG argues that there should be an explicit reduction in EDI s approved rate of return. As discussed in EDI s Final Argument, EDI s witnesses confirmed that the inclusion of both volume and price in the deferral account was made clear in its evidence in the Generic Cost of Capital proceeding, and that the evidence of EDI s expert witness Dr. Evans was premised on the deferral account being approved on the basis reflected in EDI s DTA. EUB Decision (August 13, 2004) 79

86 As stated in EDI s Application (DTA Binder 1, p. 76, ll. 8-10), the use of the deferral account is integral to its formula-based methodology of converting the AESO s rates to the SAS rates. This methodology has been used by EDI since EDI also notes that a 100% deferral account also enables the possibility of a simplified SAS rate design for mass market customers (i.e., Mrs. Jones Redux, Exhibit ) by providing a mechanism to fully true-up the impact from mismatched DTS and SAS billing determinants (e.g., by turning two demand charges in the DTS into a simplified SAS Energy charge for Mrs. Jones). Because of its integral nature, as described in section 11 of EDI s DTA, the Transmission Charge Deferral Account cannot be modified in the manner suggested by PICA or CG without seriously compromising the integrity of EDI s SAS methodology. PICA argues that the transmission charge deferral account should only be used to flow through to customers any AESO charges or credits associated with working capital or other adjustments not built into the AESO tariffs. (PICA Argument, p. 14) In other words, PICA claims that only the AESO s rate riders not already built into the AESO s tariff should be included in the account. Under PICA s approach, EDI would be subject to both price and volume risk in carrying out its responsibility to flow through the AESO s tariff. This is exactly the opposite of the status quo treatment in place since 2001, and is not supported in any reasonable way by the evidence in this proceeding. As pointed out by EDI (EDI Argument, p. 40), neither transmission costs nor volumes can be controlled by EDI. The CG, on the other hand, builds its case for a price-only transmission charge deferral account on the flawed assumption that EDI takes ownership of the transmission volume forecast and thereby earns a rate of return on the risks around that forecast. (CG Argument, p. 56) EDI s transmission volume forecast is shown in columns G and H of Schedule SAS-1 (DTA Binder 2). The purpose of these forecast numbers is strictly for illustrative purposes, as stated in EDI s Application. (DTA, p. 80) The tables shown in Schedule SAS-1 illustrate how the total cost from the AESO will be calculated and recovered. This information is for illustrative purposes only and EDI is not requesting approval of any of the values or numbers used in the illustration. This fact was emphasized again in a written response provided by Mr. Cowburn to the Chairman: (Exhibit ) As stated at lines 32 to 33 at page 80 of EDI s DTA narrative (Binder 1), Schedule SAS-1 is presented for illustrative purposes only as EDI is not requesting approval of any of the values or numbers used in the illustration. The record is clear that EDI does not own a transmission forecast for SAS ratemaking purposes and does not earn a rate of return surrounding that forecast. As such, the CG s recommendation that EDI should be held financially liable for volume risk on figures, which have been generated for illustrative purposes, only is unreasonable and should be disregarded by the Board. The UA submits that EDI s proposal to use a single /KWh rate rider for all rate classes conflicts with Board-established principles because the method disregards known information regarding cost causation. (UA Argument, p. 4) The UA asks that EDI be directed to allocate the 80 EUB Decision (August 13, 2004)

87 transmission deferral account to rate classes in proportion to how it was caused. EDI disagrees with the UA s proposal for the following reasons. Firstly, the UA s recommendation is based on the false premise that amounts in the transmission charge deferral account can be clearly allocated to rate classes. The record demonstrates that this is not possible. For example, in response to PICA-EDI-2, EDI provided evidence that tracking separate balances for energy and demand would be problematic and is unwarranted The UA, on the other hand, has presented no evidence or reasonable argument to refute EDI s position. By continuing the existing practice of charging or crediting customers a single /KWh rate rider based on each customers consumption, EDI s rate design already represents a suitable balance of all rate design criteria, and is not merely focused on cost causation. Secondly, EDI submits that the UA s recommendation will create undue complexity (by artificially attempting to attribute costs on the basis of cost causality) resulting in unwarranted administrative burden, increased regulatory costs (e.g., rate classes would be incented to attempt to convince the Board to shift costs to others), and rate instability (due to cost shifts between rate classes), when a reduction in rate complexity, administrative burden, and regulatory costs, as well as, increased rate stability, should be the objectives (i.e. Mrs. Jones Redux). For the above reasons, the UA s recommendation is not in the public interest and should be rejected. Views of the Interveners CG The CG submitted that EDI s proposal to include volumes in the proposed Transmission Access Deferral account amounts to a reduction of risk it takes with respect to the volume forecast. Absent an explicit reduction in the rate of return for risk transference, the CG recommends approval of the proposed deferral account for changes in prices only. EDI proposed a deferral account for System Access Service costs: based on the premise that the standard, province-wide transmission tariff should flow through to retailers as transparently as possible, thereby accurately communicating the price signals which the Board has determined to be appropriate. EDI also notes that it has no control over the AESO s charges relating to System Access Service, and is therefore not in a position to forecast the cost to EDI on a reasonably accurate basis.edi proposes to record, on a calendar year basis, the total cost of transmission related charges from the AESO, and the total revenue associated with EDI s System Access Service Rates in its Distribution Tariff The difference between the cost and revenue associated with System Access Service will be to the account of customers, and the deferral account will be amortized over the 12 month period following the year in which the deferral account accrued. 110 EDI stated in Response BR-EDI-1 (b) that a transmission deferral account that accounts for both prices and volumes is appropriate since neither transmission costs or volumes are controllable by EDI and the Board s approach is to set all transmission costs at 100% revenue cost ratio per Decision , p Exhibit , p. 27 EUB Decision (August 13, 2004) 81

88 The CG submits, while the concept of a Transmission Access Charge deferral account is appropriate, it should be limited to changes in prices only. The fact is that EDI develops its own transmission forecast related to transmission related volumes, and takes ownership of that forecast, thereby earning a rate of return on the risks around that forecast. For it to now suggest that customers take that volume risk implies that there has been a reduction to the risk for which it is being compensated for. To accept EDI s proposal would mean that there would have to be an explicit reduction in the rate of return to reflect the risk transference related to transmission volumes to customers. The CG submits the Transmission Access Charges deferral account should be approved to recognize changes in prices only. In reply CG submitted that given the evidence that the monthly amounts accumulating in the Transmission Charge Deferral account will either be positive or negative, the CG agrees with EDI position that the true-up in this deferral account be undertaken on an annual basis. Frequent true-ups, such as on a monthly or quarterly basis, will lead to frequent rate changes and in the CG s submission, are not consistent with customers desire for rate stability. EDI states in its Argument at p. 39 that while its preference is to have a deferral account that is trued up on an annual basis, it would be agreeable to a quarterly true-up process if the Board determines that to be appropriate. EDI suggests a $10 million amount would be appropriate for purposes of determining materiality. At the interim hearing, EDI stated: I would also point out that what seems to happen with the AESO, as with any party in this industry, is that one month or series of months you will be up and the next few months you will be down, depending significantly on Pool prices. So from a customer rate change stability perspective, we would suggest considering that factor in deciding what amounts and over what periods of time to true-up. But of course this is really a customer concern issue to us that we just don't want to see customers inconvenienced anymore than they need be. (Tr. pp ) For the reasons advanced by EDI, particularly with respect to rate stability, the CG agrees that a quarterly adjustment would not be appropriate. The CG position with respect to the allocation of the balances in the proposed SAS Deferral Account is not unanimous and will be dealt with by parties in separate arguments. 82 EUB Decision (August 13, 2004)

89 UA EDI s tariff application proposes to balance its transmission cost deferral account using a single /kwh rate rider that is applicable to all rate classes. 111 The AESO s transmission tariff is a public document, and therefore the cost drivers behind the transmission deferral account are known: surpluses and shortfalls may occur on demand-based charges, energy-based charges, and Operating Reserve charges (a variant of energy-based charges that incorporate the wholesale value of energy). Furthermore, Board Decision supports an improved transparency in the reconciliation of AESO deferral accounts, which will no doubt assist EDI in understanding the cost drivers of its own deferral account. At the same time, EDI possesses rate class load data as to how each rate class is contributing to system peak demand, to total energy consumed, and to when the energy is consumed. 112 From the DAS and SAS schedules provided in the EDI application, the University understands that EDI uses this information to calibrate its System Access tariffs for each rate class. Acquiring this information poses no additional effort because EDI already possesses all the information to understand the cost drivers behind the transmission deferral account as well as how rate classes on the distribution system contribute to those cost drivers. Therefore, the University submits that EDI s proposal to use a single /kwh rate rider for all rate classes conflicts with Board-established principles because the method disregards known information regarding cost causation. By making use of this information, the University believes that fairness can be materially improved with little effort from EDI and with no additional complexity for customers. As a minimum, the University believes that the Board should direct EDI to allocate the transmission deferral account to rate classes by each rate classes contribution to the deferral account. This can be calculated by comparing actual revenues for each rate class to allocated costs (subject to what the Board may direct in regard to volume risk). Provided the deferral account is initially allocated to rate classes in proportion to how it was caused, the deferral account could still be balanced through a /kwh rate rider, although it would now be different for each rate class. The University is aware of rate rider billing problems encountered by an EPCOR affiliate in the past, and suspects that a contributing factor may have been related to the complexities of allocating a deferral account down to the individual customer level. Notwithstanding this concern, the University submits that its proposal or other proposals that more accurately settle the transmission deferral account on a cost-causation basis should be adopted. As it stands, the proposed EDI method is unfair and out of step with Board established principles of cost causation. Views of the Board The Board agrees with EDI that it would be appropriate to establish a transmission access charge deferral account. However the Board agrees with the interveners that the transmission access charge deferral account should be a price only deferral account See Section of the October application, starting on p. 27 See EDI s Schedule DAS-11 EUB Decision (August 13, 2004) 83

90 The Board notes that the 39.0% common equity ratio determined for EDI in the Generic Cost of Capital (GCOC) Decision was based on the assumption that the deferral accounts that the Board approves for EDI in this Proceeding would not be materially different than the deferral accounts in existence at the time of the GCOC Proceeding for the Fortis DISCO and the AE DISCO. The Board notes that both the Fortis DISCO and the AE DISCO have transmission deferral accounts based on price only. Accordingly, the Board concludes that a price only transmission access charge EDI deferral account is consistent with the 39.0% common equity ratio determined for EDI. The Board also considers that a price only transmission access charge deferral account will provide EDI the proper incentives to manage transmission billing demands. The Board is not convinced that the amounts in the transmission deferral account would be any greater than the amounts in EDI s energy deferral account which is trued up on a quarterly basis. The Board agrees with EDI s proposal to true up the deferral account on a quarterly basis and collect/refund the quarterly balances in this deferral account on a per kwh basis over the subsequent quarter. Accordingly, the Board directs EDI, in its refiling, to establish a transmission access charge deferral account that records changes in transmission access costs due to changes in AESO rates only. The Board also directs EDI to implement a process to true up the deferral account on a quarterly basis and collect/refund the previous quarter s balances in this deferral account on a per kwh basis over the subsequent quarter. 5.2 AESO Charge Deferral Account Views of the Applicant In its revised filing, 114 EDI requested an additional deferral account. The AESO Charge Deferral Account would track costs incurred by EDI in respect of the AESO, which are over and above the AESO s charges included in the Transmission Charge Deferral Account. The costs to be included in the AESO Charge Deferral Account include EDI s operating and/or capital costs relating to AESO administration charges and the AESO s systems initiatives, all of which are undefined and uncertain at the present time and are outside of EDI s control. 115 Included in the account would be AESO s capital and operating costs related to the enhanced Load Settlement initiative. EDI stated that an estimate of $1.1 million had been provided based on limited information, and that the actual expenditures to meet 2004 AESO requirements could be several million dollars. As another example of potential future charges, EDI indicated that it has received certain bills from the AESO (for which it had no prior knowledge) in respect of the 2002 and 2003 Load Settlement Cost Recovery ($45,871 and $314,965, respectively). EDI noted these costs will be dealt with as part of 2003 and are not included in the 2004 Revenue Requirement. The ongoing uncertainty of the AESO charges, the undefined nature of the AESO s current system initiatives, and the uncontrollable nature of these costs resulted in EDI proposed AESO Charge Deferral Decision , p. 53 Exhibit , pp Tr. pp EUB Decision (August 13, 2004)

91 Under the proposal when EDI must make capital investments or incur operating costs to comply with AESO directives, the associated investments and costs would be included in the AESO Charge Deferral Account, to be subsequently reviewed by the Board and included in EDI s approved rates in its next DTA. For the purposes of EDI s 2004 forecast filing, EDI proposed that an amount of an additional $400, be included in the revenue requirement to establish an initial AESO Charge Deferral Account balance. Parties asked questions regarding EDI s forecast of $1.1 million respecting the AESO s Central Site Registry and Hub Project, which project would be included in the applied-for AESO Charge Deferral Account. 117 EDI s witnesses indicated that the $1.1 million forecast was based on EDI s best guess in the face of extremely limited information on which to base its forecast. Mr. Cowburn stated that EDI would have no objection if this account were consolidated with EDI s applied-for Transmission Charge Deferral Account. 118 EDI submitted that the evidence demonstrated that EDI s AESO Charge Deferral Account was just and reasonable and should be approved by the Board. In reply EDI noted that the CG argues that $400,000 of the $1.1 million associated with EDI s share of the AESO s enhanced Load Settlement Initiative should be removed from the AESO Charge Deferral Account on the basis that EDI will henceforth be getting advance notification of such billings. EDI submitted that the CG s argument should be rejected because the $400,000 settlement project, like the rest of the $1.1 million and other future costs, are all part and parcel of the same project. As such, EDI is unable to control or forecast the costs on a reasonably accurate basis. Furthermore, the CG agreed that in principle it is appropriate to provide for deferral account treatment for the settlement project. The CG s recommendation to disallow the 400,000 amount contradicts the very principle it endorses and should be disregarded. Views of the Interveners The CG concurred with EDI with respect to the establishment of the AESO deferral account with respect to capital costs considering the significant uncertainty with respect to the total capital related costs associated with the enhanced Load Settlement initiative. The CG noted there is some considerable debate in the industry as to whether the AESO should even proceed with this project. 119 Hence, the CG agreed in principle that it is appropriate to provide for a deferred account treatment for this project, as well as any related EDI capital projects to comply with AESO directives. With respect to operating costs associated with load system initiatives, the CG noted in the Attachment to Response to UA-EDI-8, AESO provided EDI on November 27, 2003 an advanced notification of the expected 2004 recovery charges, based on the ISO Board approved load settlement operating costs. The CG submitted that, while EDI stated that the 2002 and Tr. pp Tr. pp Tr. pp Tr. p EUB Decision (August 13, 2004) 85

92 billings were somewhat of a surprise, the evidence suggests EDI will be henceforth be getting advance notification 120 of such billings and there is no need for the creation of a deferral account for these operating expenses. The CG also submitted that there is no history to suggest that the amounts estimated by the ISO for the forthcoming year will be materially different than the actual costs. In time, if EDI can demonstrate there is significant difficulty in determining a reasonable forecast for the ISO load settlement operating costs, it may be appropriate to consider a need for a deferred account. The CG submitted, that need had not been demonstrated in these proceedings. Based on the foregoing, it is the CG s submission that the entire $400,000, most 121 of which is related to the Load Settlement operating costs, should be removed from the AESO Charge Deferral Account. The CG submitted that separating the $1.1 million of capital costs related to AESO s Central Site Registry and Hub Project in the AESO Charge Deferral Account would provide for better transparency than including them as part of the Transmission Charge Deferral Account. Further, the AESO project is capital in nature, and potentially the costs may vary significantly (estimate of total projected costs range from $10 million to $100 million, per Tr. p. 1253). However, the CG agreed the costs for this project can, if the Board desires, be consolidated with the applied-for Transmission Charge Deferral Account. Views of the Board The Board considers that it would be appropriate to establish an AESO Charge Deferral Account to record EDI s share of AESO capital projects such as the e-lsi project. The Board considers that it is appropriate to establish a deferral account for these costs since they are outside the control of EDI management and may be significant and difficult to forecast. The Board considers that an AESO Charge Deferral Account separate from the Transmission Access Charge Deferral Account is appropriate so that costs can be allocated over the period of time for which the project provides benefits. Therefore, the Board approves the establishment of an AECO Charge Deferral Account and also approves EDI s proposed 2004 funding for this account of $1.1 million. 5.3 Hearing Cost Reserve Account The Board approved the establishment of a Hearing Cost Reserve Account for EDI effective January 1, 2004 in Decision The Board has dealt with funding this account earlier in this Decision. 5.4 Self-Insurance Reserve Account Views of the Applicant EDI s proposed Self-Insurance Reserve Account is described in section of EDI s Application. EDI s witnesses further described the purpose, mechanics and criteria associated with the account in their testimony, including the manner in which EDI differentiates between November 27, 2003 Letter from AESO, Attachment to Response UA-EDI-8 Total forecast 2004 AESO Load Settlement Costs amount to $2,717,468 [Response UA-EDI-8, Attachment] applied to 13.38% estimated percent allocation to EDI [GRA Revised Filing, Exhibit , p. 32], equals $364, EUB Decision (August 13, 2004)

93 emergency repairs and replacements, which would be covered by the deferral account, and repairs and replacements that would not be covered by the account. 122 EDI proposed maintaining the current $558,000 balance in the account, which is reasonable based on EDI s largest deductible in terms of its insurance coverage. 123 In reply EDI noted that the CG argument that the Board should make a number of directions to EDI in relation to the self-insurance reserve. EDI submitted that the CG s central concern with respect to the reserve in the 2004 test year appeared to be ensuring that there is no double counting of costs. EDI submitted that it was well aware of concerns over potential doublecounting of costs and has adopted protocols to ensure that such double-counting does not occur. EDI s witnesses provided an example of the process that is followed by EDI to ensure that double counting of costs does not occur. 124 EDI submitted that the record is clear as to both the criteria that will be used by EDI to determine whether a cost should be included in the reserve, and the protocols in place within EDI to ensure that there is no double counting. As such, EDI submitted that the directions the CG requested need not and should not be made. Views of the Interveners CG The CG submitted that to provide clarity and ensure there is no double-counting of costs, EDI should be directed to exclude from all future costs of repairs, any event that fits the definition of emergency repairs or replacements. Likewise, EDI should demonstrate that all emergency repair items it proposes to charge to the SIR are not included in the repair forecast. EDI should provide supporting evidence to this end at the next GRA. EDI should be directed to expand the criteria used to assess whether a cost item is eligible for the SIR treatment. Specifically, if an emergency repair or replacement meets the criteria for capitalization under GAAP or EDI s internal policies, it should not qualify for recovery through the SIR treatment. EDI, in its filed application (Section 6.2.3, p. 30) stated that as a result of recent events, there has been considerable turmoil in the insurance sector in respect of property and replacement insurance for electric utilities. As a result, property and replacement insurance for aerial and underground distribution facilities is either not available or has become for more expensive than in previous years. As a result, EDI has not obtained insurance for aerial and underground distribution facilities. EDI indicated that it has had balance in the SIR account of $558,000 since 2001 i.e. there have been no claims charged to this account nor has there been any additional expense recovery from customers since The balance in this account is based on the deductible amounts and the largest deductible is for Business Interruption which is currently $500, The CG notes Tr. pp Tr. pp Tr. pp Response CCA-EDI-12 (f) Response CCA-EDI-12(i) EUB Decision (August 13, 2004) 87

94 at Tr. p. 1894, this was corrected to read that the $500,000 amount is related to third-party liability. Based on an understanding that any proposed charge against the SIR will be reviewed by the Board for approval, the CG agrees with EDI s proposal. The CG also notes EDI contemplates including the cost of emergency repairs or replacements related to its aerial and/or underground distribution assets 127 in the SIR. If such a claim is made, the CG recommends that the Board direct EDI to provide detailed evidence that the cost of such repairs or replacements were not included in the Board approved forecast revenue requirement and rates and is clearly distinct and incremental from the repairs forecast in the Revenue Requirement. The CG notes from a discussion at Tr. p and Tr. pp , that the distinction between an emergency repair and a normal repair appears not to be clear. For example, all costs to fix repairs are recorded on a work order and only subsequently is a determination made whether it is a normal or emergency repair. For instance, a number of years ago, we had a spring snowstorm, and it brought down a lot of our lines and caused a lot of power outages to our system. We would take out at least one repair work order for our people to charge their time to, and that would come under the repair activities or the repair accounts area of the organization. That order would then have all the time, material, equipment charged to that particular work order. When, upon having completed that and the days following that event, probably through discussions that would have involved Mr. Rowes and Mr. Grimes, we would make a determination of whether the self-insurance fund should maybe be used to cover the costs of that expense and have that expense removed from the repair activity. At that time that discussion would take place, and if it was determined that this should be something that s taken over into the self-insurance reserve, then at that time the appropriate accounting measures would be put into place to clear those costs away from that work order in those repair accounts and moved into the self-insurance reserve activity accounts. 128 The witnesses also appear not to make a distinction between a normal and emergency repair. And further: In the language I use, an emergency repair or repair are more or less the same thing. We don't -- we don t have repairs that are not really caused by something that is going to result in an unsafe or environmental concern imminently. 129 I d just like to clarify my understanding of it. Simply, when you go to a nonscheduled event that has occurred, you end up calling that a repair. And, really, it s unscheduled maintenance. You could think of it as unscheduled maintenance, in a sense. You have to go out and fix something. You may just fix it, or you may totally replace it GRA Filing, Exhibit , p. 30, Response CCA-EDI-12 (g) Tr. pp Tr. p EUB Decision (August 13, 2004)

95 But getting caught up in this word emergency, when repairs are things that we do not forecast, and so that -- and normally when we're doing a repair, it's involved in a customer outage. And as soon as you tell me we have a customer outage, I call that an emergency. And so we deal with it immediately. So I think we re just getting a little bit hung up on this word emergency. A repair, in fact, is simply a repair. 130 From EDI s perspective, it boils down to being hung up on the word emergency. However, from a customer perspective, it is critical that there be clarity in definition so that the intent and integrity of the SIR is respected. The CG do not want to see normal repairs being flowed into the SIR for to do so, would effectively compensate EDI twice; once through the inclusion of the repair forecast in the O&M and secondly, through the SIR mechanism. To this end, EDI should be directed that all future costs of repairs should exclude any event that fits the definition of emergency repairs or replacements and to provide supporting evidence to this end at the next GRA. Likewise, EDI should demonstrate that all emergency repair items proposed to be charged to the SIR are not included in the repair forecast. EDI also provided six criteria to be applied that must be met for a claim to be flowed through the SIR. In response to BR-EDI-5, EDI confirmed that costs that meet the criteria for capitalization in EDI s Capitalization Policy would not be charged against the self-insurance reserve. This was further confirmed at the interim hearing: I wanted to know if you would agree that if the claim was one which could be capitalized under the generally approved accounting principles and under your capitalization policy, such a claim would not ordinarily be recoverable under the self-insurance reserve; is that fair? MR. COWBURN: one or the other. Sounds quite sensible. You don't want to be recovering it twice. It's Q. And as such, would you agree this becomes an additional criterion that should be added to the six-point list? A. MR. COWBURN: That seems reasonable, yes. 131 The CG therefore submits the Board direct that EDI expand its six criteria to include the foregoing, that is, if an emergency repair or replacement meet the criteria for capitalization under GAAP or EDI s policies, it does not qualify for recovery through the SIR treatment. Views of the Board The Board agrees with parties that a self-insurance reserve should be established. The Board agrees with the criteria proposed by EDI respecting claims to the self-insurance reserve Tr. pp Tr. p. 194 Section of EDI s Application EUB Decision (August 13, 2004) 89

96 The Board notes these criteria are similar to those approved for other utilities under the Board s jurisdiction. Accordingly, the Board directs EDI, in its next GTA, to demonstrate that it has established procedures, which include a requirement for senior management approval, to ensure the following criteria are followed prior to making a claim against the self-insurance reserve: the claim must exceed a materiality threshold of $100,000 (costs of such items as emergency repairs and replacements less than this value are to be considered as normal operating costs); the claim must arise from or relate to an event that is sudden and accidental; the claim will represent the deductible payable if the claim is otherwise insured or the full amount if insurance is either unavailable or EDI elects to self-insure because insurance premiums are prohibitively expensive; the claim is outside management s control and could not reasonably have been foreseen or prevented; the claim is not one for which EDI is compensated through its return on equity; and the claim arises from or relates to an event that is low probability and has a high dollar impact (i.e., exceeding $100,000). Further, the Board directs EDI, in its next GTA, to demonstrate that any claims against the selfinsurance reserve are removed from the bases used to forecast maintenance and repair expenses so that there is no possibility of double compensation to EDI. 6 RATE BASE Opening Balances EDI forecast that its mid-year rate base would be $299.7 million in 2004 based on 2002 actual net capital asset balances and forecast 2003 and 2004 capital additions. EDI indicated that, in preparation for its first DTA to the Board, EDI undertook an extensive review and analysis of its capital assets in the field to ensure that its opening rate base balances for 2004 were reasonable. The Capital Asset Review (CAR Study) was filed as Appendix J to EDI s Application. EDI indicated that the CAR Study provided the information necessary to allow EDI to implement asset recording practices, which are consistent with the methods and procedures approved by the Board for other utilities (Exhibit , Appendix J, section 2.1.2). Views of the Applicant EDI noted that no evidence was filed in the proceeding taking issue with the methodology, analysis or results of the CAR Study, nor was the CAR Study challenged in cross examination. EDI submitted that the record clearly demonstrates the reasonableness of its opening asset balances for 2004 and that those balances should be approved by the Board. In reply EDI noted that the CG, based on the evidence of Mr. Pous, took issue with EDI s opening balances and the CAR study that EDI filed in support of their reasonableness CG Argument, section EUB Decision (August 13, 2004)

97 EDI submitted that the CG has not provided any reasonable basis for its assertions and requested disposition respecting EDI s opening balances for the reasons that follow. To begin with, the CG s assertions are largely based on a misunderstanding or mischaracterization of the CAR study and its purpose. The objective of the CAR study is provided on page 1 of the study (Application, Appendix J) as follows: EDI designed the Capital Asset Review project with the objective of verifying that the asset costs currently recorded in EDI s books are reasonably accurate in terms of reflecting the original cost of those assets currently used in providing distribution access service to customers. Further, the CG s Argument is incorrectly based on numbers from the interim CAR results rather than the final results, which were summarized on page 2 of Appendix P to EDI s DTA. For ease of reference, those results are provided in the following table: Table 13. EDI Comparison of Capital Asset Review and Asset Tracking System Asset Class Capital Asset Review ($M) Asset Tracking System ($M) CAR as % of Asset Meters % Aerial Transformers % Underground Transformers % Aerial Distribution % Underground Distribution % Underground Ducts, Vaults and Power Cables % Total % The CG appears to have overlooked the fact that EDI s CAR study for distribution cables was filed as Appendix P on December 22, 2003, and that Mr. Cowburn provided some clarifying corrections to that Appendix at the outset of the hearing. 134 EDI submitted that, while the CG purported to identify several flaws in the study, the CG s arguments in this regard are based on clear mischaracterizations of the facts. For example, the CG argued in reference to Appendix J, p. 15 that EDI admits that its costing information is on an actual basis only for the period 1992 forward. EDI submitted that this is a clear mischaracterization of the facts. Page 15 of the CAR study makes it clear that applicable rates for labor, fleet, materials and related overheads were based on historical inflation factors. Asset cost information was derived from the best available data, and in the case of meters, transformers and other assets, the original cost information was, in fact, available and relied upon. Further, the study makes it clear that the historical index used for the estimates was provided by Dr. Ryan. None of the members of the CG chose to challenge any of Dr. Ryan s evidence by filing evidence of their own or through cross examination of Dr. Ryan, and no party has provided any reasonable basis in final argument to doubt his analysis or conclusion. 134 Tr. p EUB Decision (August 13, 2004) 91

98 EDI submitted that estimation is the essence of the fixed forward test year regulation and no party can reasonably claim that the mere use of estimation renders an analysis invalid. EDI submitted that it is incumbent on parties who seek to challenge EDI s estimation work to provide a reasonable basis for their criticism. EDI submitted that it had provided a detailed description of the data and the procedures it used in completing the CAR study and the CG has failed to provide any reasonable basis for challenging their reasonableness, or logical nature. EDI states at page 17 of the CAR study that These variations are within the range of reasonableness one would expect from the first application of this estimating process all under 10%. The CAR is a first application of a comprehensive verification process for EDI s assets. EDI submitted that the final results of this Review (Appendix P) indicated that EDI s books of record somewhat understate the original cost of those assets currently used in providing distribution access service to customers. EDI submitted only that its CAR supports the use of its book asset numbers for the purposes of establishing customer rates. EDI submitted that the CG had failed to establish that the CAR study is inappropriate and instead the CG s comments respecting the CAR study amount to little more than a mischaracterization of EDI s methods, which are clearly set out in the record of this proceeding. EDI noted that its methodology consisted of three stages: determination of asset count, determination of asset in-service date and determination of original asset cost. 135 EDI submitted that the GIS provided an accurate listing of assets in service, which no party has challenged. In many cases, the asset in-service date was known with certainty. As indicated above, these dates are known for essentially all meters and transformers throughout their service lives. 136 EDI indicated that in other cases, the asset in-service date was not known with certainty, but could be reasonably established with a high degree of confidence. For example, the in-service date of transformers was well known, and it is transparently obvious that when an aerial transformer is hung on a pole in a new development, the transformer and pole must be installed at the same time. Accordingly, in assessing the in-service dates of the various mass plant components such as poles, conductor, cross-arms and other supporting structures, the in-service date of the related transformers is a reliable estimator, since both would have been installed at exactly the same time. 137 EDI submitted that the most important component of the data is asset cost information. This is known for all assets with confidence back to As shown in the Table at page 8 of Appendix J (as revised in UCA-EDI-20), nearly 60% of EDI s assets were installed between 1994 and 2003, meaning that approximately 2/3 of EDI s assets have been confirmed through the CAR study. The property balances most affected by estimation methods are of ever-diminishing financial importance (e.g., property over 20 years old represents only 16% of EDI s fixed asset charges to customers, and property over 30 years old represents less than 3% of these charges) Application, Appendix J, pp DTA, Appendix J, pp. 24 and 30 Application, Appendix J, p. 37 Application, Appendix J, p. 38 Application, Appendix J, p EUB Decision (August 13, 2004)

99 Based on the above, EDI submitted that the CG had failed to point to any flaws in the CAR study that would render it unfit for the purposes for which it was prepared. Neither has the CG provided any reasonable basis for the actions it asks the Board to take. EDI submitted that the evidence demonstrated that the CAR study verifies that the asset costs currently recorded in EDI s books are reasonably accurate in terms of reflecting the original cost of those assets currently used in providing distribution service to customers. EDI submitted that those balances should be approved by the Board as EDI s opening rate base balances for Views of the Interveners CG The CG noted that in EPCOR IG s evidence, 140 EPCOR IG recommended that the Board establish an independent process to allow EDI s gross plant and reserve to be more realistically tested and established for ratemaking purposes. EPCOR IG further submitted the values proposed by EDI for its 2004 opening balance should only be utilized as a placeholder until such time as EDI, the Board, and customers can better determine the most appropriate opening balances for the regulated entity. CG noted that EDI s 2004 opening plant balances are comprised of two components: gross plant less the accumulated provision for depreciation (reserve) and that EDI states that its books are reasonably accurate. 141 This statement was based on a review of gross plant in conjunction with EDI s attempt to verify the accuracy of the values set forth on its books. The CG was not convinced that the CAR study provided the justification for EDI s claim that its rate base was reasonable. CG noted that EDI admitted that its CAR Study compared to its Asset Tracking System (its records) results in an 11% differential with the CAR Study producing the higher value. 142 While EDI submitted that this should provide comfort to the Board and customers, CG took the position that this was clear indication that EDI s records cannot be considered valid for rate base purposes. CG submitted that EDI established that its books and records can vary from 10% under (sic over) booked values to approximately 94% above (sic under) booked values would imply one of two things. Either that the methodology employed to test the results may be inappropriate or that EDI has historically kept poor records. In either case, the final results are not of a sufficient quality and credibility to establish an opening rate base under regulation that will continue as the basis to charge customers in the future. CG also submitted that a review of the CAR study identified several potential flaws in EDI s analysis. First, EDI admitted that it has not completed its recovery respecting distribution cable. 143 In addition, EDI also admitted that its costing information is on an actual basis only for the period 1992 forward. 144 EDI had to estimate prior data as well as historical overhead rates in Exhibit , pp Application Appendix J, 2004 Capital Asset Review, Section 1.1 Application Appendix J, table at Section 2.3 Application Appendix J, Section 1.2 Application Appendix J, p. 15 EUB Decision (August 13, 2004) 93

100 its effort to establish its CAR dollar amount by plant area. 145 Further, EDI submitted, without any underlying justification, that if a value derived from its CAR is within 10% of its Asset Tracking System then EDI s proposal is reasonable. 146 CG submitted that the reason why EDI s values may be in error by appreciable amounts is its underlying methodology. EDI relied on its Geographic Information System (GIS) to establish what it characterizes as realistic allocation curves. 147 The allocation curves are EDI s basis for estimating historical plant activity. However, EDI admitted that the GIS data was often deficient when it came to obtaining the various installation dates of the asset; this problem was focused primarily in the Mass Plant asset classes. 148 Moreover, the Mass Plant category represented the majority of the investment in EDI s wires function. Thus, while EDI claimed that the asset allocation curves were indicative of the historical trends, they most likely were part of the underlying problem that produced results significantly different from EDI s actual books. The CG submitted that, EDI could not reasonably claim that it has plant in service worth more than reflected on its books, but rather the only correct inference that can be reached is that EDI s approach or system of determining what it has in place is inaccurate. CG submitted that once it is established that EDI s measuring tool is in fact inappropriate, then any conclusions that can be drawn from such analysis lack credibility, especially when one considered that the CAR results apply to the establishment of rate base, and thus return and depreciation components of revenue requirements. The CG also noted that the CAR also remains silent on the reserve. The CG submitted that, without more information regarding historical activity and accuracy of the reserve, no credible inference could be established as to the accuracy of the reserve. EDI admitted that it has not tracked retirements and it utilized assumed survivor curves as a basis for estimating retirement activity. CG submitted the establishment of retirements based on assumed survivor curve patterns does not rise to the level of credible evidence for the establishment of something so important as rate base. 149 As noted in EPCOR IG s evidence, 150 CG recommended that the Board establish an independent process through which both EDI s gross plant and reserve could be more realistically tested and established for ratemaking purposes. CG further submitted that the values proposed by EDI for its 2004 opening balance be utilized for this case only as a placeholder until such time as EDI, the Board, and customers can better determine the most appropriate opening balances for the regulated entity. In reply CG submitted that it would simply add that EDI s claim that the CAR has also provided the information necessary to allow EDI to implement asset recording practices is meaningless since even incorrect values, methods, procedures, etc. can provide information to implement incorrect recording practices. The values proposed by EDI for its 2004 Opening Balances should be utilized for this case only as a placeholder, until such time as EDI, the Ibid., at pp Ibid., at p. 17 Ibid., at p. 37 Ibid Exhibit , p. 19 Exhibit , pp EUB Decision (August 13, 2004)

101 Board, and customers can better determine what is the most appropriate Opening Balances for the regulated entity. Views of the Board The CG raised two concerns in regard to EDI s 2004 opening rate base balances: The level of the accumulated depreciation balance. The results of the CAR Study. In regard to the accumulated depreciation balance, the Board notes that there is nothing on the record to suggest that the accumulated depreciation is not representative of the accumulation of past depreciation charges paid by customers. Accordingly, the Board considers that it is appropriate to use the booked accumulated depreciation to establish the 2004 opening rate base. The Board notes that EDI plans to file a full depreciation study with its next GTA. The Board considers that customers are not prejudiced if, as a result of the depreciation study, the theoretical accumulated depreciation reserve turns out to be different from the actual accumulated depreciation reserve. Similarly, the Board considers that customers are not prejudiced by the affect on rate base, since customers are only responsible for paying a return on prudent net plant that has been derived from actual accumulated depreciation. In regard to the results of the CAR Study for gross plant, the Board notes that while the CG indicated that the gross rate base determined by the CAR study was 11% higher than the gross rate base on EDI s books, the final differential was 4% higher in total. 151 The Board considers the 4% total difference to be reasonable under the circumstances, wherein a number of changes to EDI s accounting and systems have occurred over the last several decades. The Board notes CG s recommendation that the Board establish an independent process through which both EDI s gross plant and reserve can be more realistically tested and established for ratemaking purposes. The Board considers that, since an item-by-item evaluation of every asset in EDI s rate base would be extremely expensive, a sampling methodology is the only cost effective method to determine EDI s opening rate base. In the Board s view, EDI s sampling was extensive and its CAR Study was detailed and comprehensive. The Board views the CAR Study as strong evidence of the reasonableness of EDI s recorded gross plant. The Board also agrees with EDI that the most important component of the data is asset cost information and notes that this is known for all assets with confidence back to The Board also notes that nearly 60% of EDI s assets were installed between 1994 and For all of these reasons, the Board accepts EDI s recorded gross plant as filed. The 2004 rate base that the Board approves in the Decision for EDI arising from its refiling will reflect the average of the opening rate base and the closing rate base (i.e. the closing rate base as modified by the approved 2004 forecasts of capital additions, AFUDC, capitalized expenses and approved depreciation). 151 Appendix P, p. 2 EUB Decision (August 13, 2004) 95

102 The Board directs EDI, in the next GTA, to file its 2005 opening balance for gross plant, calculated by starting from its 2004 gross plant level and then adding its actual 2004 capital additions. Similarly, the Board directs EDI, in its next GTA, to file its 2005 opening balance for accumulated depreciation, calculated by starting from its 2004 opening accumulated depreciation balance and adding the actual Board approved 2004 depreciation. The Board notes that testing of the prudence of EDI s 2004 additions to rate base, if required, will be completed at the time the final 2005 opening balances are approved in the context of EDI s next GTA. 6.2 Capitalization Policy Views of the Applicant EDI filed information describing its current capitalization policy in sections 2.2, 7.2 and Appendix E and J of its Application, and provided further information in UCA-EDI-6 and UA- EDI-8(b): EDI submitted that the record clearly establishes that EDI s current capitalization policy is reasonable and prudent and is working effectively. For example, the CAR Study has shown that capital asset balances are consistent with those physical assets in the field. EDI s capitalization policy accords with Generally Accepted Accounting Principles (GAAP). As noted by EDI s witnesses (Tr. p. 1467), EDI intends to review and revise its capitalization policy in the future having regard for its CAR and its ongoing work to prepare a property unit catalog. In response to questions on EDI s practice of adding 6% as capital overhead to rebates paid to developers, EDI indicated that the allocation of a 6% overhead charge to capital was appropriate as the charge reflects the costs of indirect engineering support that EDI provides in respect of the facilities installed by developers and, as such, is a legitimate capital cost. The 6% represents EDI s average overhead cost charged to all capital projects. The 6% of the costs have been removed from operating costs reflecting the actual estimated time that employees would dedicate to capital in The net result of this is that EDI s rate base is understated by $300, EDI s submitted that the practice of allocating a 6% overhead charge to capital is reasonable and appropriate. EDI submitted that determining a specific overhead cost for each particular project would neither be reasonable or necessary as the administrative cost of doing so would outweigh any benefit gained. EDI also submitted that customers are not harmed in any way by the use of an average overhead rate as the total overhead included in rate base would be the same under either approach. EDI submitted that it had summarized the evidence demonstrating the reasonableness of its capitalization policy in its Argument. EDI s CAR study demonstrates that its capital asset balances are consistent with those physical assets in the field. EDI indicated that its capitalization policy is in accordance with Generally Accepted Accounting Principles (GAAP) and was reviewed with EPCOR s Corporate Controller as well as EDI s Controller and several other senior accounting personnel within the EPCOR group of companies. EDI submitted that the record clearly established that EDI s capitalization policy was reasonable and prudent and, 152 Tr. p EUB Decision (August 13, 2004)

103 further, that it is working effectively given that the CAR study has shown that capital assets physically in the field are reasonably representative of the amounts recorded in EDI s fixed asset account. EDI also noted that it had stated on the record that it intended to have discussions with other comparable electric utilities in formalizing its capitalization policy. EDI believed a review of other utilities PUCs would be beneficial and was willing to make use of them in the construction of its own PUC. EDI submitted that CG s assertion that EDI could adopt appropriate property units simply by making use of other utilities PUCs was unreasonable. A PUC is ultimately unique to each utility and while there may be similarities between the PUCs of different utilities, there will be significant differences as well. These differences arise as a result of differences in climate, geography, rural vs. urban locations, and differences between local laws and building codes, among other variables. 153 However, EDI submitted that the most obvious difference was in the method by which assets have been historically recorded in each utility s chart of accounts. For example, is a pole the asset, or is it a pole with the cross arms, or is it a pole with cross arms and insulators, or is it a pole with cross arms, insulators and the cable? Is it dependent on the voltage flowing through the cable? Is one pole an asset or is it five poles? It is likely that each utility tracks these items differently. On that basis, EDI submitted that the suggestion by CG that EDI simply use AE s PUC without conducting its own review was unreasonable. EDI also submitted that the CG s suggestion that EDI does not need to develop a formal PUC and CPR contradicts CG s other recommendations. For example, CG indicated that it requires more information regarding the historical activity and accuracy of EDI s reserve. The CG also expresses concern in respect of retiring assets on the curve. EDI submitted that, in order to provide the historical information that the CG criticizes EDI for not having, EDI must develop PUCs and conduct a CAR. In EDI s submission, intergenerational equity for EDI customers will be met by the implementation by EDI of a PUC and a capital asset review that work within the constraints of EDI s current accounting system. This is, in part, due to the fact that additional information about EDI assets will be available to all parties that will enable the computation of accurate depreciation rates, thereby providing for an ongoing accurate rate base. EDI submitted that the CG provided no substantive basis for its assertion that EDI s capitalized overhead appears low other than its comparison to EPC. EDI submitted that the record was clear that EDI s financial results are independently audited as a component of EUI s financial results, 154 and the CG did not provide any evidence based on publicly available information or otherwise that would suggest that EDI is anything other than fully compliant with GAAP, including with respect to its overhead capitalization policy. Further, the evidence shows that EDI and EPC are different in a number of ways and may not be comparable. 155 EDI s support costs were lower than EPC s on a per customer basis. 156 EDI submitted that this clearly demonstrated that there are differences in the recording of costs in the accounts of the two utilities that would have an impact on overhead rates. The mix of direct versus non-direct costs would further have Tr. p Tr. p Tr. p Tr. p EUB Decision (August 13, 2004) 97

104 an impact on overhead rates. EDI concluded that it was unhelpful to attempt to compare EPC and EDI without having a clear understanding of how costs are to be recorded in each account. EDI noted that in any event, this evidence was not led by the CG during the evidentiary portion of the hearing and, accordingly, could not be addressed in that context. EDI submitted that the CG has not provided any compelling basis for the requested direction. Views of the Interveners AE AE submitted that EDI should be required to develop and implement a capitalization policy in a manner that is consistent with the practices approved by the Board for other utilities. When asked whether a consistent approach is required in order to give parties and the Board some comfort that EDI is properly representing what is capital versus operating costs, Mr. Grimes replied: I would say that having a more detailed capital policy would probably be helpful at the operational level, and also helpful to the Board here. The policy that we do have in effect is at a fairly high level, as are most policies. There has been past practices that are carried out and well known within the field as far as the treatment of capital or operating expenses. Documenting that in a policy would not or would certainly be acceptable.(tr, p. 1099, lines 5-16) AE submitted that, if the Board accepts EDI s current justification for the 2004 DT in this regard, it should, at the very least, include an explicit direction to file the complete policy in the 2005 DT proceedings. In reply AE stated that during the oral portion of the hearing, EDI appeared to acknowledge that its capitalization policy needed formalization and improvement, but in Argument EDI stated that its capitalization policy was reasonable and appropriate. AE was concerned that EDI is overstating the adequacy of its capitalization policy and agreed with the CG that EDI's policy should be developed in a manner similar to other EUB-regulated utilities. CG The CG submitted that the basis for EDI s proposed capitalization policy was flawed. The use of ad hoc arbitrary advice from personnel to determine accounting policy was not appropriate. The CG submitted that rather than developing a formal PUC and CPR and prior to committing capital and resources to the project without an end date or forecast of total costs, EDI should be directed to consult with AE to determine appropriate property units and a more formalized capitalization policy. In the interim, the proposed capitalization policy should be used for Then if EDI considers additional capital and resources are required to develop a more formal PUC and CPR, the appropriate business case could be presented in its next GRA. In discussion with UCA counsel, EDI admitted that only one of its experienced senior personnel had experience in a regulatory department of a regulated utility (i.e. Enbridge). 157 Further, EDI was unsure whether the individual dealt specifically with capitalization policies. 158 When Tr. p Ibid 98 EUB Decision (August 13, 2004)

105 questioned why EDI did not consult with other regulated utilities with significant experience in regulatory filings and capitalization policy, EDI responded that...it was primarily a matter of time restrictions 159 and indeed EDI was not even aware of what AE s capitalization policy was. In an apparent change of mind, EDI stated that the CICA Handbook was...really the basis upon which the capitalization policy was prepared. 160 EDI s use of the capitalization policy, which was a work-in progress was predicated on having appropriate property units, which EDI proposed would be part of the CAR. 161 In the interim, EDI s proposed capitalization policy would be applied on a case-by case basis. 162 EDI further summarized their proposed capitalization policy as not being formalized in the near-term, but evolving based on experience in This experience would include discussions with other electric utilities. 164 In response to UCA-EDI-6(l), EDI committed to...commence work on a PUC and CPR in 2004 and...include in its next General Tariff Application the work completed to that point. CG submitted the basis for EDI s proposed capitalization policy was flawed. CG submitted that while the CICA handbook may be appropriate for accounting purposes, it is not comprehensive enough to be relied on for regulatory purposes. Further, the use of ad hoc arbitrary advice from personnel to determine accounting policy is clearly not appropriate. CG also submitted that EDI does not need to develop a formal PUC and CPR, with future, perhaps multi-year unknown additional capital and O&M costs associated with it. CG submitted that EDI should be directed, as a starting point, to consult with AE and any other comparable Alberta utilities to determine appropriate property units and a more formalized capitalization policy. This is the prudent action to commence, prior to committing capital and resources to a PUC and CPR project with no end date or forecast of total costs. The CG submitted that, instead, EDI appeared to have an inventory of its property, plant and equipment 165 that could be applied using AE s property units and capitalization policy to determine a starting point for EDI. This could be done with minimal effort and cost. CG submitted that a further examination of the requirement to further develop a PUC and CPR could be completed by EDI in its next GRA, with the appropriate presentation of a business case to support any additional capital or operating costs beyond In the interim, CG submitted that the proposed policy, while not ideal and on an ad hoc arbitrary basis, can be continued for The appropriate presentation of the results of discussions with AE and a proposed PUC and CPR, if required, can be completed in EDI s next GRA. If EDI considers additional capital and resources are required to complete a more formal and comprehensive PUC and CPR, then EDI can present an appropriate business case in its next GRA. The business case would clearly provide proper justification of the selected alternative showing all future capital and operating costs beyond Tr. p Ibid Tr. p Tr. p. 1098; UCA-EDI-6(i) Tr. pp Ibid Appendix J and numerous related information responses EUB Decision (August 13, 2004) 99

106 CG submitted that GAAP and the CICA handbook while appropriate for accounting purposes are not comprehensive enough to be relied on for regulatory purposes. One obvious example is the depreciation detail undertaken by parties in regulatory hearings. GAPP and the CICA handbook do not discuss the Equal Life Group procedure of straight line depreciation, the appropriateness of use of industry averages for establishing Average Service Lives, nor net salvage or other types of analysis employed in conducting an appropriate depreciation study. The CG submitted that the Board determines the appropriate Capitalization Policy and accounting standards that may include and/or supplement consideration of GAPP and/or the CICA Handbook. EDI s submission that its Capitalization Policy is consistent with GAAP is not all that helpful and should be viewed as addressing only the tip of the iceberg by the Board in its determination of the appropriate regulatory Capitalization Policy for EDI. The CG submitted EDI s capitalization policy approach was too ad hoc for regulatory purposes. The CG submitted that moving from the ad hoc work-in progress to a finished product should not take place over an indeterminate time frame with unknown costs. Instead, AE s property units and Capitalization Policy can be used in the interim. The CG submitted future steps and the related costs associated with moving to a more comprehensive and finalized Capitalization Policy would to some extent also depend on the Board s decision on the appropriate approach to depreciation. That is, if the Board decides a light handed approach to depreciation is appropriate in the longer term, then there may be no need for further extensive changes to the Capitalization Policy, other than adopting AE s policy. If the Board decides that a more traditional approach to depreciation is appropriate, then EDI could submit a detailed Business Case in support of that approach for its next GRA. The Board could then determine if the time frame and costs (both presently unknown) of a more comprehensive Capitalization Policy match the benefits. The CG submitted that the amount of overhead capitalized appeared low, particularly in relation to EPC. CG submitted that EDI should be directed to review its overhead capitalization policy to ensure it is consistent with generally accepted accounting principles for capitalization of overheads and report its findings at the time of the next GRA. The CG also noted the amount of overhead capitalized by EDI appears to be on the low side particularly in relation to EPC as shown below: Table 14. Comparison of EDI and ECP Overhead Capitalized EDI EPC EDI Reference EPC Reference ($M) ($M) Total O&M Schedule D-1 Schedule 4.1 Less property taxes Schedule D-2 Total O&M Excluding Property Taxes Overhead capitalized Exhibit Schedule 4.1 O&M before overhead capitalization Overhead capitalized as percent of O&M 6% 17% Capital expenditures D & D-7 Schedule Capitalized Overhead as % of capital additions 7.1% 14.3% 100 EUB Decision (August 13, 2004)

107 The CG recommended that EDI be directed to review its overhead capitalization policy to ensure it is consistent with GAAP for capitalization of overheads and report its findings at the time of the next GRA. Views of the Board The Board notes that all parties, including EDI, shared the view that further refinement to EDI s capitalization policy is required. The Board also notes EDI s indication that it has followed the CICA Handbook in creating the capitalization policies that it currently follows. The Board would be concerned with changes in capitalization rates or policies from one GTA to the next and/or inconsistent application of policies that would result in the capitalization of items that were forecast to be expensed when a prior year s revenue requirement was determined. In that regard the Board takes some comfort in EDI s indications that its capitalization policy 166 principles and approach have been consistent with past practices. 167 The Board recognizes that over the long run customers will pay an appropriate cost of service regardless of whether an expenditure is capitalized or expensed. The Board considers that any intergenerational inequities would not be material, except where capitalization policies were unreasonable or expenditures capitalized were very large. The Board considers that neither circumstance applies in Therefore, the Board is not convinced that EDI s capitalization policy is unreasonable. Accordingly, the Board will accept EDI s capitalization rate and policy as filed for As to the future evolution of EDI s capitalization policy, the Board directs EDI to consider the determinations that the Board has made in this Decision and the capitalization policies of other Alberta utilities in the policy it recommends in its next GTA. 6.3 Capital Additions General Views of the Applicant EDI forecast 2004 capital additions of $42.3 million. EDI indicated that its 2004 capital additions were described in Section 7.3 and Schedule D-8 of its GTA. A prioritization process that was used by EDI to ensure that all expenditures were prudently incurred was described in Appendix H to the Application (with additional detail provided in UCA-EDI-8). EDI s responses to a number of information requests and undertakings provided additional information respecting its applied-for capital additions (e.g., BR-EDI-16(e), (f) and (g), UCA-EDI-9, Exhibits , 27, and 30. In response to questions from counsel, EDI's witnesses provided a detailed explanation of the corporation's 2004 capital budgeting process (see Tr. pp and EDI s response to UCA-EDI-7). EDI submitted that it provided extensive information in support of its forecast capital additions through its Application and responses to information requests, as well as through the oral evidence of EDI s witnesses and EDI s undertaking responses to clearly demonstrate the need for, and prudence of, each forecast addition. The reasonableness of EDI s forecast capital EDI 2004 GTA, Appendix E EDI 2004 GTA, Section 7.2, p. 34 EUB Decision (August 13, 2004) 101

108 additions for 2004 is confirmed by the fact that EDI s forecast total capital additions to electrical infrastructure for 2004 is not materially different from previous years capital additions. EDI noted that section 121(2)(a) of the EUA provides that the Board shall 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 the costs associated with capital related to the owner s investment in the electric utility, if the costs are prudent. EDI submitted that the costs associated with EDI s forecast capital additions for 2004 were prudent and should be approved by the Board. EDI submitted that it provided ample evidence with respect to each capital project proposed for 2004 above a minimum cost threshold of $250,000 that clearly demonstrated that each addition is prudent. The record establishes that there is a demonstrated need for all the capital additions forecast by EDI for 2004 and that their costs are reasonable. EDI submitted that, while certain interveners expressed concern that EDI did not file formal business cases in regard to each of its proposed capital additions, the witnesses provided evidence demonstrating that the information provided by EDI was reasonable in the circumstances. In Reply EDI submitted that EDI s approach to forecasting capital additions for 2004 was reasonable and appropriate and that no party took issue with this conclusion in final argument. Further, that the record demonstrated that EDI s capital additions forecast process was logical and appropriate and, further, that it was sufficiently rigorous and contained checks and balances to ensure that the various components of the forecast were reasonable. EDI submitted that the record contained more than adequate explanations and justifications for each of its proposed capital projects, commensurate with both their nature and size and that there was no reasonable basis for acceding to the CG s suggestion that the Board disallow EDI s forecast major capital projects and convene a separate process to deal with any or all of them for this test year, or withhold approval of these projects until EDI s next GTA. EDI agreed that, if the Board determines it necessary in future GTAs, the Board could direct EDI to provide additional information in respect of its capital projects forecast for future test years. Views of the Interveners AE AE submitted that the same standards should be applied to all EUB-regulated utilities in relation to the adequacy of filed business cases for capital projects. EDI acknowledged that it had not filed any business cases with its application and that what it had provided in its initial filing were essentially only descriptions of the proposed projects. 168 No business case was provided in relation to the remote meter-reading project and, as EDI acknowledged, in the RDS compliance project business case, which was only provided in response to an information request, there was no quantification of the costs associated with the alternatives. While EDI pointed to supplemental information provided through responses to information requests as justification for 168 Tr. pp EUB Decision (August 13, 2004)

109 some of the projects, EDI confirmed that, in respect of some capital projects, the justification provided was basically intuitive. 169 To contrast AE noted that as recently as Decision (ATCO Pipelines 2003/2004 GRA- Phase 1), the Board stated that the minimum requirements for justification of major capital projects included: a detailed justification including demand, energy, and supply information; a breakdown of the proposed cost; the options considered and their economics; and the need for the project. (p. 12) AE submitted that EDI acknowledged that there was significant disparity in the level, scope and detail of the information EDI had provided in relation to its proposed capital projects as compared to that required of other electric applications. 170 As an explanation for this apparent deficiency in its application, EDI relied upon the fact that this was its first application before the Board. AE took the position that, if there is to be any permissible difference between the information included in EDI s application and the applications of other electric utilities, the fact that this was EDI's first application to the EUB would warrant more detail, not less. AE submitted that, if, despite the fact that EDI has failed to provide an adequate level of quantitative information to comply with standard Board requirements, the Board determines that the individual projects or proposals are reasonable, then EDI should be directed to meet the significantly higher standards that are applied to other utilities in future DT filings. CG The CG submitted that the Board should disallow all EDI s major capital projects due to the lack of proper business cases. CG submitted that EDI has not provided sufficient evidence of the net benefits to customers of undertaking these projects. The CG submitted all remaining major capital expenditures in excess of $500,000 should be denied until such time as EDI can provide appropriate business cases to justify these expenditures. The CG noted that UCA cross-examined EDI on the issue of use of business cases to justify capital expenditures as a preamble to discussions on the business cases provided for EDI s capital projects. 171 EDI confirmed via information response 172 and during cross-examination 173 that it was aware of the EUB practice of provided detail for all major capital projects. Despite EDI s agreement that it was aware of the Board s requirement for provision of detail for all major capital projects, the CG s review of EDI s original and updated application shows not one business case was provided for its major capital projects. EDI also confirmed this to AE counsel. 174 Further, even when asked to provide the business cases 175 the explanations that were provided were either minimal or at best qualitative descriptions of the projects. Not one project provided an economic analysis that would allow the Board and Interveners the ability to Tr. p Tr. p Tr. pp UCA-EDI-9(c) Tr. pp Tr. pp UCA-EDI-9(d), BR-EDI-16 and S105-EDI-2 EUB Decision (August 13, 2004) 103

110 determine whether the capital projects provide a net benefit to customers. EDI also agreed with AE counsel that what had been filed in support of its capital expenditures,...were not intended to be justifications or cost-benefits analysis. 176 The CG submitted that none of EDI s major capital projects should be approved, as EDI has not provided sufficient justification to show the net benefits to customers of undertaking these projects. At a more pragmatic level, CG submitted that another alternative was to disallow all major capital projects until EDI is able to provide business cases for each major capital project, at the level of detail normally expected by the Board for other utilities, to justify the inclusion of these projects in rate base. The business cases could be reviewed in a separate proceeding or as part of EDI s next GTA filing. The CG noted that, if the Board is inclined to give EDI a general relaxation of the business cases requirements, the CG also provided its comments on a number of specific major capital projects. In Reply CG noted that its submissions on EDI s lack of proper business cases for major capital projects were addressed in the CG s Argument. The CG submitted that EDI s relying on a dollar amount, description and then an intuitive type feeling falls short of the required regulatory justification. The CG again submitted that the Board should disallow all major capital projects of EDI. The CG shared AE s concern that the same standard requirement for business cases ought be applied to all utilities regulated by the Board. The CG noted that When ATCO Pipelines did not provide proper business cases, it did not obtain Board approval for certain capital projects. The CG submitted that there should be consistent treatment of all utilities regulated by the Board. The CG submitted that EDI had not provided any good reasons why the Board should deviate from its policy requiring detailed business cases for major capital projects. Views of the Board The Board agrees with interveners that for all capital addition expenditures in excess of $500,000 business cases should as a matter of course be provided with any GTA filing, as has been reflected in recent Decisions of the Board such as Decision respecting ATCO Pipelines GRA. In that regard the Board notes that EDI had some familiarity with the Board s requirements for business cases for large capital projects. However, the Board acknowledges that Decision , the Decision that sets out the Board s guideline for business cases for ATCO Pipelines on which Interveners relied, was issued on December 2, 2003, well after EDI filed its 2004 DT Application. Under the circumstances and considering the legislated timelines that the Board must meet in this proceeding, the Board does not consider the CG s recommendation that the Board direct EDI to redo this aspect of its application to be reasonable or fair. The Board also notes that CG opposed approval of all of the major projects in capital expenditures requested by EDI for While the lack of business cases may have somewhat handicapped parties at the start of the proceeding, given the IR process and the opportunity for cross-examination, the Board does not consider that it would be appropriate to disallow all of the 176 Tr. p EUB Decision (August 13, 2004)

111 major capital expenditures of EDI, provided there is otherwise sufficient evidence to support the reasonableness of the proposed expenditures. Therefore, the Board will only consider the specific disallowances of capital expenditures on a project-by-project basis in the sections that follow. Nevertheless, the Board agrees with CG and AE that to ensure a full record, consistent with that required for other utilities, EDI should in its next GTA provide certain material for all capital expenditures in excess of $500,000. Accordingly, the Board directs EDI, in its next GTA, to provide appropriate business cases for capital expenditures in excess of $500,000 clearly showing: The reasons/need for the proposed expenditure; The alternatives examined; The incremental capital and operating costs associated with each alternative examined for a minimum 10 year period; The discount or investment rate used to compare alternatives and the basis for its use; The annual costs of each alternative for the period analyzed; The rationale for choosing a specific alternative, including any qualitative considerations used in choosing the alternative; and The date of preparation and the date of approval Regulated Default Supply Compliance Project Views of the Applicant EDI submitted that as noted in cross examination (Tr. p ff), EDI provided a detailed business case in response to UCA-EDI-9(d), setting out and analyzing the alternative means of complying with the Regulated Default Supply Regulation and related tariff responsibilities and provided the business analysis in BR-EDI-16 Attachment 1. As explained by the witnesses (Tr. p. 1754), this project will enable EDI to comply with the standardized tariff formats expected to be prescribed by the Board in 2004, and to provide bill-ready tariff information to retailers. The system will also incorporate the extensive audit and process controls required both to ensure accuracy and completeness of all customer billing, and to report on the quality of billing services to the Board on a regular basis (Tr. p. 1630). EDI indicated that the existing settlement systems of EDI and a number of other Load Settlement Agents were built around settlement timing. When built, it was commonly understood that that coupling the AESO s wholesale settlement with distribution tariff calculations was the policy direction in which the industry was moving (Tr. p. 1124). The new industry requirements required the revision of EDI s current systems and processes. EDI also indicated that this project would be of benefit to retailers, EDI s regulated rate provider and customers. EDI submitted that the RDS project was a prudent and reasonable response to the current industry requirements, and is required to deliver tariff-billing services to customers. The evidence demonstrates that the RDS Project is prudent and should be approved by the Board. In Reply EDI noted that the CG argued that the RDS Compliance project should be denied. EDI submitted that, in making those assertions, the CG has either failed to understand or is attempting EUB Decision (August 13, 2004) 105

112 to mischaracterize the need for the project and ignored clear evidence that EDI has in fact carefully examined all reasonable alternatives. EDI submitted that the Business Case provided in response to BR-EDI-16(e) provided a comprehensive review of the need for this project (pp. 2-4). Further, although the CG tried to focus its argument on only the RDS legislation, it is clear that there are three inherently linked legislative requirements that create a need for the RDS project. These include: the requirement under the Billing Regulation for disclosure of the amounts paid to the owner under the owner s distribution tariff (Billing Regulation, section 4(a); RDS Business Case, p. 10); the requirement under the RDS Regulation that energy and delivery charges for all bills be based on common consumption data, and that twice a year the bills be based on actual meter readings (RDS Business Case, pg. 10); and the Billing Code, which is under development by the AEUB (Tr. p. 1755) (As noted by EDI s witnesses, several of the anticipated Billing Code requirements were articulated in the RIM-C report (Tr. p. 1756), and have thus been known for some time.). EDI also notes that the entire discussion of Mrs. Jones bill format was predicated on the assumption that Mrs. Jones would in fact see her distribution delivery charges on her RRT bill in a bill-ready presentation provided by EDI, and that the format and content of that bill presentation would be determined by the Board (Tr. p. 1755). EDI submitted that the record demonstrated that the ongoing evolution of Alberta s competitive marketplace has created the need for major system changes to meet these new requirements. As stated at Tr. p. 1124: We have modeled our system, as did at least three of the other four wires companies in the province, around the actual timing of when settlement calculations are done, as per the Alberta Settlement [System] Code. And our understanding of how the industry direction was moving, was that that was the way to go.so what we have, at present, is a system that complies with what we saw as the spirit [and] intent of the new industry structure being, but which makes it just impossible for a retailer to take information they re receiving from us and in a timely manner calculate the customer s distribution tariff charge. EDI submitted that the CG mischaracterized this statement by indicating that: the three wires companies further decided that they needed to match the meter reading with settlement. The simple fact is that the Settlement System Code has always mandated that meter readings be used in settlement. At issue is the use of settlement calculations for distribution tariff calculations, which is not dealt with in the Settlement System Code. EDI also submitted that even absent the anticipated EUB directive that distribution charges should be presented to retailers in a bill-ready format, the customer benefits of EDI providing bill-ready calculations to all retailers are obvious (Tr. p. 1126). EDI submitted that, the CG chooses to ignore that if distribution charges are to be flowed through to customers, then EDI is the appropriate party to perform the calculations, both from an efficiency standpoint and billing quality standpoint. 106 EUB Decision (August 13, 2004)

113 EDI submitted that the CG s argument completely misses the central issue, which is how to provide distribution tariff information for customer billing and respond to Mrs. Jones questions as to how those charges were derived. The CG s alternative that un-synchronized customers simply switch their meter reading dates is entirely irrelevant to the issue. As clarified by EDI s witnesses in cross-examination, providing bill-ready detail is a major undertaking and that the benefits of this project go beyond bill calculation. EDI submitted that the record is clear that it is because the RDS project is being undertaken that EDI will be able to meet the Board s eventual requirements. Were the RDS project not undertaken, and a do nothing alternative selected as argued by the CG, then not only would EDI face substantially higher costs to implement the Board s requirements, but EDI s ability to respond to these requirements would be substantially delayed. EDI submitted that the CG s proposal to do nothing and to in effect await litigation was entirely irresponsible. The requirement to move to flow-through billing is well-known throughout the industry, as witnessed by the lengthy consideration given to the impact of flowthrough billing on Mrs. Jones. To irresponsibly ignore inevitable regulatory and legislative requirements, and passively await enforcement and litigation before meeting one s obligations, would be entirely unacceptable to EDI. EDI submitted that it had clearly demonstrated the need for and prudence of this capital project, and has provided an extensive business case that lays out the relevant considerations in a clear and fulsome fashion. The evidence clearly demonstrates that the logic of EDI s decision is clear and compelling. EDI submitted that given that the do nothing alternative is completely inappropriate, the only question that remained was how best to undertake the project. As discussed in the Business Case, there are only two possible alternatives: purchase the software from a vendor, or develop it inhouse. Vendor settlement software is inappropriate for the Alberta marketplace as stated on page 6 of the Business Case and cited by the witnesses. Although EDI with its current system has seen only 16 post-final adjustment mechanism error claims under the Settlement System Code (Tr. p. 1641), making major modifications to a system not designed to accept change is fraught with risk. EDI stated that it is well aware of the shortcomings of vendor software and that the CG s contention that EDI did not examine all reasonable alternatives was completely without basis. EDI has given all reasonable alternatives serious consideration, seeking the lowest cost alternative with the highest degree of reliability from a billing standpoint (Tr. p. 1130). EDI also disagreed with the CG s characterization that the costs of the project are preliminary. EDI submitted that the fact that the costs of the chosen option are forecast costs is an inevitable consequence of fixed forward test year regulation. EDI s cost estimate for this Project was derived through the expertise of our own people in-house on basically the hardware and software side, assessing systems of similar quality and size that they had been involved in before. So it was essentially done by our IT professionals. (Tr. p. 1148) EUB Decision (August 13, 2004) 107

114 EDI took the position that the record clearly demonstrated that EDI has met its onus of justifying the RDS Compliance Project including the need for the project, the analysis of alternatives and the justification for the alternative chosen, and the reasonableness of the forecast of the Project s cost. EDI submitted that there was no doubt that this industry-critical project merits the Board s approval. Views of the Interveners CG The CG submitted that the RDS project should be denied. EDI has not provided adequate evidence to support this capital project. The CG submitted that EDI has not provided a proper business case analysis of the RDS project, all reasonable alternatives were not examined, the costs of the chosen option are preliminary and EPC, who do not believe they are violating any regulations, will not be synchronized by October 1, Further, if the RDS project is truly required, then EDI could submit the RDS project for approval in its next GTA presenting an appropriate and proper business case that clearly shows the chosen alternative is the best alternative for EDI s customers. The CG noted that UCA spent considerable time examining EDI on the $5.765 million RDS Project. 177 The CG received the following admissions from EDI with respect to the RDS project: (i) (ii) (iii) (iv) (v) (vi) EDI provided details of the RDS project in response to the respective attachment to BR-EDI-16(e); 178 The business analysis examined three alternatives with the chosen option being required by July 1, 2004; 179 EDI agreed that it was narrowly within compliance of the RDS Regulation currently and that the July 1, 2004 date had slipped to October 1, This date is based on the EUB rendering a final decision on EDI s 2004 revenue requirement; 180 Once approval was received from the EUB it would be providing disclosure of charges to the retailer and it would be synchronizing meter reads with the production of the distribution tariff so that both would be in the same time frame. This would synchronize the measurement of consumption of customers between the wire services provider and the retailer; 181 The business analysis prepared for BR-EDI-16(e) was prepared after the filing of the GTA (i.e. November 2003) and in more comprehensive detail and with better documentation than any internal decision making done and presented to EDI management which resulted in their approval of the RDS project option to go forward with; 182 While admitting that he was not a lawyer, Mr. Cowburn stated that the do nothing alternative would have no cost associated with it but might violate the letter of law if not the spirit of the law. Piecemeal changes commencing with the do nothing alternative would be inexpensive (i.e. less than $100,000) but would be more Tr. pp Tr. pp Tr. p Tr. pp Tr. pp Tr. pp EUB Decision (August 13, 2004)

115 expensive in the long run than the chosen option. However, that option was not fully examined; 183 (vii) Three of the four wire companies in the province modeled their system around the timing of the settlement but the three wire companies further decided that they needed to match the meter reading with the settlement; 184 (viii) Without this project, any retailer that wanted to do a flow-through distribution tariff calculation on their customer s bill would either have to build their own system or could not flow the charges through; 185 (ix) The RDS project also included other checking and control and auditing functionality than a traditional billing system has in it; 186 (x) While admitting that EDI was not running the retailer s business, the benefit of the RDS project to retailers is significant. The retailers were not contributing to the cost of this new system but the EDI approach would be more cost effective than each retailer doing their own modifications; 187 (xi) EDI confirmed that there was only one active residential retailer in Alberta (i.e. ENMAX) with EPCOR still serving residential customers but getting out of the business and Direct Energy still not confirmed; 188 (xii) EDI s business analysis did not state a do nothing alternative would be in violation of the regulations; 189 (xiii) The second option of Vendor Supplied Software while having a greater cost than the chosen option, was not quantified anywhere apparently because the option was not viable at the first level of analysis. This conclusion was reached without an RFP process; 190 (xiv) The only detail of the costs associated with the chosen option are provided at page 9 of the attachment to BR-EDI-16(e) and that detail is shows only three costs that total $5.765 million; 191 (xv) EDI s business analysis did not include any additional O&M or capital costs over the next 5 to 10 years. The reason this was not done was that once the option was decided on then the cost of the chosen option...would be what they would be. The other alternatives were not reasonable; 192 (xvi) With respect to the chosen option the forecast costs were still accurate, the software provider, who did not have a contract signed, but had a letter of intent; 193 and (xvii) The original estimate of the cost of $5.765 million was based on an internal estimate and not one from external sources. 194 In follow up discussion, EDI indicated that 93% of customers have their meter reading and bill calculations synchronized and thus EDI was already...pretty close to delivering on that Tr. pp Tr. pp Tr. pp Tr. p Tr. pp Tr. pp Tr. pp Tr. pp Tr. pp Tr. pp Tr. pp Tr. pp EUB Decision (August 13, 2004) 109

116 regulation. 195 The Chairman also followed up on the reasoning why it is not 100% in synchronization. EDI stated that it was because customers were...set up on different billing periods. Ironically, when questioned on an Affiliate s ability (i.e. EESAI) to flow through Aquila s charges, the synchronization was...pretty small, like darn close zero. 196 The Chairman further questioned EDI on the timing of the RDS project relative to an EUB letter of February 27, 2004 that essentially was setting up a stakeholder process to standardize the format of wholesale invoice billing, align consumption and wholesale billing information and implement a bill-ready whole invoice billing process. EDI considered that the RDS project was not impacted in any way by any decision made in this stakeholder process. 197 CG submitted in the first instance, that EDI has not provided an appropriate business case to justify the expenditures for the RDS project. EDI s business analysis for the RDS project did not provide economic analysis of each of the alternatives and provided scant detail on the costs of the chosen alternative and the basis for the costs. CG submitted that EDI had chosen the project prior to even conducting any business case analysis. If it had, the business case would have been presented with much more detail and certainly would have been dated some time before the filing of the application. The actual process for approval of the chosen case before EDI s Board of Directors was likely premature given that no detailed business case was prepared. The CG submitted that, if the decision was made without a detailed business case, there was a serious problem with the conduct of decision making at the EDI Board of Director s level, at least as it relates to determination of appropriate capital projects to undertake and have EDI s customers pay for. The CG submitted that another serious flaw in EDI s business analysis was that they do not appear to have examined all reasonable alternatives. In the CG s view, the do nothing alternative, for 2004, seemed like a more appropriate alternative given the EDI decided slippage in the time frame for implementation from July 1, 2004 to October 1, This slippage was entirely based on the timing of the EUB decision, not whether or not EDI would be in clear violation of any regulation or law. What would happen if the EUB decision were delayed to November or December? CG submitted that this reasoning alone was sufficient rationale for the Board to delay approving the RDS project for The CG submitted that another alternative might have been for the remaining 7% of customers who are not synchronized, to simply switch their meter reading dates. While there may be some additional cost associated with doing this (i.e. requirement for additional meter readers or AMR devices), the additional O&M associated with this alternative would likely be much less than the annual revenue requirements of a $5.8 million capital project. The first full year revenue requirement of this project was likely in excess of $500,000. That is a lot of meter readers. EDI did not examine this alternative by itself or in conjunction with the do nothing alternative. The CG submitted that it wad very likely there are several other alternatives that exist that EDI chose not to consider. The CG submitted that the issue of violation of regulations or law was speculative. EDI s original business case did not mention any certainty associated with violation of regulations or law, only possibilities. In fact, in discussions with Board staff, EPC s witness indicated that EPC Tr. pp Tr. p Tr. pp EUB Decision (August 13, 2004)

117 was complying with all current regulations even though there was not synchronization of meter readings or exactly the same bill. Further, EPC believed that there were further changes occurring after this year or in The CG submitted that EPC believed it was in compliance with the RDS regulation even without 100% synchronization and that EDI s attempt to convince the Board that there are legal requirements to do the RDS project were unfounded. In summary, the CG submitted that EDI has not met the burden of proof of the requirement for the RDS project and it should be denied. The CG submitted EDI has not provided proper business case analysis of the RDS project, all reasonable alternatives were not examined, the costs of the chosen option are preliminary and EPC, who do not believe they are violating any regulations, will not be synchronized by October 1, The CG submitted that, if the RDS project is truly required, EDI could submit the RDS project for approval in its next GTA presenting an appropriate and proper business case that clearly shows the chosen alternative is the best alternative for EDI s customers. In reply the CG strongly disagreed with EDI s assertion that it provided a detailed business case on the RDS project. The CG submitted that its Argument pointed out of the shortcomings of EDI s business case and justification for this project (all reasonable alternatives with economic analyses were not examined, costs of the chosen option are preliminary, ENMAX believes it is in compliance with the RDS regulation and no changes were needed until 2005). The CG submitted that the RDS Project should be denied since EDI had not met the burden of proof required for this capital project. Views of the Board The Board has some difficulties with EDI s justifications for and apparent desire to move forward rapidly with the RDS project. The Board does not consider that it is prudent for EDI to embark on a complete rework of its billing system when the form of a number of the ultimate outputs of that billing system are still to be determined, either by this Decision or other processes currently ongoing. Matters that have yet to be decided include: the Tariff Billing Code, which is under development by the Board and the rate design, which will be determined by the Board in this Decision. Therefore, the Board is not persuaded that EDI has justified the need for the $5.8 million RDS project in However, recognizing that some work will be required to meet legislative commitments, and recognizing that work is already underway on the project, the Board will make a partial allowance for the RDS project for the purposes of establishing the 2004 revenue requirement. The Board will therefore allow 50% of the forecast costs, or $2.9 million, to be included in the forecast 2004 capital additions in respect of the RDS project. Accordingly, the Board directs EDI, in its refiling, to remove $2.9 million from 2004 forecast capital additions. The Board noted earlier that the prudence of actual 2004 additions will be tested at the time of the next GTA. The Board directs EDI to file, at the time of its next GTA, a comprehensive 198 Tr. pp EUB Decision (August 13, 2004) 111

118 business case justifying actual 2004 costs for the RDS project, for the purposes of establishing the opening 2005 rate base Meter Data Management Remote Project Views of the Applicant EDI noted that counsel asked questions respecting the justification for the MDM Remote Project. EDI submitted that the record demonstrated the need for and reasonableness of the MDM Remote Project to meet Settlement Code requirements. 199 In order to reach the 100% standard for meter reading set out in the Settlement System Code, EDI proposed that 2,500 hard-to-read meters be changed in In Reply EDI submitted, while the CG argued that the Project should be disallowed, EDI s argument addressed and fully refuted the CG s submissions and showed that the MDM Project was prudent and should be approved by the Board. Views of the Interveners CG The CG noted that EDI requested approval of the MDM project with total capital expenditures in 2004 of $1.1 million with no business case presented to justify this project. The CG submitted that, while EDI provided some information on this project in response to BR-EDI-16(g), the information was mostly qualitative. The CG submitted that, while the CG did not dispute the requirement to read remote sites, an examination of the narrative provided by EDI only shows that EDI has stated that the cost to continue the status quo which includes...continually pursuing out-of hours arrangements, repeated attempts to gain access, and administration is considerable. The amount of this cost is unknown. Further, EDI provided little detail about the products reviewed to accomplish the remote meter reading other than a statement that...edi has reviewed the products available in the market for providing remote access to difficult meters, and has determined that there is a reliable product that provides remote radio frequency meter data to a mobile reading vehicle. The CG noted that, while the cost is provided (i.e. $400/meter), there is no mention of costs of alternative options or technologies. The Board and Interveners are left with a guess about what those costs might be and whether it is cheaper or more expensive than the alternative EDI is proposing. The CG submitted that EDI makes the ultimate statement of its view of how approval of capital projects take place when it states at page 5 of BR-EDI-16(g) that Based on its operating experience EDI considers it would be appropriate to change out some 5,000 hard-to read meters, 2,500 in 2004 and a further 2,500 in The CG submitted that one cannot just simply trust EDI s operating experience, rather, EDI needs to provide an appropriate business case to justify the expenditure, particularly one that takes place over at least a two-year time frame. The CG submitted that the Board should disallow the MDM project since EDI has not provided sufficient justification for the Board to approve the alternative shown. In reply CG submitted that EDI s Argument did not provide further support for approval of this project. While EDI might wish to have as an objective a 100% standard for meter reading as set out in the Settlement System Code, that alone is not enough to justify approval of this project. 199 DTA, section 7.3 and in BR-EDI-16(g) 112 EUB Decision (August 13, 2004)

119 Since no quantitative analysis of the alternatives and their costs were done, the Board and parties do not know if the alternative chosen provides the highest net benefit to customers. The CG submitted that the MDM Remote Project should be denied since EDI has not met the burden of proof required for this capital project. Views of the Board The Board agrees with the CG that EDI has not provided a sufficient case to support the need for the $1.1 million that it forecasts that it will spend on the MDM project to replace 2500 hard-toread meters in The Board is not persuaded that the costs of continually pursuing out-of hours arrangements, repeated attempts to gain access, and administration would exceed the revenue requirement arising from the $1.1 million capital investment. The Board considers that an appropriate business case as described in this Decision that sets out, among other things, the incremental capital and operating costs associated with each alternative examined for a minimum 10-year period is necessary before the Board will approve the additional net revenue requirement for the MDM project. Accordingly, the Board directs EDI, in its refiling, to reduce its forecast 2004 capital additions by $1.1 million for the MDM project Vehicles Views of the Applicant EDI forecast $5.6 million in vehicle replacements for The level of expenditure for vehicles and equipment in 2004 compared to previous years was questioned. EDI submitted that it had provided clear evidence of the need to replace its aging vehicles in order to reduce future operating costs and maintain customer service levels (e.g., DTA section 7.3, Appendices J and H, BR-EDI-16(f), PICA-EDI-45, 46). The increase in 2004 forecast over previous years represents the replacement of vehicles that are reaching the ends of their respective useful lives in The evidence demonstrates that the replacement of EDI s fleet in 2004 is cost-effective and prudent In Reply EDI submitted that EDI s forecast vehicle and equipment additions in 2004 are costeffective, prudent and reasonable. EDI noted that while the CG suggested in argument that there was no justification for approval by the Board of any amounts to replace EDI s vehicles and equipment, the CG also conceded that some vehicles will likely need replacement in 2004 simply because of age and mileage. In reply EDI that it was the need to replace its aging vehicles in order to reduce future operating costs and maintain customer service levels was clear. EDI also noted that the record shows that the City of Edmonton s MESIS model, used by EDI, provides a logical, comprehensive, and reasonable framework to assess the optimum time for replacement of vehicles BR-EDI-16(f) EUB Decision (August 13, 2004) 113

120 Views of the Interveners CG The CG submitted that, while EDI requested approval of $5.5 million for a Vehicle and Equipment replacement project in 2004, there was no business case presented to justify this project. EDI provided some information on this project in response to BR-EDI-16(f), the basis for the response is the City of Edmonton MESIS+ which examines a number of indicators in order to determine if a vehicle is required to be replaced. These include Annual Equivalent Cost, Cost/Usage, Life Cycle costs, Discounted Annual Equivalent Cost, Mileage and Age. There is no further information provided to quantify what the factors are for each of these indicators. That is, at what age are vehicles replaced, what mileage, what annual equivalent cost, etc. Over and above the black box model used by the City of Edmonton, EDI...also inspects each unit annually and uses its internal expertise in fleet management to determine which units require replacement. (emphasis added) There is no attempt to provide detail about what criteria would be used to override the MESIS+ model. The CG submitted this is another example of the trust us belief of EDI. The CG submitted that, while there has been no justification for approval of any amounts to replace EDI s Vehicles and Equipment, CG recognizes some vehicles will likely need replacement in 2004 simply because of age and mileage. CG submitted that the Board should approve one half of the expenditures requested by EDI or $2.75 million for In reply CG submitted that CG s submissions on the appropriateness of the Vehicles capital expenditures are addressed in its Argument. EDI states it had provided...clear evidence of the need to replace its aging vehicles in order to reduce future operating costs and maintain customer service levels. CG submits this generic statement is true. However, as demonstrated in CG s Argument EDI has not provided any further and helpful detail about the black box model that they are using to make decisions to replace vehicles. As noted in CG s Argument, CG recommends that the Board only approve one half of the Vehicle expenditures requested by EDI for Views of the Board The Board agrees with the CG that a business case should be filed in future GTAs to support significant expenditures such as the forecast $6.0 million of vehicle replacements, which are approximately double EDI s historic average. However, the Board will look at the record of the proceeding in this case to consider whether any of the forecast is reasonable for The Board notes that when EDI forecast $5.5 million in 2004 vehicle replacements in its October 1, 2003 filing, its historic vehicle replacements 201 were $2.2 million and $2.7 million in 2001 and 2002, respectively, and re-forecast 2003 replacements were $3.3 million. In EDI s revised filing of February 23, 2004, EDI forecast $6.0 million in 2004 vehicle replacements, historic vehicle replacements 202 were $2.2 million and $3.6 million in 2001 and 2002, respectively, and re-forecast 2003 replacements were $5.3 million EDI GTA Table 15, dated October 1, 2003 EDI GTA Table 15, dated October 1, EUB Decision (August 13, 2004)

121 The Board notes that not only had EDI s re-forecast for 2003 changed by $2.0 million ($5.3 million vs. $3.3 million), in addition EDI s historical actual 2002 number had increased by $900,000. Although EDI considered its forecast of $6.0 million to be supported by clear evidence on the record, the Board is unable to agree. EDI indicated in response to BR-EDI-16(f) that: $5.5 million is budgeted to replace Vehicles and Equipment in A number of units have already exceeded their expected useful lives, resulting in increased downtime and higher maintenance costs. This project will facilitate the replacement of these units and the acquisition of new units to accommodate continued growth. However, the Board can find no detailed evidence establishing what replacements are likely to occur in 2004, except in the responses to PICA-EDI-45 and 46. The Board does not consider this clear evidence to support EDI s vehicle replacement forecasts or even EDI s service life estimates. In the Board s view the evidentiary record on which EDI relies is not explained fully and does not support a forecast of $6.0 million for vehicle replacements in In the circumstances, notably the lack of persuasive evidence supporting EDI s revised forecast of $6.0 million, the Board finds that actual average vehicle replacements in 2001 and 2002 of $2.9 million represent a more appropriate forecast for 2004 vehicle replacements. Accordingly, the Board directs EDI to, in its refiling, use a vehicle replacement forecast of $2.9 million. The Board noted earlier that the prudence of actual 2004 additions will be tested at the time of EDI s next GTA Other Data Processing Equipment Views of the Applicant EDI submitted that, the CG s arguments either ignore or mischaracterize clear evidence on the record demonstrating the prudence of EDI s work management system, as this system has been in place and operating within EPCOR since July 2, 2002 (UCA-EDI-15(j)). It involved the replacement of a legacy system which had become completely obsolete, and which was essential to EDI s ability to ensure that work was properly scheduled and tracked necessary for the operation, maintenance and repair of EDI s system. 203 EDI submitted that the record demonstrated that the work management system was prudent at the time it was put into service, and the CG has provided no rational basis, in either the evidence or based on any reasonable argument, as to why it should be removed from EDI s rate base. Views of the Interveners CG The CG noted that UCA examined EDI on the Work Management System capital project. 204 The CG submitted that, the response to an undertaking to provide the business case associated with Tr. p Tr. p EUB Decision (August 13, 2004) 115

122 the Work Management System with total capital expenditures in excess of $4.0 million to the EPCOR companies, Exhibit , provided nothing in any remote way to justify including expenditures associated with this project. The CG submitted that the Work Management System project should be disallowed from rate base until such time as EDI can provide appropriate justification for the project. Views of the Board The Board notes that the issue interveners raise here appears to be the inclusion of the Work Management System in rate base, rather than any capital additions related to the Work Management System for The Board notes that the work management system has been in place and operating within EPCOR since July 2, 2002, under tariffs approved by EDI s former regulator. The Board also notes that interveners do not suggest that the Work Management System is no longer required. Therefore, in the Board s view, the remaining issue is whether the capital costs relating to the Work Management System are appropriately accounted for and reflected in EDI s 2004 opening rate base. The Board is satisfied from EDI s evidence that capital costs related to the Work Management system have been appropriately accounted for and reflected in the 2004 opening rate base. 6.4 Customer Contributions Views of the Applicant EDI forecast customer contributions of $76.7 million in 2003 and Actual customer contributions for 2001 and 2002 were $76.4 million and $76.6 million, respectively. EDI confirmed its intention to undertake a review of the contribution policies and practices of other distribution utilities in Alberta for its next GTA. Views of the Interveners CG The CG submitted that EDI s contribution policy was dated as EDI has made no change in its contribution policy since 2000, and it was at that time based on the TransAlta policy. 206 With respect to commercial or general service, the contribution policy amounts were determined even earlier, in The CG submitted that, unless circumstances warrant, the contribution policies of the various regulated distribution utilities in Alberta should be more or less similar. The CG recommended that EDI be directed to undertake a review of the contribution policies and practices of other distribution utilities in Alberta. Such an assessment should also include a review of past Board decisions, in particular, Decision related to AE s Investment Policy (Appendix ) and subsequent Decision on AE s compliance filing. The CG recommended that EDI present the results of the review should be provided at its next GRA, and EDI s rationale as to why its contribution policies are adequate in light of the review Exhibit , Schedule D-4, Response BR-EDI-15 (a) Tr. p.1270 and 1442 Tr. p EUB Decision (August 13, 2004)

123 Views of the Board The Board notes that EDI and the CG agreed that EDI should undertake a review of its contribution policies with the intent of developing terms consistent with industry practices. Accordingly, the Board directs EDI to undertake a review of the contribution policies and practices of other distribution utilities in Alberta with a goal of developing terms consistent with industry practices, and to file the review and EDI s policy as part of its next GTA. 6.5 Working Capital Views of the Applicant EDI s working capital requirements were described in section 7.5 of EDI s Application. An analysis of EDI s lead/lag of receipts and payments for 2004 was provided in Schedules D-10 to 18 of the Application, and EDI s treatment of inventory and balances in reserve accounts were described in sections and of EDI s Application, respectively. EDI submitted that the working capital requirements reflected in its Application were reasonable and should be approved by the Board. In reply EDI indicated that the errors in Schedule D-10 of EDI s Application noted by the CG, would be corrected in EDI s refiling and result in a decrease to working capital of $1.2 million. EDI noted that customer contributions for work related to costs associated with additions to the distribution system beyond what EDI invests are held for a short period of time, typically less than six weeks. The funds are held while the work on the distribution system is in progress. EDI submitted that there was no reason to recognize these amounts as working capital. In reply EDI noted that the CG agreed with the need for a hearing cost reserve account. EDI submitted that it was not necessary for the Board to direct that EDI provide a separate calculation of the net lead (lag) to the extent the lag in payment for hearing costs is different from the one used in the calculation of the lag associated with other operating costs. 208 The opening and closing balances in the hearing cost account for 2004 will be zero, and there is no working capital impact relating to hearing costs when using a mid year methodology. Further, to preserve intergenerational equity, it would be appropriate to match the collection of its hearing cost reserve to the period to which the costs relate and, therefore, year-end balances should be zero. As such, there would be no impact to EDI s working capital. Views of the Interveners CG The CG noted errors in EDI s NWC calculation. In Schedule D-10 of EDI s filing, 209 line 11 shows the mid-year balance of the Unamortized Deferred costs as $0.6 million. Schedule D-19 of EDI s Filing shows this amount is with respect to the mid year balance of the 2004 Self- Insurance Reserve Account. At the hearing, 210 EDI confirmed that the balance on Schedule D Application, Schedule D-14 Exhibit Tr. p EUB Decision (August 13, 2004) 117

124 represents an over-collection position and as such should be shown as a reduction to the midyear NWC Schedule D-10. The CG submitted that, to correct this error, the mid-year Working Capital balance be reduced by $1.2 million from negative $5.4 million to negative $6.6 million. The CG noted that EDI confirmed that it collects deposits from customers for all construction when the customer contribution did not cover the entire cost of the construction. 211 The CG submitted that, to the extent these deposits provide a source of funds to EDI and are used to meet working capital requirements, the mid-year balance of such funds should be included in the computation of the NWC. EDI should be directed in its refiling to reflect re-compute its 2004 NWC to reflect the 2004 mid-year average of the deposits collected from customers. The CG also noted that EDI explained in CCA-EDI-11 (a) that the $2 million of hearing costs is made up of $1.3 million for intervener and $0.7 million for EDI costs. The CG submitted that, to the extent payment associated with intervener costs is not made in 2004, EDI may be collecting this amount in advance of the requirement to pay. However, based on the discussion at the hearing, 212 EDI s expectation is that the Board s cost order will be issued in a timely manner such that these payments will be made during the course of the test year The CG submitted that a significant time period can elapse between the time EDI collects the revenue with respect to this component of the revenue requirement, and the time the related cost is actually paid out. The EUB Guidelines for Utility Cost Claims dated June 2001, section 4.1 states that participants must file their cost claims within 30 days of the close of proceeding for which the costs are claimed. In this proceeding, the 30 days from the final Reply argument (which is due on May 17, 2004 for EDI as per the Board s January 14, 2004 letter) would make the filing date about June 16, The Board then will likely make a ruling on these cost claims. Assuming that the Board is able to issue a costs order in about 90 days, by the time the costs are paid to interveners, it might be sometime in the late fall (probably in the October- November 2004 timeframe) of The CG noted that in the meantime, customers keep paying through their rates on a monthly basis a sum in respect of these costs. The CG submitted that EDI would have had the use of these funds for a significant period of time prior to the requirement to disburse these funds. This lag in payment is certainly more than the 45.7 days calculated lag for operating costs. 213 Based on the foregoing assessment, the CG submitted EDI s NWC computation should be adjusted to account for the lag between the timing of payment of intervener costs of $1.3 million and the collection of revenues related to these costs. The CG submitted that EDI should be directed to provide, at its next GRA, the lag in payment for this cost item to the extent it is different from the one used in the calculation of the lag associated with other operating costs and include this in the determination of the Necessary Working Capital. Views of the Board The Board has dealt with parties concerns regarding the impact of hearing costs on NWC in the Operating Expense section of this Decision. There, the Board indicated that, due to the mismatch Tr. p Tr. pp Schedules D-11, L8 and Schedule D EUB Decision (August 13, 2004)

125 in the timing of annual provisions to the HCR and the Board approved payments from the HCR, there might still be an impact on working capital. The Board does not agree with the CG that increasing the accuracy of the calculation of NWC beyond the mid-year convention is warranted. The Board notes that this level of accuracy is not normally used even for the timing of capital additions, debt issues or other items that have a much larger impact on working capital than hearing costs. EDI agreed with CG that the errors in EDI s necessary working capital Schedule D-10 of EDI s Application should be corrected to reflect a decrease to working capital of $1.2 million. EDI indicated that it would reflect this correction in its refiling and the Board directs EDI, in its refiling, to do so. The Board notes CG s suggestion that EDI should be directed to recognize the mid-year amount of construction deposits in the determination of its working capital. However, the Board notes EDI s evidence that customer contributions for work related to costs associated with additions to the distribution system beyond what EDI invests are held for a short period of time, typically less than six weeks. The Board is therefore not persuaded that the impact of construction deposits on working capital is material enough to warrant the direction requested. The Board has examined EDI s lead/lag study and the other portions of its NWC calculation and accepts that the methodology is appropriate. The Board directs EDI, in its refiling, to recalculate its necessary working capital using the same methodology and lead/lag parameters to reflect the affects of the Board s findings in other sections of this Decision. 7 DEPRECIATION 7.1 General EDI forecast gross depreciation expense of $18.63 million 214 for This was derived from an asset gross depreciation expense of $16.98 million plus vehicles depreciation expense of $1.65 million. CIAC amortization of $1.78 million reduced the depreciation expense to $16.85 million. EDI s depreciation expense was calculated based on previously approved studies and parameters. EDI prepared a Technical Update, which EDI indicated included reclassifying assets to improve accuracy and reasonableness. Mr. John Spanos of Gannett Fleming Inc. provided expert evidence supporting EDI s applied-for 2004 depreciation expense. EPC has used the term amortization and EDI has used the term depreciation when referring to the allocation of the original cost of capital investments. The Board notes that the CICA Handbook states Amortization may also be termed depreciation or depletion. 215 For purposes of this Decision, the Board has used the terms depreciation and amortization interchangeably. However, when the Board uses the term amortization it is usually in the context of allocating the cost of plant over a fixed period. EDI submitted that the preparation of a Technical Update for the purpose of determining EDI s depreciation expense for 2004 was both proper and appropriate in the circumstances Schedule D-6 Revised Section EUB Decision (August 13, 2004) 119

126 The Board has reviewed depreciation in the sections that follow: Complexity of Method Regulatory Treatment of Net Salvage 2004 Depreciation Expense Other 7.2 Complexity of Method Views of the Applicant During its cross examination of EDI s depreciation witnesses, the Board raised the possibility of moving to an approach for depreciation that would simplify EDI s accounting and record keeping processes while at the same time reducing utility and hearing costs. 216 EDI understood that the approach would involve the Board fixing the depreciation parameters that EDI would use to determine its depreciation rates for a period of, for example, 5 to 10 years. The parameters would be reviewed at the end of the period for ongoing reasonableness, having regard for the actual asset retirement experience of EDI over the period. EDI s witnesses confirmed their view that fixing parameters for a specified period of time as the Board was suggesting, would be reasonable and cost effective. 217 The 5 to 10-year review period would provide parties with a reasonable opportunity to review EDI s actual retirement experience and consider whether changes to the parameters were warranted. Mr. Urban provided his view that the approach would be consistent with GAAP in terms of the recovery of costs over the life of the asset. 218 EDI noted Mr. Pous expressed the concern that a utility might continue collecting depreciation expense on assets that had been fully depreciated and retired. 219 EDI submitted that the Board could easily address this concern by ensuring that appropriate policies and procedures were in place within each utility to ensure that depreciation expense was recovered in the manner prescribed by the Board. EDI submitted that the Board s suggested approach would be reasonable, appropriate and efficient. EDI recommended that the Board consider adopting the approach as a generic approach for all utilities in the province. EDI stated that it would be pleased to participate in any process established by the Board to employ this approach on a generic basis. In reply, EDI noted it appeared that what the EPCOR IG was suggesting as the depreciation component of the least complex approach was an amortization approach in its classic sense; that is, a square curve approach to depreciating assets in an account. EDI submitted that a square curve approach may be reasonable and appropriate for accounts with large numbers of small assets that are difficult to track, but it would not be appropriate for larger accounts. Instead, a reasonable and appropriate approach that would yield considerable efficiencies would be the Tr. pp Tr. p Tr. p Tr. p. 25: EUB Decision (August 13, 2004)

127 approach (which EDI will refer to in this submission as the frozen curve approach ) developed during the discussion between the Board and EDI s depreciation panel. 220 In any event, EDI submitted that there was ample basis in the Board s extensive experience in dealing with the issue of depreciation and on the record of this proceeding (including the testimony of Messrs. Spanos, Urban and Cowburn, each of whom have extensive experience in the area of depreciation) for the Board to direct EDI to, for the purposes of its next GTA, proceed in a manner that was consistent with the frozen curve approach. EDI stated that this would entail EDI proceeding with its planned depreciation study and then filing asset parameters in its next DTA that were consistent with the results of the study which would remain in place for a period to be determined by the Board. EDI submitted that there was no reasonable basis for requiring EDI to conduct the analysis recommended by the EPCOR as no additional helpful insights or information would be gained, and it would delay the implementation of a sound and logical way to proceed while increasing costs to customers. EDI submitted that EPCOR IG s recommendation to direct applicants to provide the results from a reasonable number of well thought out series of actuarial or semi-actuarial analysis in Excel or Lotus readable electronic format should be rejected on the basis that the EPCOR IG has failed to demonstrate based on any evidence that such an exercise would be of demonstrable value or assistance to the Board. EDI stated that the EPCOR IG had also failed to provide any reasonable basis as to why such analyses should be considered to form part of the Applicant s evidence in support of its applied-for depreciation expense and, further, has failed to identify any issue or concern of substance with respect to EDI s or any other applicant s practices that would show a need for this type of information. EDI stated that it would not object to providing vintage asset data, upon request, to interveners so that they could perform a series of actuarial or semi-actuarial analyses if they wanted to, as long as any such analyses were provided to the Board, the applicant and other parties in Excel readable format to enable a timely review of the material. EDI further stated that the party conducting such analyses would be required to demonstrate its relevance, materiality, helpfulness, etc. in the context of the Application before the Board. EDI noted that EPCOR IG s suggestion that the existing depreciation rate should be retained without modification until a full depreciation study was performed to eliminate the effort and controversy associated with technical updates which are not frequently used in Alberta. EDI submitted that the EPCOR IG s assertion that technical updates were not frequently used outside of Alberta was both inaccurate and misleading and that the EPCOR IG had provided no evidentiary basis whatsoever for this assertion. EDI stated that the record showed that in the absence of a depreciation study, or in years between depreciation studies, the technical update approach results in depreciation rates that were as accurate as possible, ensuring that intergenerational equity is maintained. EDI noted the EPCOR IG argument that no matter what approach, method, system, etc. was employed, adequate safeguards must be in place, suggesting that simply assuming that a utility will only collect 100% of its investment may in theory be correct but in practice may not 220 Tr. pp EUB Decision (August 13, 2004) 121

128 be. EDI noted that one of the main purposes for conducting a technical update was to ensure that a utility s investment in assets was appropriately recovered through its depreciation expense. Views of the Interveners AE AE submitted that a full depreciation study should be conducted for an entity, like EDI, that was facing EUB-regulation for the first time. While the amortization method employed by EDI appeared to reasonably accord with actual experiences in the field, a depreciation study would provide more detailed information in this regard. EDI had already retained Gannet Fleming to perform such a study, suggesting that EDI recognized some value in proceeding with the exercise. Therefore, the Board should order EDI to file a full depreciation study in its 2005 DT application. EPCOR IG The EPCOR IG stated that the overall process of developing the ultimate depreciation expense in a rate proceeding could range from very simple to very complex, and that the two extremes were to either expense an investment or capitalize it forever. EPCOR IG stated that neither extreme was appropriate, as both resulted in unacceptable levels of intergenerational inequities. EPCOR IG stated that within the range of acceptable alternatives were the simple approach of straight amortization over an assumed acceptable period, and the more complex approach of full statistical analysis and detailed judgment investigation. EPCOR IG stated that while the simple approach had the obvious advantage of being less costly to develop and implement, it may also result in the greatest level of intergenerational inequity. EPCOR IG stated that the more complex development of depreciation expense raised its own set of issues and concerns, including the more costly nature required to develop and then review the result. EPCOR IG submitted that while depreciation normally attempted to attain a rational and systematic recovery of investment, the cost to monitor the unique and complex arrangements that could be devised to perform depreciation analyses might not warrant the reduction in the level of intergenerational inequities that may transpire. Least Complex Method The EPCOR IG stated that the least complex method or approach associated with depreciation would be equivalent to amortization of the investment as this approach relied on an assumed amortization period to recover the investment with different options associated with net salvage. EPCOR IG submitted that the simplest net salvage treatment, and the least costly to regulate, was that associated with straight rate base treatment outside of the accumulated provision for depreciation as any costs incurred associated with cost of removal of the retired item, or any gross salvage obtained due to sale or reuse would be assigned to plant in service, totally bypassing the accumulated provision for depreciation. EPCOR IG stated that this approach did not change the level of rate base, but did impact the level of depreciation expense charged in any given period. EPCOR IG stated that for purposes of this proceeding, both EDI and EPCOR IG relied on life, salvage, and calculation simplifications in determination of depreciation expense, as both parties: 122 EUB Decision (August 13, 2004)

129 (i) Based their line parameters on industry comparisons rather than actuarial analyses; (ii) Excluded the net salvage component from the depreciation analysis; and (iii) Relied on the Average Life Group (ALG) calculation procedure rather than the Equal Life Group (ELG) procedure. EPCOR IG stated that while the life approach taken by the parties eliminated the costs of actuarial analysis, it still resulted in areas of disagreement. EPCOR IG noted that costs had also been reduced due to the less complex approaches taken for salvage and the calculation procedure. EPCOR IG submitted that, if the Board was inclined to move to the less complex approach, it still must establish and maintain safeguards, such as ordering EDI to perform a thorough and complete analysis of the cost and benefits associated with employing the least controversial and costly approaches to the development of life, salvage, and calculation procedures to be utilized in developing depreciation expense in its next rate proceeding. Then the Board and interveners would have the benefit of such analysis to determine whether each approach was appropriate or required modification. More Complex and Unit EPCOR IG stated that normal expectations were that more complex and detailed analysis provided more accurate results, and that more accurate results normally were expected to result in less intergenerational inequities. EPCOR IG noted that many Alberta utilities have employed some of the more complex calculation procedures and net salvage calculations than elsewhere in North America but that these complex methods have not been universally accepted as resulting in more accurate outcomes. EPCOR IG stated that the more complex and unique approaches, such as the Constant Dollar Net Salvage calculation and the ELG calculation procedure cost more to develop, investigate, defend and criticize. EPCOR IG further stated that in the area of life analysis, the maintenance of aged data was more costly, but allowed the performance of actuarial rather than semi-actuarial analyses in the establishment of more accurate life parameters, which, depending on the size of investment, could have millions of dollars of annual revenue requirement impacts. EPCOR IG stated that one last area associated with a complex development of depreciation was the ultimate ability of either a utility or intervener to present its analyses in such a manner so that it was understandable to those who may not consider themselves depreciation experts. EPCOR IG submitted that the discussion of different portions of a survivor curve and their impacts on average service lives was not what would be considered interesting to most individuals, but that subtle differences in various areas of depreciation analyses could have a significant impact in the annual revenue requirement charged to customers. EPCOR IG Recommendation Regarding Complexity of Method The EPCOR IG summarized its position by noting that while many different approaches were available to depreciation, each came with a price. The simplistic approach, without adequate checks and balances, could end up being more costly in the long run, whereas utilizing complex and rarely employed approaches ran up costs not only in the development of depreciation expense by the applicant, but in the review of such expense by interveners and the Board. EUB Decision (August 13, 2004) 123

130 EPCOR IG also stated that such additional complexities could also result in intergenerational inequities, possibly to an even greater extent than the simplistic approach. EPCOR IG stated that the guiding principle should be the cost involved versus the benefits obtained but that, unfortunately, the cost involved in developing depreciation on a more traditional basis for small utilities may be just as costly for large utilities. EPCOR IG noted that the overall depreciation expense might be in the few million dollars or less range for a small utility, whereas for large utilities, it could be in the many tens of millions of dollars annual range, and therefore one concept did not fit all situations. Therefore, the Board might need to view its decisions from the standpoint of major and minor utilities. EPCOR IG submitted that no matter what approach was employed, adequate safeguards must be in place, such as mechanisms that check whether EDI recovered 100% of its investment, within a reasonable range. EPCOR IG noted that once the average service life and dispersion curve are selected, another cost saving approach to depreciation analysis would be the utilization of the ALG rather than the ELG approach. The ELG approach, while utilized extensively in Alberta, is rarely used in North America. The added complexity with the ELG calculation and the need to revisit such approach on an infrequent basis requires additional time and effort. EPCOR IG stated that, under standard depreciation approaches, there were several areas that could be standardized and more detailed information provided on electronic format to lower overall costs. EPCOR IG suggested that the Board consider holding a generic proceeding or workshop to receive input from all parties involved under its jurisdiction regarding ideas. The ECPOR IG disagreed with a time between depreciation studies from 5 to 10 years and submitted that there was no basis for up to a 10-year hiatus in between regulatory reviews and assessments of one of the largest revenue requirements. The EPCOR IG supported all appropriate and well thought out efforts to reduce the complexity and cost of a depreciation analysis, but not the boundaries of the time periods suggested by EDI. EPCOR IG noted that EDI s own expert recommended a full depreciation study every three to five years. 221 The EPCOR IG also indicated that there was no evidence that GAAP or any other regulatory body has established that a period up to 10 years was acceptable. EPCOR IG stated that this was especially true when some of the assets may have estimated service lives of less than 30 years or amortization periods less than 10 years. Views of the Board When considering a tariff application, the Board must, pursuant to the provisions of section 122(1)(a) of the EUA, 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 the costs and expenses associated with capital related to the owner s investment in the electric utility, including depreciation, if the costs are prudent Tr. p EUA, section 122(1)(a)(i) 124 EUB Decision (August 13, 2004)

131 The Board notes that the prudence of the capital investment is considered at the time the owner requests that a capital investment be added to rate base. Once the Board has approved a capital investment as prudent and found it appropriate to be added to rate base, the task facing the owner is to allocate the original cost of the capital investment to customers in a just and reasonable manner in the form of depreciation expense. The primary objective of the depreciation method is to allocate the original cost of the capital investment in facilities, no more, no less, over the service life of the facilities. A secondary objective of the depreciation method is to utilize an allocation method that allocates the original cost of the capital investment as evenly as possible over the service life of the facilities. The secondary objective attempts to achieve intergenerational equity by requiring each generation of customers to pay their fair share of the original cost of the capital investment. The Board notes that costly and very complex methods have traditionally been used in Alberta to achieve the secondary objective of allocating the original cost of the facilities as evenly as possible over their service lives. The traditional, more complex depreciation method usually involves all or some of the following steps: Service lives are continually updated and adjusted by using an actuarial study of the pattern of past retirements modified as necessary by future plans and expectations for the facilities, in order to predict an average service life and retirement dispersion (represented by an Iowa curve) for each account. The ELG method is used to calculate the depreciation expense using the selected retirement dispersion. Accumulated depreciation reserves are adjusted to align past experience with future expectations. The Board notes that, despite the above steps, the secondary objective of allocating the original cost as evenly as possible over the service life is not necessarily achieved. This is because the service life and retirement dispersion is continually changed (to align with current expectations), resulting in differing amounts charged to customers each year. Further, accumulated depreciation reserve adjustments may be used to recoup portions of the original cost of the facilities after the retirement of the facilities. This accumulated reserve adjustment is accomplished by assuming that all plant has been fully depreciated at the time of retirement by charging the accumulated depreciation with the full amount of the original cost. The Board also notes that the initial costs of implementing and the annual costs of maintaining these complex depreciation methods do not add any value to the utility service but rather form an overhead cost to customers. Given that the Board now has jurisdiction over EDI and given that the present Application is the first EDI tariff application to be considered by the Board, the Board considers it opportune to review the methods used by EDI to determine the depreciation expense component of its revenue requirement. The Board considers that significant initial and ongoing cost savings could potentially be achieved by EDI by implementing a simpler system of depreciation. The Board recognizes that management must have systems in place that are able to monitor inventory and track facilities that are in service in order to provide efficient utility service. However, as a general principle, EUB Decision (August 13, 2004) 125

132 the Board considers that the depreciation method should not drive the design and implementation of these asset management systems. Rather, the chosen depreciation method should benefit from and utilize whatever systems management considers necessary to provide efficient utility service. In the Board s view, following this general principle will minimize additional overhead costs that are solely related to the determination of depreciation expense. The Board notes that in its basic form a simplified depreciation system would generally have the following characteristics: A square-curve amortization approach for all property classes. A system that ensures that neither more nor less of the original cost of the facilities is recovered through the depreciation expense. The square-curve amortization approach is illustrated in Appendix 2 as one possible basic depreciation system. The Board notes that EDI is planning to implement a sophisticated CAR management system in This system will allocate the existing gross plant investment to the existing property units that are in service. In the Board s view, EDI can implement safeguards to ensure that the amounts allocated to property units are retired when the units are removed from service, thereby ensuring that the no more, no less principle is satisfied. The Board notes that the following processes would tend to add complexity to a basic depreciation system: Calculation of depreciation expense by vintage within each account. Use of a frozen retirement dispersion curve. Periodic reconciliation between actual accumulated depreciation and theoretical accumulated depreciation. Periodic review of the validity of the amortization periods for each property class. The Board agrees with the EPCOR IG observation that one depreciation method may not be appropriate for every utility under the Board s jurisdiction. Further, the capital asset management systems that the utility has in place may, to a large extent, drive the degree of sophistication of the depreciation method. Considering, all of the above, the Board considers that there is merit in simplifying the method used to determine EDI s depreciation expense. The Board notes EDI s argument that a square-curve amortization approach may be appropriate for property accounts with large numbers of small assets that are difficult to track, but that a square-curve approach would not be appropriate for larger accounts. The Board directs EDI, at the time of its next GTA, to propose a simplified method of determining its depreciation expense considering the views expressed by the Board in this Decision. The Board expects EDI s proposal to consider whether the basic form (or other basic forms) would be appropriate in EDI s circumstances. Further, the Board expects that EDI will 126 EUB Decision (August 13, 2004)

133 only add those complexities to its proposal that EDI considers would be cost efficient and appropriate considering the data and circumstances of the EDI system. The Board notes EDI s assertion that its CAR Study supports the reasonableness of EDI s depreciation parameters. EDI submitted that the CAR Study demonstrates that the value of EDI s wires assets in the field is reasonably close to the value of the same assets on EDI s books, showing that the ASLs in place are reasonable. Further the Board notes that the ASLs were the result of a technical update prepared by EDI, which were subject to considerable testing and examination in these proceedings. Accordingly, the Board considers that it would be appropriate for EDI to use the ASLs approved by the Board for each account in this Decision as the account amortization period in EDI s proposed simplified depreciation method. In other words the Board considers that the next GTA should focus on the testing of the simplified depreciation method rather than a retesting of each account s ASL. 7.3 Regulatory Treatment of Net Salvage Views of the Applicant EDI stated that its historical approach to net salvage had been to include the cost of salvage as part of the cost of the replacement asset, which resulted in the net salvage amount being recovered over the life of the replacement asset. EDI indicated that for its next DTA to be consistent with other utilities under Board regulation, it was proposing to review the net salvage parameters provided by Mr. Spanos (Application, Appendix O) in conjunction with actual net salvage data gathered by field staff on a sample basis. EDI stated that it would incorporate the appropriate net salvage parameters in its next filing, as well as in its future depreciation studies. 223 EDI stated that it would also change its practice by recovering the projected retirement cost of an asset over the asset s life, and recording the actual cost of retirement when the asset was retired. EDI noted that this would require that EDI s field crews be trained to apportion their work between removing an asset and the installation of the replacement asset. Mr. Cowburn expressed his concern with the difficulty and amount of effort that would be required to implement and maintain this practice. 224 EDI noted that the Board questioned the appropriateness of EDI changing its practice and incurring added costs for the sake of achieving regulatory precision. 225 In response to the Board s questions as to whether it would be reasonable to allow EDI to continue to use its historical approach to net salvage, EDI s witnesses provided their view that the approach would be fair and reasonable and would not violate any generally accepted accounting principles. 226 EDI noted that Mr. Spanos confirmed that this approach would result in the full recovery of the net salvage, although it would be recovered over the life of the replacement asset rather than the original asset PICA-EDI-35 Tr. pp. 2277, 2306 Tr. p Tr. pp Tr. p EUB Decision (August 13, 2004) 127

134 EDI also noted that Mr. Pous stated that after further review and consideration, he concurred that this approach would be reasonable, indicating that it was consistent with concepts that he has been advocating over the last five years. 228 EDI submitted that the record clearly demonstrated that allowing EDI to continue to use its historical approach to net salvage rather than requiring it to conform to the practices of other Board regulated utilities would be reasonable, appropriate and cost effective. EDI noted that even though the EPCOR IG argued that the average service lives applicable to a number of EDI s wires accounts should be changed based on Mr. Pous reference to other utilities, the EPCOR IG argued that in this proceeding that no net salvage should be recognized in EDI s depreciation expense. EDI submitted that, as noted in the Rebuttal Evidence of Mr. Spanos, 229 it is inconsistent to adopt the average service lives of other utilities without consistently adopting the other parameters, including net salvage since the parameters are inherently interrelated. Further, if the net salvage parameters for the utilities in Mr. Pous sample were taken into account, Mr. Pous analysis would then yield a significant increase, rather than a decrease, in EDI s depreciation expense. EDI noted that, while the EPCOR IG argued that EDI should be required to conduct a detailed analysis of the pros and cons associated with retaining its historic net salvage practice, both EDI s witnesses and Mr. Pous on behalf of the EPCOR IG agreed that allowing EDI to retain its historical approach to handling net salvage would be reasonable and appropriate. EDI submitted that, the EPCOR IG assertion that, if a net salvage component was applied in this proceeding, then it should approximate a zero level, was based on a simplistic and misleading interpretation of certain of the data provided in Appendix O to EDI s Application. Views of the Interveners The EPCOR IG believed that EDI s approach, of excluding net salvage from the depreciation calculation, had merit as it captured the cost of removal and gross salvage and kept such amounts in rate base, yet had the added benefit of eliminating the litigation of net salvage in the rate proceeding. EPCOR IG noted that such an approach was no different from what many other utilities utilized as it pertained to amortization of costs. In many instances, utilities that amortized costs simply amortized the investment and booked any cost of removal or gross salvage associated with the investment being amortized to rate base. EPCOR IG submitted that for this proceeding, no net salvage component to depreciation should be recognized and that the Board should order EDI to provide a thorough and detailed analysis of the pros and cons associated with retaining its historic practice for future rate proceedings. EPCOR IG stated that, if the Board were inclined to consider application of a net salvage component in this proceeding, realistic results still would approximate a zero level of net salvage. EPCOR IG stated that this conclusion was based in part on a review of Appendix O of the Application, where EDI presented the industry range of net salvage values for investment in the wires function. EPCOR IG stated that most of the accounts reflect net salvage ranges that include positive or zero values and as such, EDI s assumed negative levels, without any further Tr. pp Exhibit , Spanos Rebuttal, pp. 12, 18, EUB Decision (August 13, 2004)

135 substantiation, was not adequate support for a negative net salvage level. EPCOR IG stated that this was especially true given EDI s outside consultant s testimony in the recent Nevada case that indicated even more positive ranges for certain wires accounts than reflected in Appendix O, and thus, the evidence indicated that zero or even positive values were realistic for net salvage in the wires function. Views of the Board The Board notes that parties were in agreement that it would be appropriate for EDI to continue its current practice of charging cost of removal less any salvage (i.e. net salvage) to the capital costs of the replacement asset. The Board also notes that EDI s witnesses provided their view that the current EDI approach would be fair and reasonable and would not violate any generally accepted accounting principles. 230 Mr. Spanos, EDI s deprecation expert, confirmed that the EDI approach would result in the full recovery of the net salvage, although it would be recovered over the life of the replacement asset rather than the original asset. 231 Finally, the Board notes the agreement of Mr. Pous, the EPCOR IG expert, that the EDI approach would be reasonable and that it was consistent with concepts that he has been advocating over the last five years. 232 The Board is satisfied that allowing EDI to continue to use its historical approach to net salvage would be reasonable, appropriate and cost effective. The Board considers that the additional overhead cost of the analysis recommended by the EPCOR IG to provide a thorough and detailed analysis of the pros and cons associated with retaining EDI s historic net salvage practice would likely outweigh any benefit to customers. Accordingly, the Board approves EDI s method of charging cost of removal less any salvage (i.e. net salvage) to the capital costs of the replacement asset Deprecation Expense Views of the Applicant EDI noted that its applied-for depreciation expense was described in section 8 of the Application. 233 In support of its depreciation expense, EDI conducted and filed a Technical Update 234 prepared by Mr. Urban, EPCOR s Capital Assets Accounting Manager, which included a detailed description of the methodology used by EDI to determine its applied-for depreciation expense. EDI noted that Mr. Spanos, Vice President of Gannett Fleming Inc., provided evidence confirming the reasonableness of EDI s approach, as well as the reasonableness of EDI s applied-for depreciation expense and the parameters used in its determination Tr. pp Tr. p Tr. pp Exhibit Application, Appendix A Application, Appendix O; PICA-EDI-50 and UCA-EDI-24 EUB Decision (August 13, 2004) 129

136 EDI stated that it was in the process of implementing a more traditional approach, which included the development of a property unit catalogue and continuous property register, which would allow EDI to carry out a depreciation study for its next DT Application. The depreciation study was currently underway. EDI stated that its approach to determining its depreciation expense for the purposes of this proceeding was reasonable and appropriate, and that it would make no sense to make any significant changes to the parameters underlying EDI s depreciation expense, including average service lives, until its next GTA when the Board would have the benefit of EDI s depreciation study. EDI also noted that the CAR study demonstrated that the financial records maintained by EDI were reasonable in respect of the value of assets in the field. EDI noted that the EPCOR IG $88,376 recommended reduction was, in fact, incorrect and, instead, what Mr. Pous actually recommended was $15,569. EDI noted that this was derived by first taking the total applied-for depreciation expense for EDI s wires assets of $10,826, and subtracting the depreciation expense for the contributed capital wires assets of $1,712,993, 237 which yielded a net depreciation expense of $9,113,659 for these assets. Second, from Mr. Pous revised Schedule JP-1 from his Opening Statement, EDI took Mr. Pous computed depreciation expense for EDI s wires assets of $10,945,404 and subtracted his computation of the offsetting contributed capital wires depreciation expense of $1,816,176, which yielded his recommended net depreciation expense for wires assets of $9,129,228. EDI stated that the difference between these two amounts was a $15,569 increase to EDI s applied-for depreciation expense for these assets. EDI noted that EPCOR IG appeared to have abandoned even Mr. Pous revised recommended changes to the ASLs for EDI s wires accounts. After stating that Mr. Pous revised recommendations result in a decrease of only approximately $88,000 to EDI s applied-for depreciation expense (which, as described above, is really a $15,569 increase to EDI s appliedfor depreciation expense), the EPCOR IG suggested that the issue is still significant due to future considerations. 238 EDI noted that the EPCOR IG s central concern was now with the ASL applicable to FERC Account 367 for Underground Cables (which is the ASL used for EDI asset accounts 23133, 23134, and 23145), in that the EPCOR IG asserted that both Mr. Pous and EDI s recommended ASLs for these assets may be too short, and suggested that the Board should order EDI to analyze and present in its next depreciation study a full investigation into its historical purchase and installation of different types of underground cable with corresponding dollar values. EDI noted that the EPCOR IG went on to state that, Armed with such critical information, the Board will be better informed when establishing the appropriate EDI specific average service life associated with underground cable investment in the next proceeding. EDI submitted that the only reasonable interpretation of the EPCOR IG s comments was that the EPCOR IG was no longer requesting any changes to the ASLs or EDI s applied-for depreciation expense relating to EDI s wires accounts, but was instead requesting that the Board direct EDI to include in its upcoming depreciation study an investigation into its underground cable assets Schedule D in EDI s Application Schedule D in EDI s Application EPCOR IG Argument. p EUB Decision (August 13, 2004)

137 EDI agreed that the Board should approve EDI s depreciation expense for its wires accounts as applied-for in EDI submitted that the specific assertions made regarding the ASL applicable to EDI s underground cable assets were puzzling and based on fundamentally flawed reasoning. EDI noted that the revised evidence of Mr. Pous actually recommended a lifespan of 36 years for these assets (which was lower than the 38-year lifespan proposed by EDI) and that the EPCOR IG indicated that the assets likely had a lifespan that was significantly longer than that recommended by Mr. Pous, demonstrating that even the EPCOR IG conceded that Mr. Pous analysis was inherently flawed and unreliable. EDI noted that these assets would naturally be included in the depreciation study that it had committed to carrying out for its next DTA. EDI submitted that there was no reasonable basis, either in the fundamentally flawed analysis of Mr. Pous or anywhere else on the record that would demonstrate that the investigation suggested by the EPCOR IG would be useful or even relevant to the issue of depreciation and that, at any rate, EDI did not have the detailed records necessary to conduct a historical purchase and installation study of these assets. EDI stated that the relevant issue for the purposes of depreciation was the assets that were currently in service, and these would be included in EDI s upcoming depreciation study. EDI noted that Mr. Pous asserted that the lifespan of EDI s minor computer systems should be extended to a minimum of 10 years 239 based on his claim that EDI s choice of a 6-year lifespan was arbitrary. EDI submitted that the record showed that EDI s approach to determining appropriate lives for computer assets was logical and appropriate. EDI stated that the 6-year period was consistent with the EUB s previous determinations, 240 and Mr. Cowburn had provided evidence as to the analysis that must be undertaken to determine whether any changes to the lifespan of EDI s computer assets would be warranted. 241 EDI submitted that Mr. Pous had not conducted such an analysis, and it would be unreasonable to make the changes Mr. Pous suggested. EDI disagreed with the EPCOR IG assertion that EDI s applied-for depreciation expense for Account should be reduced by $545,630 for 2004 on the basis that the amortization period applicable to the assets should increased from 6 to 10 years for a number of reasons: With respect to the EPCOR IG assertion that Mr. Cowburn s evidence with respect to the importance of maintaining technologically current workstation assets accounted for only $1.2 million of the $8.7 million in Account 23127, EDI stated that it was clear from Mr. Cowburn s Rebuttal Evidence that his testimony dealt with both the $l.2 million referred to by the EPCOR IG, as well as the $3.6 million which the EPCOR IG references as other items in this account. The EPCOR IG also claimed that EDI s justification for a 6 year amortization period for the $3.9 million in the Account for Y2K assets is limited to the unsupported statement that it provides an appropriate recovery period that reasonably minimizes intergenerational inequity Pous Evidence, p. 15 Application, section 8.2 Cowburn Rebuttal, pp. 4-6 EUB Decision (August 13, 2004) 131

138 EDI stated that contrary to the EPCOR IG s position, the record demonstrated that all of the assets comprising this account were small (i.e., less than $1 million) assets and, barring any compelling evidence to the contrary, should continue to be treated in accordance with the Board s previous determination that a 6 year amortization period was appropriate for these assets. EDI stated that neither the EPCOR IG nor Mr. Pous had provided any rational or compelling basis for changing this approach. EDI refuted the EPCOR IG argument that the lifespan of this Account should be increased based on the fact that Mr. Spanos of GF has proposed longer amortization periods elsewhere. EDI noted that neither the EPCOR IG nor Mr. Pous proffered any evidence or analysis which would support the comparability of the assets in Account with the assets of the other utilities referred to, and furthermore, the EPCOR IG neglected to mention Mr. Spanos evidence on this issue 242 that in the majority of cases in which I have recommended amortization periods for Information Systems, my recommendation has been for 5 years. In the cases that a longer amortization period was recommended, the assets were considerably larger. EDI also refuted the EPCOR IG assertion that Mr. Pous evidence reflected information of what the industry has proposed as EDI was unaware of any such information provided by Mr. Pous on the record of this proceeding. EDI stated in summary that the record clearly demonstrated the rational and logical basis for EDI s selection of appropriate amortization periods for its general plant assets, as well as the type of study that should be undertaken before any changes were made. Views of the Interveners EPCOR IG EPCOR IG noted that given the modified positions of EDI and EPCOR IG, the net result was an $88,376 difference in recommended depreciation expense for the wires accounts and a $545,630 difference for Account 23127, I/S software investment. 243 The EPCOR IG submitted that there were two functional plant areas at issue remaining to be decided. With respect to EDI s wire function, EDI noted that while the dollar difference between EDI and EPCOR IG for the wires function was now minimal (only approximately $88,000 absent EDI s effort to also change plant balances when a depreciation life parameter was changed), the issue was still significant due to future considerations. EPCOR IG stated that the key reason that such minimal difference still had significance was the short average service life utilized for FERC Account 367-Underground Cable. While both EDI and EPCOR IG relied on limited comparative industry data in order to establish the average service life to be utilized for this type of investment, the results for many of the utilities relied on were from older depreciation studies. 244 EPCOR IG noted that EDI s investment in this type of Spanos Rebuttal, Q.31 Exhibit , Opening Statement for the wires function recognizing the contributed capital credit component of the depreciation calculation and the remaining $8.7 million of minor software that EDI still requests a 6-year amortization. Response to PICA-EDI-26 and EUB Decision (August 13, 2004)

139 plant was over one-third of the total of EDI s wire investment associated with underground cable, 245 and the longer average service life associated with newer types of underground cable utilized by utilities meant that older depreciation studies may very well not reflect the correct life indicative of the newer, advanced underground cable. 246 EPCOR IG stated that if EDI s investment in underground cable was more current than that reflected in the older depreciation studies reviewed, then the average service life utilized by both EDI and EPCOR IG were too short. EPCOR IG stated that to the extent that EDI s correct average service life for underground cable should be greater than 40 years, it would have a material impact on the appropriate level of depreciation expense for EDI. While it is not quantifiable at this point in time, EPCOR IG urged the Board to order EDI to analyze and present in its next depreciation study a full investigation into its historical purchase and installation of different types of underground cable with corresponding dollar values. EPCOR IG submitted that armed with such critical information, the Board would be better informed when establishing the appropriate EDI specific average service life associated with underground cable investment in the next proceeding. EPCOR IG recommended an increase in the length of the amortization period from 6 years to 10 years for EDI s investment in Information System (I/S) software Account but noted that as the proceeding progressed, both EDI and EPCOR IG modified their positions. EPCOR IG stated that EDI modified its position in the rebuttal testimony of Mr. Cowburn where EDI identified $12.1 million of I/S software in Account as major software and proposed to extend the requested amortization period from 6 years to 10 years. 248 EPCOR IG noted that the remaining $8.7 million of investment in Account was categorized by EDI as now constituting minor software investment 249 and that EDI proposed to retain its original 6-year amortization period for such investment. 250 EPCOR IG submitted that with respect to the remaining I/S software investment issue, the Board must decide whether EDI has met its burden of proof to utilize a 6-year amortization period for the remaining $8.7 million of investment at issue. EPCOR IG stated that in defense of its modified position, EDI argued that it could not have effectively prepared, managed and accessed regulatory filings using 6-year old computers, and that a 6-year amortization period for its investment in Y2K hardware and software was appropriate in that it reasonably minimized intergenerational inequity. 251 EPCOR IG noted, however, that Mr. Cowburn also admitted that (1) EDI s reclassification was not in its main application, (2) its rebuttal evidence also fails to present any specific criteria for its new major and minor classification of investments, and (3) the only identifiable support for EDI s position is what it understood to be implicit in prior Board decisions Exhibit , Accounts 23133, 23134, 23135, and response to PICA-EDI-29 Tr. pp Exhibit , pp Exhibit , pp. 2-6, and response to PICA-EDI-48 Id. Exhibit , pp. 3-4 Exhibit , Cowburn rebuttal, pp. 3 and 4 Tr. pp EUB Decision (August 13, 2004) 133

140 EPCOR IG submitted that EDI had failed to adequately support its position. EPCOR IG stated that Mr. Cowburn s reference in his rebuttal testimony to the workstation that must be based on current and modern technological advancements to enable EDI to perform rate cases failed to recognize that only $1.2 million of the $8.7 million remaining at issue was associated with such category of investment. 253 Moreover, within the $1.2 million, EDI failed to identify what portion may be associated with printers, monitors, or other investment that were not directly associated with the need for newer CPU components or multi-gigabyte disc drives or CD-Rom burners referenced in his rebuttal. EPCOR IG stated that all that was available from EDI was that something less than $1.2 million of the remaining amount fit into the category that it claimed was truly associated with investment that should have 6-year or shorter average service lives. In fact, EDI s basis for the remaining portion of the $8.7 million at issue was either totally nonexistent or minimal at best. EPCOR IG also noted that the Y2K investment comprised $3.9 million of the $8.7 million of minor system software. As previously noted, the Company s total support for its efforts to retain a 6- year amortization period for this investment was that it provides an appropriate recovery period that reasonably minimizes intergenerational inequity. 254 EPCOR IG stated that this simple, unsupported statement highlighted EDI s lack of basis for its position, and obviously, the Y2K related efforts undertaken by EDI to prepare its software systems in order to be able to operate in the 21 st Century were still in place, and were still a used and useful investment. EPCOR IG submitted that to arbitrarily assign a 6-year amortization period without adequate basis was inappropriate and must be denied. EPCOR IG stated that the remaining portion of the $8.7 million was associated with a category called Other in the amount of $3.6 million 255 EDI s rebuttal only stated that the current Board practice of a 6-year life span is already at the high end of the reasonable range of service lives for these assets. 256 EPCOR IG submitted that EDI had even failed to identify what actually comprises the $3.6 million in the other category, and. EDI s statement referencing small budget capital projects did not support a 6-year amortization period when it was entirely possible that the investment may be used and useful for 10 or 15 years. EPCOR IG submitted that the only credible evidence was that of its witness. EPCOR IG stated that Mr. Pous recommendation on this matter was that a minimum 10-year amortization period was appropriate, and that his evidence reflected the reality associated with Y2K investment, information of what the industry had proposed, EDI s historical investment that was more than 6 years old but still in service, and the fact that Mr. Spanos of GF had proposed longer amortization periods elsewhere. 257 EPCOR IG stated that EDI had not shown in this record that a 6-year amortization period was appropriate for the remaining investment in what it now categorized as minor computer systems, and in fact, after given the opportunity EDI did not even identify what was reflected in Response to PICA-EDI-48 (a) Exhibit , Cowburn rebuttal, p. 4, lines 6 and 7 Response to PICA-EDI-48 Exhibit , Cowburn rebuttal, p. 3, lines 23 and 24 Exhibit at pp EUB Decision (August 13, 2004)

141 the vast majority of the remaining minor category other than to label it Y2K or Other (PICA- EDI-48). The EPCOR IG submitted that there was no recorded evidence of any meaningful analysis performed by EDI to demonstrate what was an appropriate lifespan for the remaining investment in the new minor category, and urged the Board to accept Mr. Pous recommendation of 10 years, a lifespan level that Mr. Spanos has supported in other jurisdictions (Exhibit 9-01 at p. 16). Views of the Board With the respective modifications to the positions of EDI and the EPCOR IG noted above, the Board finds that there is no material difference between the positions of EDI and EPCOR IG respecting EDI s wire accounts. The Board has reviewed the proposed EDI ASLs and considers them to be reasonable. Accordingly, the Board approves EDI s applied-for ASLs and resulting depreciation expense relating to EDI s wires accounts. With respect to an appropriate amortization period for computer hardware and software investment, the Board has reproduced the table provided in PICA-EDI-48 to illustrate the breakdown of the asset investment in Account 23127: Table 15. EDI Investment in Information Software Account ($ Millions) Initiative Basis for Justification Hardware Software Total Workstation Purchase workstation for new employees Replace obsolete workstations. Replace inoperative workstations not covered under warranty. Y2K An initiative undertaken to ensure EDI was Y2K compliant. Meter Data Management / Assets required by regulation for Settlement Settlement/Other Regulatory Compliance Projects (RDS, AESO, Hub, MDM, Remote, AEUB Tariff). Other Numerous small budget capital projects Total EDI proposed the use of a 6-year amortization period for the minor assets in Workstations ($1.2 million), Y2K ($3.9 million) and Other ($3.6 million). Subsequent to the preparation of the above table, EDI transferred the investment in Meter Data Management/Settlement/Other ($12.1 million) to a separate Account with a place-holder amortization period of 10 years. The Board is not persuaded that the amortization period for the remaining EDI investment in Workstations ($1.2 million), Y2K ($3.9 million) and Other ($3.6 million) should be increased from 6 years to 10 years as recommended by the EPCOR IG. Based on the evidence of EDI, the Board considers that these assets fall into the minor category for which a 6-year amortization period is reasonable. Accordingly the Board approves EDI s proposed amortization periods of 6 years for minor assets and 10 years for major EDI investment in IS software. However, the Board agrees with the EPCOR IG that the depreciation expense calculated by EDI is too high by approximately $536,000 since it appears that EDI did not revise its proposed depreciation expense of EUB Decision (August 13, 2004) 135

142 $2,721,805 for Account 23127, in its revised schedules, to reflect the 10-year amortization of major IS software agreed to by EDI for Accordingly, the Board directs EDI, in its refiling, to revise the proposed depreciation expense for Account to reflect EDI s proposed amortization periods of 6 years for minor assets and 10 years for major EDI investment in IS software. 7.5 Other Views of the Applicant EDI noted that it did not explicitly deal with various areas of concern addressed by Mr. Pous because they largely had either no sound basis in reason or evidence, or the evidence already on the record provided an ample response. EDI was confident that the Board would assess these recommendations carefully and reject those that clearly constituted fishing expeditions for largely irrelevant and unhelpful information. EDI noted that redistribution of the reserve was approved by the Board in Decision U99099 in the context of Edmonton Power Generation Inc. (now EPCOR Generation Inc.) and Edmonton Power Transmission Inc. (now EPCOR Transmission Inc.). EDI further noted that Mr. Spanos made the following comments on the practice of redistributing the reserve (Exhibit , Spanos Rebuttal, pp ): 42. Q. Please describe the redistribution of the reserve imbalance? A. The current depreciation rates for EDI are based on the average life group and whole life method. The whole life method determines a depreciation rate without consideration of the level of accumulated depreciation. This practice requires a comparison of the theoretical reserve with the actual book reserve to insure full recovery of the assets -- no more, no less. Consequently, the actual annual depreciation expense by account is the summation of the whole life depreciation amount and the redistribution of the reserve. The result of this methodology produces a relatively constant overall expense and will provide an appropriate level of accumulated depreciation by account at the time that EDI files a complete depreciation study. Where the imbalance is less than the standard 5 percent variance, then no redistribution for the account is undertaken. EDI stated that its approach to redistributing the reserve in respect of its 2004 Technical Update was in keeping with the Board s comments with respect to the practice described in Decision U99099 and with the sound depreciation practices as noted by Mr. Spanos. Further, EDI submitted that there was no evidence supporting the EPCOR IG s assertion that redistributing the reserve results in increased costs, and to the contrary, the information provided in EDI s response to EDI-PICA-37 demonstrated that EDI had mechanized the process of redistributing the reserve and was able to provide the spreadsheet to the Board and interested parties used for that process, making it easy and inexpensive for other parties to assess both the process and the results. Finally, EDI submitted, there was no evidence demonstrating that the redistribution of the reserve creates any intergenerational inequities as claimed by the EPCOR IG as the evidence demonstrated instead that the reserve was redistributed within functions, consistent with the Board s comments in Decision U EDI refuted the EPCOR IG s comment that the redistribution of the reserve changes the recovery pattern from the remaining life associated with the actual investment to the remaining life of the investment in a different account because 136 EUB Decision (August 13, 2004)

143 as EDI uses a whole life technique, the whole life depreciation rate of an asset account is based upon the average service life ( ASL ) only. EDI stated that the redistribution of the reserve impacts only the amortization of the reserve imbalance rate, and by redistributing the reserve the difference between the calculated and actual reserve for each asset account was minimized, and this in turn minimized the changes in the rate to amortize the reserve imbalance. 258 EDI stated that redistribution of the reserve does not change the recovery pattern of the investment in the asset but rather ensured that the depreciation rate impact of the recovery of the reserve imbalance was consistent within each function. 259 EDI stated that Mr. Pous suggestion that EDI be required to perform a comprehensive and detailed analysis in respect of the curve generated retirements was entirely refuted by EDI s initial Application, as well as the discussions during the hearing respecting the continuation of the approach EDI has historically used respecting net salvage. (Tr. pp ) EDI noted in section 8.1 of its Application that beginning this year, EDI was proposing to track and book its actual experienced retirements at their estimated original cost, consistent with the procedures approved by the Board for other utilities. EDI further stated that Mr. Pous suggestion that the Board should direct EDI to report on the changes to its capitalization policy over the history of its assets would obviously serve no helpful purpose. EDI stated that while EDI shared the Board s concern over accurately computing and recovering its rate base in service, a study of what EDI s capitalization policies had been over the past half dozen decades would be completely unhelpful in reaching that objective. With respect to Mr. Pous recommendations relating to the re-use of assets (which are rare in the case of EDI (PICA-EDI-39) and reimbursed retirements, EDI stated that both of these topics will be addressed through the property unit catalogue now under development by EDI and, as such, could be addressed in the context of EDI s next DTA. With respect to Mr. Pous suggestion that EDI be required to supply all necessary and appropriate information to perform a review of the depreciation parameters to be filed at or before its next filing, EDI noted that it had made the commitment to undertake a depreciation study. EDI stated that study would be filed in its next DTA and, if the relevant information that interveners believe they require to analyze EDI s applied-for depreciation rates could be found in that study, then interveners could ask for it through the IR process. EDI submitted that prior to directing utilities to develop a uniform system of accounts, the Board should first give careful consideration to the significant costs that would be incurred in the short term versus the benefits that would potentially be realized over the longer term. EDI stated that it would be pleased to participate in any study initiated by the Board in this regard and that it would, of course, abide by any directions the Board ultimately determined to be appropriate. Views of the Interveners The EPCOR IG submitted there were a number of areas associated with depreciation analyses before the Board that could result in lower costs without going to the most simplistic approaches. EPCOR IG noted that in the area of life analysis, the cost to gather and verify the underlying base data could be significant due to its severe time requirements, and if a standard depreciation EDI Application, Appendix A, p. A-2 Spanos Rebuttal, Q.42 EUB Decision (August 13, 2004) 137

144 analysis approach was to be employed, some party had to perform this analysis, and then that entity should be an applicant in a rate proceeding. EPCOR IG stated that it was not cost effective for each intervener and possibly the Board to recreate the database in a usable format in order to then test, develop and observe life table (actual historical survivor patterns). EPCOR IG stated that once the data was in the applicant s computer system, the creation of life tables based on various experience and placement bands was not a costly undertaking. EPCOR IG noted that if applicants were required to perform a reasonable number of well thought out series of actuarial or semi-actuarial analyses to develop and observe life tables, it would significantly reduce the overall cost of investigation into the appropriateness of the assumed or proposed average service life and corresponding survivor curve by the applicant. EPCOR IG submitted that the Board order applicants to provide on electronic medium in Excel or Lotus readable format the output of the reasonable number of well thought out series of actuarial or semi-actuarial analysis. EPCOR IG stated that the subsequent curve matching analysis by Board or interveners was not a time consuming or costly process, and that in addition, the Board should order each applicant to provide on electronic medium in Excel or Lotus readable format the surviving balance by vintage, by account. EPCOR IG stated that in this manner, both the Board and interveners could easily calculate remaining lives and theoretical reserves based on their selected average service lives and corresponding dispersion patterns, if different. EPCOR IG stated that another activity undertaken by EDI that resulted in increased costs and a further creation of intergenerational inequities was the redistribution of the reserve. EPCOR IG stated that the process of redistributing the reserve adds cost to the entire process and changes the allocation of costs over time since different accounts have different remaining lives, and when the reserve is redistributed among the various accounts, it changes the recovery pattern from the remaining life associated with the actual investment to the remaining life of the investment in a different account. EPCOR IG stated that therefore, not only was it more costly to perform the redistribution of the reserve, it was also inappropriate to perform such analysis. EPCOR IG stated that another complexity not employed frequently outside of Alberta was the reliance on a technical update, since the theoretical increase in accuracy obtained from such calculation was most likely not significant over short periods of time. EPCOR IG stated that the alternative of simply retaining the existing depreciation rate without modification in between rate applications until a full depreciation study was performed eliminated the effort and controversy associated with technical updates. EPCOR IG stated that in the area of net salvage, many complications can and do exist. The quantification and treatment of reuse material, the treatment of reimbursed retirements, and the allocation of costs incurred in the replacement of an asset between the cost of a new addition and cost of removal were but a few of the complicating issues that arise in standard or traditional net salvage analyses, 260 and to the extent that proper safeguards were put in place, EDI s approach of rate base treatment outside of the reserve would reduce costs in rate proceedings. 260 Exhibit , pp EUB Decision (August 13, 2004)

145 Views of the Board The Board considers that EDI s approach of redistributing the accumulated reserve in its technical update was appropriate and notes that the redistribution minimizes any adjustment required to bring the actual reserve into line with the theoretical reserve on an account-byaccount basis. The Board notes that reserve adjustments may not be necessary under the basic form of a simplified depreciation method. Similarly, the Board considers that the issue of curve generated retirements may not arise under the basic form of a simplified depreciation method. The Board also notes that a rigorous actuarial study of the pattern of past retirements may not be necessary under the basic form of a simplified depreciation method. The Board notes that Mr. Pous recommendations relating to the re-use of assets will be addressed through the property unit catalogue now under development by EDI and, as such, can be addressed in the context of EDI s next tariff application. The Board agrees with EDI that a direction to EDI to report on the changes to its capitalization policy over the history of its assets would serve no helpful purpose. 8 RETURN ON RATE BASE 8.1 General EDI indicated that for the purpose of developing its applied-for revenue requirement and distribution rates in this DTA, EDI has used the capital structure and rate of return on equity reflected in its evidence filed in the GCOC proceeding - a capital structure comprised of 45% common equity and 55% debt, and a return on common equity of 11.0%. Based on a 7.55% weighted average cost of debt, EDI s forecast weighted average cost of capital was 9.10%. This translates into a forecast return on rate base of $27.3 million. 8.2 Cost of Equity and Equity Ratio Views of the Applicant EDI submitted that the issue of the return on EDI s distribution rate base would be revisited once the GCOC decision is released. Views of the Board The Board issued Decision in the GCOC proceeding on July 2, 2004, after the record of the present Application had closed. In Decision , the Board determined that a generic rate of return on common equity of 9.60% would apply for The Board also approved a common equity ratio of 39% for EPC Distribution, deeming the balance of 61% to be financed by debt. The Board concluded that the same ratio should apply to EDI Decision , p. 31. This rate of return will be subject to annual adjustment according to the mechanism also approved in Decision Decision , p. 53 EUB Decision (August 13, 2004) 139

146 Therefore, the Board directs EDI, in its refiling, to use a rate of return on common equity of 9.60% and a capital structure of 39% equity and 61% debt as determined in Decision Cost of Debt and Debt Ratio Views of the Applicant EDI indicated that it applied for approval of the addition of $12.5 million in debt costs based on a forecast weighted average cost of debt of 7.55% in EDI filed information describing the details of its debt cost rates in section 9.2, and Schedules D-24 and D-25 of its Application, and provided further information in PICA-EDI-73 and 74, S105-EDI-9, Exhibits , 53 and 95. EDI responded to questions regarding the lack of debt issues between 1981 and 1999 in Exhibit , indicating that there were several debt issues between 1981 and 1999, but that all have been retired and, as a result, are not shown in Schedule D-25. EDI indicated that, to determine its debt rates for its EDI 0001 and EDI 0002 issues, EDI used a stand-alone debt rating provided by Dominion Bond Rating Service and performed its own market tests to ensure that the debt rates charged by EUI are competitive. 263 As described by Mr. Grimes EDI bases its debt issue on current market conditions: Q. Well, perhaps you can comment on how appropriate a sample is that s based on yields or quartered for a single day? A. Mr. Grimes: This is based on a report provided by RBC Capital Markets, dated September 22 nd. Like I said, we re trying to match the current market conditions with our current time frame of issue. You issue debt on a single day, so it would be appropriate to use the most current information, which is what we did. 264 EDI provided two RBC Capital Markets reports, dated September 22, 2003 and October 31, 2003, in Exhibit EDI s witnesses confirmed that each issue included 5 basis points for issue costs, which are real costs. 265 EDI submitted that its forecast debt issue cost in respect of its 2004 debt issue set out in PICA- EDI-74 showed that the forecast interest rate was based on a logical and reasonable methodology using readily available market information. Further, EDI provided support for its A credit rating in a DBRS report provided in IPCAA-EDI-14 Attachment. EDI noted that the report states: The A rating for EDI is based on forecasts provided, which includes the movement to cost of service regulation by the EUB with an ROE of 11.0% and a 45% equity base in its capital structure. Should EDI s financial profile become materially weaker that forecast under the new regulatory regime, a lower rating may be warranted. EDI submitted that the outcome of the Generic Cost of Capital Proceeding might justify a higher forecast debt rate if it results in a reduction to EDI s credit rating Tr. p Tr. p Tr. pp EUB Decision (August 13, 2004)

147 EDI submitted that the record clearly established that EDI s applied-for debt rate and debt costs for 2004 were reasonable and prudent. In reply EDI noted that the CG argued that the Board should reduce the rates applicable to EDI s October 31, 2003 and forecast December 31, 2004 to reflect a 105 basis point spread over long Canada benchmark bonds. EDI submitted that the method used to determine the debt rate for the forecast December 31, 2004 issue was illustrated in PICA-EDI-74. Further, EDI has provided clear evidence that its debt rate for its October 31, 2003 issue was determined based on market conditions at the time EDI issued its debt, using a comparative sample of other A rated utility companies. EDI submitted that it had provided compelling evidence as to the reasonableness of this approach and the CG has pointed to nothing on the record that suggests the debt rate that would be applied to a debt issue by EDI into the market place would be determined in any other manner. EDI also submitted that, in attempting to support the recommended reduction to EDI s appliedfor debt rates for these issues, the CG made a number of assertions which have no basis whatsoever in the record of this proceeding. For example, the CG asserted that EDI s estimates of the spread between long Canada bonds and A-rated corporate bonds were questionable for two reasons. First, the CG observed that the spreads were calculated at a point in time. The CG then asserted that those spreads may not be reflective of the normal market spread between A rated bonds and long Canada bonds over time, claiming that the spreads applicable to particular bonds were likely to vary from day to day based on the market s risk perception of the particular stock at the time. The CG submitted that a longer term view would smooth out these day to day variances. EDI submitted that there is absolutely no evidence on the record to support any of these assertions and that the CG s comments were in substance evidence which were not proffered by any witness for the CG and, as such, could not have been, and have not been, tested through information requests and cross examination. Furthermore, the CG assertions were replete with terms and phrases that are unclear and undefined, and which demonstrate that the CG s assertions cannot be relied upon. For example, the CG provided no definition for the term normal market spread, and yet what is meant by this term is absolutely key to its assertions. Does normal mean over some defined period of time, such as a week, a month, a year, 5 years? Does normal market spread have any generally accepted meaning, or for that matter does it have any import whatsoever, among participants in the debt market, such as those lending institutions that determine the debt rate applicable to a corporation seeking to borrow funds? Similarly, what is meant by longer term view? Similarly, EDI submitted that the CG provided no evidentiary basis for its comments that the market s risk perception of A rated bonds is not likely to change depending on whether it is viewing a utility stock or some other stock and a larger sample including corporate stock should have been referenced for the spread calculation. Again, those comments are in substance evidence which was not appropriately proffered by the CG in this proceeding. Having been led in argument, these comments constitute unsubstantiated innuendo and should be rejected as such. Based on its unsubstantiated assertions, the CG then makes the completely unsubstantiated and outrageous accusation that EDI appears to be attempting to use selective market data to achieve a certain outcome - that is, its applied-for 130 basis point spread. EDI indicated that it EUB Decision (August 13, 2004) 141

148 trusted that the Board would see through the CG s unsubstantiated assertions and accusations and, instead, base its determination on the clear and compelling evidence that EDI has put on the record of this proceeding. Finally, EDI submitted that the approach recommended by the CG clearly demonstrates the lack of logic in, and inherent unreliability of, its argument. Instead of basing EDI s debt rates for the two issues on the spreads applicable on the day in question, the CG suggested that it would be completely appropriate for the Board to go back five years to an EDI debt issue in 1999 and use the 105 basis point spread that was applicable then. The CG provided no rational basis for this suggestion, including such things as the relevance that this previous debt issue may have to the market conditions applicable to the debt issues in question. EDI submitted that based on the evidence that is on the record, EDI s applied-for debt rates and debt costs for 2004 are reasonable and should be approved by the Board. EDI noted that the CG concluded its argument in this section with the comment that given the uncertainties associated with imputing a debt rate on a notional basis the CG submits EDI should be directed to investigate the feasibility of EUI mirroring down specific future debt issues made on behalf of EDI, or any other affiliate. EDI indicated that it was not aware that the Board has abandoned its historical adherence to the stand-alone principle in circumstances such as those involving EDI. EDI submitted that the CG had provided no reasonable basis on which the Board should abandon that principle, and submitted that the Board should disregard the CG s suggested investigation. Views of the Interveners CG The CG noted that EDI s long-term borrowings were represented by debt instruments issued to EUI. Since EDI does not access the bond market directly the debt coupon rates are calculated by EDI based on prevailing market conditions. Schedule D shows a debt issue for $70 million on October 31, 2003 at a rate of 6.65% and a proposed new debt issue of $30 million on December 31, 2004 at a rate of 6.87%. EDI produced a variety of schedules showing how the above issue rates were calculated. In general, the rates for the EDI issues reflect the rate for a benchmark long Canada bond plus a spread of 130 basis points to reflect the risk differential between A rated corporate bonds and long Canada bonds plus a further a 5 basis points for issue costs. The CG noted that EDI in responses to PICA-EDI-74 and Exhibit showed how the 130 basis points spread was arrived at based on a review of spreads for sample A rated utility bonds, around the dates the long Canada bond rates were referenced. The CG noted that noted the sample companies used in the various calculations were not the same in each calculation. In CG s view, EDI s estimates of the spread between long Canada bonds and A rated corporate bonds was questionable. First, the spreads were calculated at a point in time and they may not be reflective of the normal market spread between A rated bonds and long Canada bonds over time. The spreads applicable to particular bonds are likely to vary from day to day based on the market s risk perception of the particular stock at the time. EDI acknowledged it had no information on the particular market factors affecting the reviewed utility stocks as of the 142 EUB Decision (August 13, 2004)

149 reference dates. 266 In the CG s submission a longer term view would smooth out these day to day variances. Second, the CG submitted that the sample selected for review was limited to certain utility stock and did not include a large enough sample to reflect a representative spread between A rated bonds and long Canada bonds. EDI indicated it did not consider it appropriate to include nonutility stock in the sample. 267 The CG disagreed with EDI s position that it is not appropriate to use non-utility A rated bonds in the spread calculation. In CG s submission the market s risk perception of A rated bonds is not likely to change depending on whether it is viewing a utility stock or some other stock. The CG submits a larger sample including corporate stock should have been referenced for the spread calculation. The CG submitted that EDI had not produced any credible evidence to demonstrate the requested spread between long Canada bonds and A rated bonds was as high as 130 basis points. Rather, EDI s selective use of market data appears to reflect an attempt to achieve a certain outcome; in this case a 130 basis points differential. In June 1999, EDI issued debt to EUI at a spread over long Canada bonds of 105 basis points. This rate appears to have been accepted by EDI s previous regulator. The CG submitted that in the absence of credible evidence that would indicate to the Board that the spread has increased since 1999, the spread used for calculating EDI s debt rates for the October 31, 2003, issue and the December 31, 2004 issue should not exceed 105 basis points. Accordingly the proposed debt rates should be adjusted as follows: Table 16. CG Recommended EDI Debt Rates October 31, 2003 December 31, 2004 Long Canada bond rate % 5.41% Spread for A rated bonds 1.05% 1.05% Issue costs 0.05% 0.05% EDI debt rate 6.51% 6.51% The CG submitted that, given the uncertainties associated with imputing a debt rate on a notional basis as above, EDI should be directed to investigate the feasibility of EUI mirroring down specific future debt issues made on behalf of EDI, or any other affiliate. The CG noted that a direct issue to the market could be expected to provide the utility the incentive to time its issues so as to minimize overall debt costs. In summary, the CG submitted that the 130 basis points spread over long Canada benchmark bonds for the debt issues in 2003 and 2004 was excessive and should be limited to a maximum of 105 basis points. Further, EDI should be directed to investigate the feasibility of EUI mirroring down specific future debt issues made on behalf of EDI, or any other affiliate Tr. p line 21 Tr. p. 1356, line 6 Exhibit Attachment 2 EUB Decision (August 13, 2004) 143

150 Views of the Board The Board considers that there are three primary issues in regard to the debt costs of EDI: Rate to be charged on, and amount of, EDI s long term debt issued under its former regulator. Rate to be charged on 2004 EDI debt issued under Board regulation. EDI s 2004 embedded debt cost rate calculation. Rate to be charged on, and amount of, EDI s long-term debt issued under its former regulator While the level of the interest costs for the capital portion of the rate base funded by existing debt is calculated annually, the Board normally looks at the level and term of long-term debt issues only once during the life of the debt issue. 269 In regard to the long-term debt that was issued prior to 2003, the Board does not have any evidence to suggest that EDI s former regulator did not approve an appropriate interest rate level and term. Accordingly, the Board will accept the interest rate levels and terms of debt issued prior to With respect to the forecast 2003 debt issue, on February 23, 2004, EDI provided an update indicating that $70,000,000 of new debt had been issued at 6.65% on October 31, 2003 (compared to the 6.80% debt cost rate in EDI s original forecast for this issue). Under normal circumstances the Board would have applied the same principles to the 2003 debt issue as set out below with respect to the 2004 debt issue, in approving the actual debt cost rate for the 2003 debt issue. However, in this case the Board will accept the cost rate of 6.65% and term of 20 years for the 2003 debt issue as having occurred under the previous regulatory regime. Rate to be charged on 2004 EDI debt issued under Board regulation The Board has some concerns with the EDI s approach of imputing a debt rate, as opposed to using an actual debt rate for debt issued to the market. Firstly, the Board considers there is some difficulty with determining the appropriate spread by analysis, relative to the use of an actual market debt cost. Secondly, the rating of a company that is not a stand-alone entity is the judgment of the debt rating agency only, and cannot be supported by comparing the costs of debt issued to the market by comparably rated companies. Lastly, there are costs for the determination of the stand-alone debt rating by the debt rating agency and the market tests performed by EDI and interveners, in addition to the hearing costs, to decide the appropriate spread over Canada bonds. The Board is not persuaded that it is appropriate to use an imputed debt rate for EDI debt issued under Board regulation. Accordingly, the Board directs EDI, in its next GTA, to provide evidence respecting EUI s actual cost rate of issuing the 2004 debt 270 including an appropriate allocation of any out of pocket issue expenses 271 passed down to EDI from EUI Typically at the first GTA following the year in which the debt is issued EDI stated that the 2003 bond was purchased entirely by EUI at Tr. p EDI stated that the issue costs for the 2003 bond was 5 basis points at Tr. p EUB Decision (August 13, 2004)

151 Further, the Board agrees with the CG that for future tariff applications, EDI should examine an appropriate method to allow EUI to mirror down actual, specific future debt issues made on behalf of EDI. The Board expects that using this approach, EUI can take advantage of economies of scale and make larger debt issues, which can then be allocated to EDI and other EUI subsidiaries. Accordingly, the Board directs EDI, in its next GTA, to examine an appropriate method to allow EUI to mirror down actual, specific future debt issues made on behalf of EDI. In regard to the debt forecast to be issued by EDI in 2004, the Board will determine a forecast cost based on the record of this Proceeding. As noted above, the actual rate of the 2004 debt issue is subject to examination in its next GTA. The Board finds no evidence that the 1.3% spread calculated by EDI using an average of utility spreads yields an unreasonable estimate of the debt cost rate used by EDI for the 2004 debt cost issue. Accordingly, for the purposes of determining a forecast 2004 debt cost rate, the Board accepts EDI s 2004 $30 million debt issue at a forecast cost of debt of 6.87% using the 1.3% spread and other components making up the forecast cost of debt for the 2004 issue as provided by EDI. EDI s 2004 embedded debt cost rate The Board must determine an appropriate embedded debt cost rate for 2004 for EDI to use on the deemed debt ratio of 61.0% as determined for both EPC and EDI in Decision On February 23, 2004, EDI provided an update reducing its forecast embedded cost of debt from 7.62% to 7.55% for The Board has examined EDI s calculation of its mid-year cost rate as set out in Schedule D-24 and D-25 of its Application and finds that the calculations are correct. Therefore, the Board approves EDI s forecast embedded cost of debt of 7.55% for Considering all of the above, the Board directs EDI, in its refiling, to use a debt cost of 7.55% as the rate for the 61.0% of EDI s rate base that was not deemed to be funded by equity per Decision DISTRIBUTION ACCESS SERVICE TARIFF 9.1 DAS Cost of Service General The Board will address the following three general DAS Cost of Service Study (COSS) issues in this section: Need for separate load profiles for Residential and Commercial rate classes Correction of Wholesale Billing costs in EDI refiling Use of Capital Asset Review in next EDI Cost of Service Study EUB Decision (August 13, 2004) 145

152 Views of the Applicant EDI stated that its Cost of Service Study, including the criteria, methodology and model used to complete the Study (described in detail in section 10.2 of EDI s Application) followed a typical approach (including determination of rate classes, then functionalizing costs, classifying costs and allocating costs) using logical criteria. EDI submitted that at each stage of the process, costs were directly assigned wherever possible (e.g., the costs associated with all distribution facilities serving customers at greater than 5,000 kv.a were directly assigned to those customers), and that once assigned, these costs were removed from the process to ensure that only those costs that could not be directly assigned were ultimately allocated among the appropriate customer classes. EDI noted that the methods used to functionalize costs by account were summarized in Table 28 in EDI s Application. EDI s witness commented that professional judgment was employed at the functionalization stage. EDI stated that it had classified each functionalized cost based on the categories set out in Tables 29 and 30 of the Application, and that no parties had taken issue with EDI s classifications. EDI noted that it had allocated each functionalized cost to rate classes having regard to the cost drivers identified at the classification stage, and that a detailed description of the allocation process was provided in section of the Application. EDI stated that Transformer, secondary, connections and meter costs were allocated to rate classes based on the RCN method, or the average replacement cost for each service category, EDI noted that parties had asked questions respecting several aspects of the RCN method, including the manner in which replacement costs were calculated and the veracity of the results. EDI stated that it had addressed these questions by filing its RCN Study in response to BR-EDI-18(b), and that the Study had confirmed that replacement costs were calculated in a rational and logical manner, and that the results of the RCN approach are fair and reasonable. EDI stated that Wholesale billing costs were allocated among rate classes based on the number of sites in each class. EDI noted that Interveners had questioned whether large customers should be allocated a higher per site billing cost. EDI further noted that load centre costs had been improperly allocated in its Application, and that its refiling in this proceeding would reflect the allocation of some $930,000 to the interval metered rate classes. EDI s witness also committed that EDI would investigate the weighting factor used for billing costs for its next GTA. In reply EDI submitted that the Settlement System Code (6.3(a)(1)(c)) required as an input Profile data (deemed and/or load research) if any profiling classes other than net system load shape (NSLS) are used. EDI noted that in the load settlement process, the NSLS was applied to all customer classes that did not have an interval meter or a predictable load. EDI noted the CCA contention that due to the potential for cross-subsidization, separate load shapes for residential and commercial classes would be desirable for EDI s next GTA. EDI stated that a study on this matter had been completed and the results were reported to the Settlement Specification Group. EDI noted that CCA acknowledged in its Supplemental Argument that the study confirmed that there was very little cross-subsidization between the residential and small Commercial rate classes using the NSLS, and that Exhibit indicated 146 EUB Decision (August 13, 2004)

153 that even under conditions of extreme price variations, the cross-subsidy of commercial by residential was only 3-4% annually. EDI noted that CCA itself had noted that the EUB has traditionally held the view that rates were generally considered reasonable as long as the revenue to cost ratio was within a +/- 5% range around 100%. EDI stated that the record demonstrated that in typical cases there was very little crosssubsidization between residential and commercial classes and that even in cases of extreme price variation, the resulting revenue to cost ratios would still be within Board accepted levels of +/- 5% of 100%. EDI therefore stated that EDI s use of NSLS in the settlement process for all customer classes that did not have an interval meter or a flat load was appropriate. EDI noted that it did not at present have a statistically valid residential load research sample that met the requirements of Schedule A of the Settlement System Code, nor had a capital proposal to install such a system been included in EDI s filing. EDI did state that there were a substantial number of residential sample meters in place, which would allow a statistical study such as that proposed by CCA to be carried out should the Board so direct. EDI also concurred with CCA that there was merit in further research into alternative methods of energy allocation, including subdividing the system into smaller, localized settlement zones with more homogenous customer types. EDI noted, however, that as EDI was implementing major changes in its settlement and billing software under the RDS project, as the EUB would soon require the implementation of a new tariff data format, and as the AESO was proceeding with the ELSI load settlement project, EDI resources that would otherwise be capable of carrying out this research were already heavily committed to these mandated, mission-critical projects. EDI submitted that this research might be more productively carried out during 2005 once these major market initiatives had been completed. EDI noted PICA s recommendation that EDI should be directed to file a cost of service study reflecting the results of the capital asset review (CAR) at its next GTA. EDI also noted PICA s suggestion that EDI should be able to demonstrate that ratios of RCN to embedded cost for different distribution property, by function, were reasonably consistent. EDI considered that there was merit in PICA s recommendation, but that there was no guarantee that a CAR based cost of service study would show any consistency between ratios of RCN and embedded functional cost for different distribution property. Views of the Interveners CCA The CCA noted that at the hearing EDI had confirmed that the Net System Load Shape (NSLS) was applied to all customer classes that did not have either an interval meter or have a flat load. The CCA stated that hence, for the Residential and small commercial (less than 150 kv) rate classes, the assumption was that these two rate classes have the same load shape or profile. CCA noted that the load settlement process was described in detail in Response CCA-EDI-37. The CCA s view was that in an ideal world it would be desirable to see a separate load shape for Residential and Commercial classes. The CCA stated that this would provide for clearer price signals and, as well, provide assistance in cost of service allocation process. EUB Decision (August 13, 2004) 147

154 The CCA noted that EDI suggested an interesting lower-cost approach (Tr. p. 2761), by assessing the physical connectivity of customers and settling by much smaller zones in the city. The CCA therefore recommended that the Board direct EDI to undertake a lower cost study, proposed by EDI, for purposes of EDI s next GRA. The CCA stated that to the extent the results of this study suggested a cross-subsidy, EDI should quantify such subsidy and if material, use the resulting separate load shapes for cost of service and rate design. In reply CCA noted that in Argument, EDI stated: Wholesale billing costs were allocated among rate classes based on the number of sites in each class. Intervenors questioned whether large customers should be allocated a higher per site billing cost. EDI noted that load centre costs had been improperly allocated in its Application, and that its refiling in this proceeding would reflect the allocation of some $930,000 to the interval metered rate classes. Mr. Cowburn also confirmed that EDI would investigate the weighting factor used for billing costs for its next GTA The CCA noted that EDI will correct its COSS to reflect the assignment of $930,000 of wholesale billing costs directly to interval metered customers, as opposed to being allocated under the EDI filed COSS to all customers, based on the number of customers. As well, the CCA stated that the Board should direct EDI to investigate the use of an appropriate weighting factor for billing costs, at its next GRA. PICA PICA noted that EDI s proposed functionalization of distribution plant is shown in Schedule DAS-2. PICA submitted that since plant records have not historically been maintained by function, considerable judgment had been used in arriving at the plant balances by function. PICA noted EDI s indication that it was currently carrying out a capital assets review. PICA noted that as a result of this review, EDI indicated it hoped to reconstruct distribution plant records from the bottom up. Specifically, EDI s witness had indicated that it will be a different buildup from the bottom up, rather than this allocation from the top down, using judgment and factors. PICA stated that EDI had indicated that the Capital assets review will help match the assets by vintage to the customer classes: And then we re going to start aggregating those pieces of property up and say, well, who uses these? Whoever uses them, as a group, should be paying for them. So that s the approach we'll use to building up this allocation process going forward. [Tr. p line 2] PICA stated that it was concerned that the 2004 cost of service study substituted judgment for sound plant records. PICA examined EDI as to whether or not any tests were carried out to assess the reasonableness of the judgments used: Q. When you used RCN values to allocate transformer secondary service connection and meter costs, did you not compare the RCN for these assets against the original cost for the corresponding assets? 148 EUB Decision (August 13, 2004)

155 A. MR. COWBURN: Right. And that would be doing the CAR comparison, and we just flat didn't have time to do that in preparation for this proceeding. What that would have meant would be filing a lot of late evidence and doing a whole lot of preliminary analysis, and I don't think it would have been helpful to the process. PICA noted EDI acknowledgement that if a proper study were carried out, the ratio of RCN to original cost would be consistent for each type of property: Further: Q. Would you expect the ratio of RCN to original cost to be fairly consistent for each of the functions of distribution plant? A. MR. COWBURN: I would be really interested to see. I think it might be. But that s the exciting thing about having a new toy, is you get to see what it actually is going to tell you. Q. Would you agree that such a comparison would be useful in testing the veracity of the functionalization and allocation of distribution plant? A. MR. COWBURN: Absolutely. PICA submitted that EDI should be directed to file a cost of service study reflecting the results of the capital assets review at the next GTA. PICA noted that EDI should be able to demonstrate the ratios of RCN to embedded costs for different distribution property, by function, were reasonably consistent. Views of the Board Need for separate load profiles for Residential and Commercial rate classes The Board notes CCA s submission that separate load shapes for the residential and small commercial rate classes would provide for clearer price signals and, as well, provide assistance in the cost of service allocation process. The Board also notes the EDI study (Exhibit ), which suggested very little subsidization between the residential and small commercial rate classes through the use of a combined Net System Load Shape (NSLS) for energy load settlement purposes. The Board agrees with EDI that that issues related to energy load settlement should await the development of the AESO ELSI load settlement project. The Board notes that the use of different residential and commercial load shapes for the allocation of distribution costs would likely result in on-peak and off-peak energy by rate class different than the on-peak and off-peak energy by rate class derived from the load settlement process and used for the billing of energy to customers. The Board is not persuaded that such a result would be an appropriate refinement to the distribution cost allocation process in the absence of a concurrent refinement to the energy load settlement. In other words, the Board considers that it is appropriate to use the same load shapes for the allocation of distribution costs as are used in the load settlement process. EUB Decision (August 13, 2004) 149

156 Correction of Wholesale Billing costs in EDI refilling The Board notes that all parties appear to be in agreement that EDI s load centre costs have been improperly allocated. In particular, the Board finds that $930,000 of load center costs should have been allocated to interval-metered rate classes. Therefore, the Board directs EDI to allocate $930,000 of load centre costs to the interval-metered rate classes as part of its refiling. The Board also directs EDI to review the weighting factors used for billing costs in its next GTA. Use of Capital Asset Review (CAR) in Next EDI Cost of Service Study The Board notes PICA s view that EDI be directed to file a COSS reflecting the results of the CAR in its next GRA. The Board also notes EDI s indication that this review should be available in time for use in its next GTA. The Board is also of the opinion that the use of the CAR would be a useful tool to be employed in EDI s next COSS. Therefore, the Board directs EDI to implement the CAR in its next GTA. The Board agrees with EDI that there is no guarantee that a CAR based cost of service study would show any consistency between ratios of RCN and embedded functional cost for different distribution property Use of On-Peak Energy to Allocate Primary Distribution Costs Views of the Applicant The purpose of the primary distribution system is to bring distribution access service along the roads and lanes in EDI s service area. The primary distribution system consists of distribution feeders that begin at an energy source, which may be the transmission point of delivery, distribution interface, or a distribution connected generator. The primary distribution system ends at the service connection or tap to serve a customer site or group of sites. The primary distribution system includes protective devices and switches on the distribution feeders. EDI stated that it had allocated each functionalized cost to rate classes having regard to the cost drivers identified at the classification stage and had provided a detailed description of the allocation process in section of the Application. EDI submitted that its approach was both reasonable and appropriate for the following reasons: This approach has been used by EDI since it was first approved by EDI s previous regulator in respect of EDI s 2001 DT. Peak energy as an allocator for primary costs has been used by other EUB regulated utilities (PICA-EDI-81(a)). EDI also noted that it had provided sound rationales for allocating 25% of primary system costs based on total energy and the other 75% based on peak energy in its response to PICA-EDI- 81(b). EDI also reiterated that it was not aware of any cons to using its approach as it had responded in PICA-EDI-81(c). 150 EUB Decision (August 13, 2004)

157 EDI noted that in response to PICA s suggestion that on-peak energy may not provide a strong signal for larger customers to manage demand, Mr. Cowburn pointed out that the signal EDI wanted to send to customers, in the interests of all customers, was an appropriate signal that caused them to be mindful of their use of the facilities during peak hours. EDI noted that the signal was not to attempt to have them micromanage their load in all hours to avoid a oneneedle spike, because that was not what affected costs on EDI s system. EDI noted that Mr. Cowburn had confirmed that a demand approach would be unreasonable and inappropriate in the circumstances. EDI further noted in Reply that the notion that on-peak charges were a reasonable proxy for demand was endorsed by the CCA in their argument. EDI also noted that PICA disagreed with EDI s position that a single peak does not drive the sizing of the system. EDI noted that PICA submitted that if a demand allocator could capture seasonal differences for the transmission interconnection charge, the same should be possible for the primary distribution system. EDI stated that its position was firmly grounded on its actual distribution planning practices, and had been explained by Mr. Cowburn during the hearing: So the planning that we do is driven by a broad understanding of what s going to go in that area. What kind of a load will it have. It s not incrementally sized any differently based on any behaviours we think we could rationally incent with rates. Again, because of the nature of our load, we don't get costs driving up and down enough to really change their planning decisions. So I don t think it s correct to say they plan to meet a specific single peak. It s a distribution system, remember. Transmission planners have very different concerns, because they're dealing with consolidated loads across a number of customers. When we're looking at a distribution system, you're looking at a feeder that isn t serving tens of thousands of customers; it may be serving hundreds. So it s a much more -- much smaller scale that we try to plan to, and it's much easier to plan for smaller units than big aggregated ones. EDI stated that PICA had failed to provide any evidence to refute EDI s position, namely, that a single peak did not drive the sizing of EDI s distribution system. EDI also noted that PICA calculated that the residential class cost responsibility based on peak energy was different than the cost responsibility based on NCP demand. EDI submitted that PICA s calculations merely demonstrated that the two methods were different (e.g. NCP is based on single needle peak whereas on-peak energy captures average use during the peak period). EDI stated that its position was not refuted by PICA s calculation. EDI also noted PICA s argument that EDI had not given adequate consideration to what was driving the minimum system costs, which could be the number of customers or the demand. EDI stated that in response to PICA-EDI-81(b), EDI had provided the minimum systems calculation that supported the basis for determining that 75% of the primary system cost was peak, as described in EDI s Final Argument. EDI submitted that there was no evidence to refute this conclusion or to support PICA s speculation that the drivers of minimum system costs were not considered by EDI. EUB Decision (August 13, 2004) 151

158 Views of the Interveners CCA In Reply CCA noted that PICA had recommended that the primary system costs should be allocated using feeder peak demand, as opposed to average demand during on peak hours, as this more closely reflected the sizing of the system or that alternatively, EDI should be directed to file a component cost analysis similar that approved by the EUB for ANCA. CCA noted that PICA s suggestion to use class NCP as opposed to on peak energy use was to affect a transfer of $6.824 million from all other rate classes to the residential customer class. CCA noted that PICA had provided the following in support of its position: Prior Board Decisions [e.g. AE 2001/02 DT Application called for 100% of primary distribution costs classified using demand]. With respect to ANCA s 2002/03 Phase 2 GRA, Board approved method referred to as the CAM, where on peak energy is not used except to allocate costs of shared transformers. A demand-based allocator captures seasonal differences for the transmission interconnection charge; similarly, the same allocator may be used to capture seasonal differences for the primary distribution system. Class NCP demand is a better proxy for feeder peak demand as it captures maximum use which drives plant sizing. The CCA had a number of concerns with respect to positions advanced by parties that on-peak energy was not an appropriate allocator. The CCA noted that as pointed out in Response PICA-EDI-81 (a), the on peak method had seen the light of day before the EUB on several occasions. CCA noted that it was the approved method for TAU s 1993 transmission access rates, Gridco s GTAs, and ANCA s 2003 DT, and the current 2002 ENMAX [Power Corporation] recently filed 2004 GTA used the average on-peak energy as an allocator for the primary systems or systems of analogous functionality. The CCA noted that even in the old EEMA days, the Board approved a 9-winter/3-non-winter method of allocating demand-related costs, in large part to recognize that system was not necessarily designed to meet the requirements of a single needle peak. The CCA noted that EDI s use of on-peak energy was based on a similar premise. The CCA noted EDI s response to PICA-EDI-81(e), where EDI stated: Depending on the nature of the demand at a feeder, the primary system will generally experience peak demand in both the summer and the winter. In addition, peak demand can occur at different times in a day and in different seasons. The sizing of assets for serving peak demand is not driven by a single needle peak but rather by a broader consideration of peaks in both the winter and the summer. On this basis, on-peak energy usage is an appropriate allocation for primary system costs. The CCA noted that in the most recent decision related to AltaGas Utilities Inc., the Board approved the modified partial plant method, and that under this method, capacity responsibility 152 EUB Decision (August 13, 2004)

159 (transmission, distribution and gas supply capacity costs) was assigned to customer classes based on the daily demands of each customer class for each of the 365 days in the year. The CCA stated that no evidence had been filed to suggest that 25% of the primary distribution system was with respect to the design of a minimum system to sustain the steady load at the off-peak levels. and that to suggest that all of the primary system costs should be allocated based on the demand allocator would not be correct. With respect to the other 75% of the primary system costs, the CCA agreed with EDI that onpeak energy was a reasonable and appropriate proxy for coincident feeder peak demand as it reflected the average demand during on peak hours. The CCA also noted that the on peak energy rate design had been in place since 2001, and had received customer acceptance during the years in effect. The CCA stated that the argument that a demand allocator be used ignored the underlying configuration and characteristics of the EDI system, as explained by EDI in the following exchange: Q. Would you agree the on-peak energy charge for primary distribution does not provide as strong a signal as a demand charge for larger customers, say, 150 to 5,000 kv.a to manage their peak demands? A. MR. COWBURN:.It depends on what you re trying to signal. In our service area, we very seldom have to expand any facilities once they re installed. It s usually reasonably straightforward to assess what s an area going to use, what kind of buildings are going to be there, and we don t find that we have spike peaks which are causing us to have to rebuild the facilities we put in place in the first place. That s because we have not a lot of air-conditioning load in a city like this, pretty far north, and we don t have much at all, any winter heating, so we don t have the kind of spikes that really drive people to have to upgrade distribution facilities. So the signal that we re trying to send to customers in our rates is, be mindful of your use of the facilities during the peak hours, but do not attempt to micromanage your peak load to avoid some one-needle spike, because that s not what affects our system. So the signal that we re trying to send is one of moderation, but we re not trying to send the kind of spike peak-related signal that a demand charge contains. I think a demand charge sends a signal, which is more than we need in our case, because it s really more of a facility allocation than a facility rationing signal we re trying to send. Further, EDI s evidence is that the facility planners do not plan for a specific single peak: Again, because of the nature of our load, we don't get costs driving up and down enough to really change their planning decisions. So I don't think it's correct to say they plan to meet a specific single peak. It's a distribution system, remember. Transmission planners have very different concerns, because they're dealing with consolidated loads across a number of customers. When we're looking at a distribution system, you're looking at a feeder that isn't serving tens of thousands of customers; it may be serving hundreds. So it's a much more -- much smaller scale that we try to plan to, and it's much easier to plan for smaller units than big aggregated ones. EUB Decision (August 13, 2004) 153

160 The CCA stated that EDI had noted that unlike distribution systems that were characterized by large injections of new industrial/commercial loads, or facility expansion, the EDI system was fairly stable in size, and as such, the focus was shifted from the need to avoid spikes created by new demand levels associated with significant plant additions, to one where customers were provided a signal respecting facility rationing, i.e. to be mindful of use of the distribution system during the peak hours. For the foregoing reasons, the CCA agreed that EDI s use of the on-peak energy allocator for primary system costs was reasonable and should be approved by the Board. PICA PICA noted that approximately 45% of EDI s distribution costs were related to the primary distribution system and that EDI proposed to allocate 75% of the cost of the primary system plant on the basis of on-peak energy and 25% on the basis of off-peak energy. PICA further noted that EDI explained that the 25% allocated on off-peak energy reflected the cost of the minimum system required to deliver energy. PICA noted that EDI s proposed classification and allocation of 75% of primary system assets based on on-peak and off-peak energy was a departure from practice accepted by the Board in the past. PICA stated that for example, in the last Phase II application for AE, primary distribution assets were classified 100% to demand and allocated to customer classes on the basis of class NCP demand. PICA further noted that in the 2002/03 Phase II application by ANCA, the Board accepted an allocation method for distribution plant referred to as the component analysis method (CAM), and that under this method, the components of plant serving different classes of customers were determined through a sampling process. PICA stated that in the CAM approach the use of on-peak energy for cost allocation was generally not used except to allocate costs of shared transformers. PICA noted EDI s statement that on-peak energy was a suitable proxy for coincident peak demand: On-peak energy usage is a suitable proxy for coincident feeder peak demand because it is indicative of average demand during on-peak hours. The on-peak energy rate design promotes optimal use of facilities by providing customers with a clear and stable pricing signal. The on-peak energy rate design has been in place since 2001, and its continuation in 2004 will maximize rate stability for customers. EDI is not aware of any shortcomings with this approach. Depending on the nature of the demand at a feeder, the primary system will generally experience peak demand in both the summer and the winter. In addition, peak demand can occur at different times in a day and in different seasons. The sizing of assets for serving peak demand is not driven by a single needle peak but rather by a broader consideration of peaks in both the winter and the summer. On this basis, on-peak energy usage is an appropriate allocation for primary system costs. 154 EUB Decision (August 13, 2004)

161 PICA further noted that during cross examination EDI stated a single peak did not drive the sizing of the system: So the planning that we do is driven by a broad understanding of what's going to go in that area. What kind of a load will it have. It s not incrementally sized any differently based on any behaviors we think we could rationally incent with rates. Again, because of the nature of our load, we don t get costs driving up and down enough to really change their planning decisions. So I don t think it s correct to say they plan to meet a specific single peak. It s a distribution system, remember. [Tr. p. 2582, line 10] PICA disagreed with EDI s characterization that seasonal differences might not be captured by the use of a demand allocator. PICA submitted that if a demand allocator can capture seasonal differences for the transmission interconnection charge, the same should be possible for the primary distribution system. PICA submitted that EDI s use of on-peak energy as a proxy for coincident feeder peak demand was based on flawed logic. PICA s submission was that a demand measure, such as class NCP demand, would be a better proxy for feeder peak demand than on-peak energy as the former captured the maximum use, which drives the sizing of the plant, and on the other hand, the latter captured average use during the peak period. PICA noted that the peak period was comprised of several hours, with the demand in each hour different from the peak hour. PICA further noted that the evidence indicated the residential class cost responsibility based on peak energy use was 30.7% (per Schedule DAS-12 (730843/ = 30.7%); whereas the residential class share of class NCP demand was 41.1%. (Per PICA.EDI-81(d) (9035.6/ = 41.1%) PICA submitted that this difference was significant and did not support EDI s assertion that peak energy use was a suitable proxy for coincident feeder peak. PICA noted that EDI indicated it was about to make changes to its cost of service study once the capital assets review was completed. PICA further noted that EDI also indicated it contemplated a component type analysis similar to the one carried out by ANCA: EDI has contemplated such an analysis, but currently uses other load tracking/forecast methods and processes for load analysis and circuit configuration. (IPCAA.EDI-13(c)) PICA submitted that EDI should be directed to review and propose an alternative to the use of peak energy to allocate primary system costs that was more closely reflective of the sizing of the system, at the time of the next GTA. PICA stated that this allocation method should be reflective of feeder peak demand rather than average demand during on-peak hours. PICA noted that alternatively, if the costs relative to a component analysis similar to the one accepted by the Board for ANCA were feasible and justifiable based on costs and benefits, the cost of service study should be based on such analysis. EUB Decision (August 13, 2004) 155

162 PICA noted that EDI s rationale for allocating 25% of primary system costs on off peak energy was set out in response to PICA EDI 81(b): Table 17. The value of 25% is based on the cost allocation of the lighter (for off-peak) and heavier (for on-peak) cables, which is approximately ¼ all energy and ¾ peak energy. The derivation based on calculating the minimum system is shown in the table below. The calculated result of 74/26 is roughly equivalent to the 75/25 ratio used in the COSS study. Conductor Size Minimum System Calculation Conductor Meters Cost $/m Min Conductor Size 4,615, ,949,623 Typical Conductor Size 4,830, ,289,327 Total 9,446, ,238,950 Cost ($) Cost Basis % #2 ASCR (aerial), #1/0 XLPE (underground) #336 ASCR (aerial), 500 MCM PILC (underground) Meters of Total Cable 9,446, ,855, Incremental cost due to demand and energy 239,956, Total Cost 325,811, PICA submitted that the classification and allocation of the primary system should reflect the parameters used in planning the system. PICA stated that given the different load factors of different customer classes, PICA was not convinced the use of energy, or the equivalent of average demand during off peak periods, to classify and allocate minimum system costs was reflective of planning to meet minimum capacity requirements of the system. PICA submitted that EDI had not given adequate consideration to what was driving the minimum system costs. PICA suggested that this could be the number of customers or it could be demand. PICA submitted that EDI should be directed to examine and address what factors were driving minimum system costs for the primary system and incorporate its findings in the cost of service study for the next GRA. Views of the Board The Board notes that PICA proposed a class NCP allocator for primary distribution system costs, and that CCA supported EDI s proposed 75% on-peak energy/25% total energy allocator for primary distribution system costs. The Board does not consider class NCP to be appropriate as the sole allocator for the primary distribution system, since the primary distribution system is not sized to meet the forecast NCP of each rate class. The Board recognizes that on-peak energy is sometimes used as an allocator for facilities that are sized to meet a forecast CP. However, the Board is concerned that the definition of on-peak energy used by EDI, which results in over 3000 hours being defined as on-peak, may be too 156 EUB Decision (August 13, 2004)

163 broad a definition of on-peak hours for the purposes of allocating the costs of facilities that are sized to meet a forecast CP. The Board also notes that the primary distribution system can be viewed as a bridge between the secondary distribution system, which is sized to meet the local NCP, and the local transmission system, which is sized to meet the CP of the DISCO. Based on this view, the Board considers that there may be an argument that some combination of CP and NCP allocators would be appropriate for the primary distribution system costs. The Board considers that the issue of the appropriate allocator for the primary distribution system costs should be further addressed at EDI s next GTA. Therefore, the Board directs EDI, in its next GTA, to further examine this issue, including an assessment of the use of both NCP and CP allocators. The Board also directs EDI to examine the use of a narrower definition of onpeak hours for the purposes of allocating primary distribution system costs, such as the critical hours within 5 or 10% of the system CP. For the purposes of this Decision, the Board considers that an appropriate allocator for the primary distribution system costs should give some weight to both NCP and on-peak energy, as a proxy for CP. The Board notes that EDI, when asked to allocate its primary system by NCP in PICA-EDI 081, chose individual site NCP, rather than rate class NCP, even though it had rate class NCP information available to it. In the Board s view, individual site NCP does not recognize any form of diversity, and is therefore of little use for allocation of the primary distribution system. The Board, in Appendix 3, has used the EDI NCP allocator that recognizes diversity within each rate class. Further, Appendix 3 illustrates that an allocator based on a 50/50 weighting of class NCP and on-peak energy produces a result that is very close to a CP allocator as measured by the six top load hours in the year EDI did not provide any forecast load profiles for 2003 or However, the Board is satisfied that for the purposes of this Decision, a 50/50 weighting of class NCP and on-peak energy to allocate primary distribution system costs would provide reasonable results. Therefore, the Board directs EDI, in its refiling, to use a 50/50 weighting of class NCP and onpeak energy to allocate primary distribution system costs. In Appendix 3, the Board has provided its approved allocators. The Board emphasizes that this 50/50 weighting of class NCP and on-peak energy is for the purposes of this Decision only, and that the appropriate allocator for primary distribution system costs will be reconsidered at the time of EDI s next GTA. EUB Decision (August 13, 2004) 157

164 The Board directs EDI, at the time of the next GTA, to provide the following data for each rate class to assist in the evaluation of an appropriate allocator for primary distribution costs: Forecast load for every hour of the year Forecast NCP Forecast CP Forecast on-peak energy Forecast off-peak energy The Board considers that there may be merit in undertaking both a minimum system study and a zero intercept study for the primary distribution system as a future refinement to the COSS. To assist the Board in making an assessment as to whether such a refinement would be beneficial, the Board directs EDI, at its next GTA, to identify the costs and the pros/cons of undertaking both a minimum system study and a zero intercept study for the primary distribution system. 9.2 DAS Rate Design General Views of the Applicant EDI stated that its DAS rates were designed using well-accepted methods, considering the structure of the retail market in Alberta. For example, EDI designed its DAS rates to eliminate cross subsidies among rate classes to the extent possible; to reflect EDI s enhanced ability to obtain and analyze customer specific usage data; and to neither encourage nor discourage the potential use by customers of what are likely to become a wide range of supply options. EDI stated that in designing its rates, EDI focused on achieving a suitable balance among the following criteria: collection of EDI s total distribution access revenue requirement, when applied to the forecast load and billing determinants; consideration of the costs from the COSS Study; encouraging the optimum use of supply facilities; recognition of the value of service; avoidance of undue discrimination between rate classes and between individual customers within each class; consideration of the existing rates, trends in rate levels and the stability of rates; simplicity of understanding and acceptance by customers, ease of administration and economy of billing; and consideration of the rates and practices of other utilities having similar costs and providing similar service. EDI submitted that EDI s DAS rate design was based on appropriate and rational criteria, and that it achieved a reasonable balance among them. EDI noted that the CCA recommended that EDI be directed to address an imbalance in the residential rate design at its next GTA. The imbalance cited by the CCA related to the fact that customers in the residential rate class pay the same fixed costs regardless of whether 300 kwh or 158 EUB Decision (August 13, 2004)

165 1500 kwh per month are consumed. EDI also noted CCA s recommendation that EDI be directed to provide an assessment of the cost allocation and rate design issues related to services provided to apartments at its next GTA. EDI submitted that a review of the customer service cost components showed that the customer connection costs of larger services were borne by the developer (and hence by the customer) in that these costs would be over and above EDI s per-site residential contribution limit. (Tr. p. 2776) As a result, EDI disagreed that any imbalance existed in respect of secondary connection costs. EDI stated that the Residential fixed daily charge was designed to recover secondary, connections, transformation, metering and billing costs, which costs are site, as opposed to demand, related costs. EDI noted that these site related costs do not vary with consumption. For example, if a customer who was consuming 300 kwh a month in a house chose to increase his consumption to 1500 kwh a month, he should still pay the same fixed daily charge as before because the costs related to the site were not impacted by consumption. Therefore, EDI did not consider that there was any imbalance with respect to the fixed daily residential charge. EDI concurred with the CCA s suggestion that EDI should provide an assessment of the cost allocation and rate design issues related to services provided to apartments at its next GTA. EDI also noted the CCA recommendation that the Board direct EDI to address, at its next GTA, the issue of why customers taking service under the distribution connected generation, such as the UA, are exempt from the provisions respecting franchise fees. EDI noted that the CCA submitted that whether a distributed generator was taking power from or injecting power into the system, it was using distribution facilities and should be subject to franchise fees. EDI stated that it followed the approach suggested by the CCA in its calculation of distribution tariff charges. EDI noted that the Distribution Connected Generation rate schedule states The Distribution Access Charges from the applicable Rate Schedule are applied to the absolute value of hourly energy as per customer meter., but also that Schedule A of the Franchise Fee Agreement (Exhibit ) states EDI shall pay a monthly amount to the City, as collected from Customers, calculated on the basis of a fractional dollar amount per kwh of electric power distributed to Customers and recorded on meters each month.. EDI considered that the Franchise Fee Agreement spoke for itself, and reiterated its position stated in its Final Argument that the Board had no authority in the circumstances of EDI to consider either the level or form of the franchise fee payable by EDI to the City of Edmonton, including the rate determined by the City under which the fee is to be collected. However EDI noted that it does not have any franchise rights in respect of the construction or operation of generation facilities by any party, irrespective of whether they were connected at transmission or distribution voltages. Accordingly, it seemed reasonable to EDI that the franchise fee not apply to generation output. EUB Decision (August 13, 2004) 159

166 Views of the Interveners CCA The CCA noted that the response in CCA-EDI-37 showed that more than 79% of the customers in this rate class consumed less than 700 kwh per month, and that in terms of consumption, about 21% of the customers consume more than 41% of energy in this rate class, as shown in the following table: Table 18. EDI Stratified Customer Consumption Strata kwh Customers % Cum % Mid Point Total kwh % of kwh Cum % <300 67, % , % > , % 79% 500 5,399, % 58.50% > , % 94% 850 2,635, % 83.20% >100 14, % 100% 1,500 1,795, % % 248, % 10,674, % Source: Response CCA EDI-37 The CCA stated that EDI had confirmed that if the larger Rate 11 customers required some additional services, the cost of such services was most likely provided for by the developer, who was compensated through the price of the lot. As such, there was no impact on the costs borne by others in Rate 11 in the aggregate. However, the CCA remained concerned that the fixed costs (site charge under the DAS and demand charges under the SAS) per month remained the same whether the customer was taking 300 kwh per month or 1500 kwh per month. The CCA submitted that for the larger customer in this rate class, the average cost of consuming more energy was, in fact, lower than that for the smaller customer. While the CCA recognized the need for a fixed cost of some sort, it submitted that the Board should direct EDI to address, at its next GRA, how this imbalance within the rate class may be addressed. The CCA also noted that EDI expressed a need to address the cost allocation and rate design issues related to the service provided to apartments: Because although apartments are metered as if they were residential customers, and indeed they are, I have a nagging suspicion that the cost of serving them is quite a bit different from the cost of serving a single-family dwelling that may also only use 300 kilowatt hours a month. So my suspicion is that the service kilowatt hours don't tell you very much about the real cost of serving it, because an apartment can run a thousand kilowatt hours if someone's got, you know, lots of heating on or lighting or whatever else they like to have. So I would be looking at the end-use service, particularly in apartments, if I was to look for some places where the cost-of-service might be getting out of line with the actual cost. (Tr. pp ) The CCA agreed with EDI that this issue needed to be assessed, both from a cost of service and rate design perspective, and accordingly, submitted that the Board should direct EDI to provide the results of this assessment at the next GTA rate filing. 160 EUB Decision (August 13, 2004)

167 The CCA stated that the evidence was not clear as to why EDI did apply franchise fees to customers that take service under the DAS Tariff Distribution Connection Generation. The CCA submitted that whether the customer was taking power from the system, or injecting power into the system, it was using the facilities that are the subject of franchise taxes. The CCA stated that EDI appeared to be making an exception for customers who both produce power and take power from the system, and that it was not clear upon what authority this distinction was based. It appeared to the CCA that whether the customer was taking power from the system, or injecting power into the system, it was using the facilities that were the subject of franchise taxes. The CCA suggested that this issue was likely to take on additional importance in the future as more and more customers, other than those over 5000 kv.a, opt for service under this rate. Certainly, the economics of this rate are enhanced if there is exemption from the franchise fees. The CCA recommends that the Board direct EDI to address, at its next GRA, why customers taking service under the Distribution Connected Generation, are exempt from the provisions of the franchise fees. PICA PICA noted that PICA.EDI-87 showed the revenue changes from existing to proposed rates by rate class and the corresponding revenue to cost ratios. PICA noted, if the concerns over allocation of primary system costs were rectified, the costs allocated to commercial customers would generally be lower. Given EDI s proposed rates were moving in this direction, PICA did not object to the proposed revenue to cost ratios for purposes of this proceeding. PICA also noted in reply that given that a franchise fee does not necessarily have an identifiable cost driver, the UA had suggested that the Board had historically approved franchise fees based upon a percentage of the customer s total bill. PICA further noted that the UA also suggested such an approach would be appropriate in this case. PICA submitted that this was also the approach it recommended in its Argument. PICA noted that the UA also recommended an alternative method of recovery: As an alternative for the Board to consider, the University would suggest the total franchise fee be allocated to revenue requirement on the basis of all other distribution costs. Once allocated to rate classes, the franchise fee could be recovered on a /kwh basis. This method should closely approximate traditional methods of cost recovery and at the same time set a fixed revenue target for rate design. By allocating the franchise fee based on all other distribution costs, the method is also consistent with cost causation in the sense the franchise fee is associated with the EDI distribution service area. 272 (UA Argument, pp ) PICA submitted that the above alternative approach is preferable to the one proposed by EDI. 272 Furthermore, the University s method is also consistent with the City of Red Deer. See ENMAX Exhibit [Ibid] EUB Decision (August 13, 2004) 161

168 Views of the Board The Board will address the following issues in this section: Level of Fixed Charge in Residential Rate Apartment Rates Franchise Fee Form and Recovery. Level of Fixed Charge in Residential Rate The Board notes the position of the CCA that the EDI Rate 11 fixed charges remained the same whether a customer was taking 300 kwh/month or 1500 kwh/month. The Board also notes the CCA example, which shows that the top 21% of EDI s highest use residential customers consume some 41% of the rate class energy. The Board further notes the position of EDI that the residential fixed daily charge was designed to recover secondary, connections, transformation, metering and billing costs, which costs are site-related, as opposed to demand-related, costs. Finally, the Board notes the example provided by EDI that if a customer chose to increase his consumption from 300 kwh/month to 1500 kwh/month, his fixed daily charge would not increase. In recent Decisions, the Board has encouraged utilities to move towards a 100% revenue-to-cost ratio by cost component. Specifically, in Decision , the Board indicated: Optimally, a rate design should reflect the manner in which costs are incurred to serve a particular class. If a utility s cost structure had more fixed costs than variable costs, a regulator would expect the rate to have higher fixed charges relative to variable charges. If a rate design strays too far from each of its demand, consumption and customer components recovering 100% of its allocated costs, two undesirable effects can result. If fixed costs are over-allocated to consumption, a utility can be exposed to the volatility in its customer s consumption. Therefore, the Board does not agree with CCA that increasing the energy charge to absorb some of the fixed charge will necessarily result in AE recovering the same revenue requirement from Rate 11. This will be the case only if AE s consumption forecast were 100% accurate. Deviations from forecast would result in AE over-recovering or under-recovering its revenue requirement from Rate 11. The second unintended effect is that, if the fixed charge recovers far less than the fixed cost, with the unrecovered proportion incorporated in variable charges, there will be a subsidy from large consumers to small consumers within a rate class. This intra-class subsidy will exist even if the utility s consumption forecast is 100% accurate. The Board notes that AE s fixed charges recover less than 100% of costs. The Board indicated its concerns in regard to this intra-class subsidy in Decision U99034, AE s last Phase II. The Board considers that AE has responded to those concerns by proposing an increase in the fixed charges for Rate 11. The Board therefore does not agree with CCA that a portion of the proposed fixed charges for Rate 11 should be moved to the energy charge. The Board considers that EDI s proposed residential fixed charge is consistent with the above Board views. 162 EUB Decision (August 13, 2004)

169 Apartment Rates The Board notes the position of the CCA that Apartment Rates should be examined in EDI s next GTA. The Board also notes the willingness of EDI to examine the cost allocation and rate design of Apartment Rates in its next GTA. Therefore, the Board directs EDI to examine the cost allocation and rate design of Apartment Rates in its next GTA and make a proposal whether a separate rate design should be applicable to Apartments. Franchise Fee Form and Recovery In a later section of this Decision, the Board has determined that it has no jurisdiction to review or approve the level of the Franchise Fee or the method of collecting the Franchise Fee by Rate Class Revenue to Cost Ratios In this section, the Board will address the appropriate level of revenue to cost ratios which should result from the final EDI DT rates. Views of the Applicant EDI noted that the CCA submitted that EDI be directed, for purposes of its next GTA, to design rates that fall within a plus or minus 5% tolerance range, and provide rationale if it proposes to design rates outside this range. EDI viewed CCA s suggestion as reasonable. Views of the Interveners CCA The CCA suggested that EDI has taken the approach in its rate design that all cross subsidies be eliminated and to that end, has designed rates such that the revenue to cost ratios are made equal to unity. The CCA submitted that given the many varied and sometimes controversial assumptions inherent in any cost of service method, the use of the revenue cost criterion, to the exclusion of other rate design criteria, was not reasonable. The CCA stated that the EUB has traditionally held the view that rates were generally considered reasonable as long as the revenue cost ratio was within a plus or minus 5% tolerance range. The CCA submitted that EDI be directed, for purposes of its next GRA, to design rates that fall within this range, and provide rationale if it proposed to design rates outside this range. Views of the Board The Board notes the position of the CCA that allowing for a +/-5% variance from 100% in a rate class s revenue to cost ratio has been accepted by the Board in the past. The Board also notes PICA s acceptance of the EDI revenue to cost ratios. The Board further notes the willingness of EDI to consider utilizing a +/- 5% variance from 100% for the revenue to cost ratios in its 2005 GTA. EUB Decision (August 13, 2004) 163

170 The Board considers that a number of different factors can influence a rate design, including the impact of rate shock, the concept of gradualism, migration of customers between rate classes, introduction of new rate classes, redesign of a rate class structure, and a significant change to a COSS. The Board considers that given the reduction in EDI s overall revenue requirement resulting from this Decision, it is now possible to develop rates which satisfy both the objective of a 100% revenue to cost ratio for each rate class, as well as a 10% combined DAS and SAS rate increase cap. Therefore, the Board directs EDI, in its refiling, to design rates that achieve a 100% revenue to cost ratio for each rate class, while not exceeding an overall 10% combined DAS and SAS rate increase for any rate class. In an earlier section of this Decision, concerning the level of EDI s residential fixed charge, the Board noted its desire for the rate structure to include rate components that are designed to recover the customer, demand, and energy cost components associated with each rate class. The Board recognizes that it may be more difficult to achieve 100% revenue cost ratios by rate component given the revisions to the COSS. Therefore, the Board also directs EDI, in its refiling, to determine a rate structure that moves towards a 100% revenue to cost ratio for the customer, demand and energy cost components of each rate class. The Board directs EDI to use its judgment in determining which components can be moved to 100% in the refiling and which components should move towards 100% over a period of time in future GTAs. Of particular note is the Board s directive for EDI to allocate Primary Distribution costs on a 50% NCP/50% On-peak energy basis. The Board expects that the proposed rate structure of EDI s refiled rates will be designed to recover the 50% demand and 50% energy costs components which are associated with Primary Distribution as close as possible, by rate component, given the other constraints mentioned above. The Board also directs EDI, in its next GTA, to include an analysis of the revenue by component (energy, demand, and fixed charge) compared to the cost by component, for both its existing and applied for DAS and SAS rates. In an earlier section of this Decision, the Board directed EDI to further examine, at its next GTA, the appropriate allocator for primary distribution system costs. The Board directs that EDI s refiled rate structures reflecting the 50% NCP/50% On-peak energy cost allocation should be revisited at the next GTA and made consistent with the results of the further examination of the appropriate allocator for the primary distribution system costs Complexity of Method Views of the Applicant EDI submitted that its DAS rate design method was not overly complex, but that it properly balanced objectives such as simplicity of understanding with other factors, such as the complexity of the industry structure in the Alberta marketplace. EDI noted that is had taken a number of steps to minimize the complexity of its 2004 DAS rate design, including: 164 EUB Decision (August 13, 2004)

171 Designing rates that covered broad ranges of customers, using available load settlement and interval metering data rather than complex customer rate groups, to achieve a 100% revenue-to-cost ratio. Setting fixed charges (i.e., demand and site charges) as daily rates to eliminate the need to pro-rate these charges for stub periods caused by the opening and termination of services or changes in retailers. Proposing the same rate classes that it has used prior to 2004, with which retailers and customers have grown familiar since the beginning of Eliminating the minimum variable charge and the power factor charge. EDI stated that no party led any evidence demonstrating that EDI s DAS rate structure was overly complex, and that the record demonstrated that EDI s DAS Tariff rate design was practical and not unreasonably complex. EDI submitted that it disagreed with the UA s characterization of its rate structures as overly complex. EDI stated that based on the evidence summarized in Section of EDI s Final Argument, its DAS rate design was not overly complex for the wholesale market, and it appropriately reflected cost causation and provided accurate price signals to the marketplace. EDI recognized and concurred with the UA that the tariff structure appropriate to a back office wholesale billing regime would not be appropriate for presentation to mass-market retailer customers like Mrs. Jones, and accordingly, EDI had actively supported the Board s extensive exploration of simpler alternatives for mass market customers with traditional cumulative consumption meters. EDI also defended its use of Weighted Average Pool Price, stating that this approach would be required by the RDS Regulation, commencing July 1, 2006, and that continuing this approach would smooth the mandated transition to pool price flow through by ensuring that this information was properly captured in information systems. EDI further submitted that continuing with Weighted Average Pool Price would provide customers with the opportunity to understand this concept while it was still a very small part of their bill, thereby reducing the shock and cost of transition in EDI therefore submitted that the UA s proposed deletion of Weighted Average Pool Price from the Residential, Small and Medium Commercial rates structures was clearly inappropriate and should be disregarded. EDI described its use of On-Peak and Off-Peak energy as useful as a lead-in to what will happen in the future, as more customer-specific time-of-use metering practices emerge. EDI submitted that this development need not await the installation of mass-market interval meters. EDI further proposed in future to assess the physical connectivity of customers and settle by much smaller zones in the city, which EDI expected to soon be able to implement. EDI stated that the on-peak and off-peak charges for the zone would then reflect the usage patterns of a much smaller group of customers, situated in the same part of the city in houses and businesses that shared similar construction dates and generally comparable socio-economic status. EDI submitted that the mechanics of this process were all set out in the Settlement System Code, and awaited only the physical connectivity model noted above. EUB Decision (August 13, 2004) 165

172 EDI submitted that the retention of its current rate structure would provide a smooth transition to a more customer-specific time of use rate structure, consistent with the goal of encouraging efficient use of all public utility assets. EDI also noted the CCA s agreement in respect of Exhibit (Mrs. Jones Redux), that under such an approach, the use of the on-peak charges appeared to be reasonable proxies for the use of demand. EDI submitted that both approaches provided the same customer signal, namely that a consistent use of energy was economically preferable to a peaky use (which was a consistent reality across all levels of the electric system), and therefore that the UA s proposal to delete On-Peak and Off-Peak energy charges from the Residential and Small Commercial rates structures should be disregarded. EDI concurred with the UA s recommendation that use of a Demand Ratchet should be discontinued, as it is difficult to maintain and verify in the context of mass-market flowthrough billing. EDI noted that as the UA had not presented any evidence on rate design, had not cross examined on many of the matters it now raised in Final Argument, and had now presented an entire set of its own rate schedules for the first time in the proceeding, that EDI was given no opportunity to cross examine on or provide evidence of, the many errors in the UA s approach. EDI stated that had the UA s evidence been presented, EDI would have provided additional factual evidence in reply. EDI s noted that its proposed tariff structure had been in place since 2001, and remained essentially unchanged in this Application. EDI s position was that no other party had objected to the current tariff structure on the grounds of complexity. EDI stated that the UA s conclusion that it was questionable that retailers could pass through the EDI tariff even if they wanted to was a restatement of the obvious. EDI stated that it had long known that linking the timing of tariff calculations with the timing of settlement calculations rendered it impossible for a retailer to take information they re receiving from EDI and in a timely manner calculate the customer s distribution charge. EDI noted that three of Alberta s four major distribution companies had made the same decision to link tariff and settlement timing, in keeping with their understanding of government policies, and that it was the timing of tariff data provision that made flow-through practices difficult. EDI further noted that the tariff structure was quite irrelevant to flow-through calculations. EDI labeled the UA s assertion of continuous retail billing problems since 2001 as completely unsubstantiated in the evidence, and irrelevant to EDI s Application. EDI noted that the facts on the record suggested quite the opposite situation: while the rest of the province had experienced on the order of 30,000 post final adjustment mechanism error claims reflecting tens of millions of dollars in settlement errors, EDI had only sixteen such adjustments in the three years since market opening. EDI stated that the UA made a number of unfounded assertions itemizing what it described as benefits to a simpler tariff, but that nowhere had the UA dealt with the costs of programming, auditing and handling inquiries respecting the UA s proposed tariff structure. EDI submitted that these facts were not in evidence, nor could they be given that the suggested tariff structure was 166 EUB Decision (August 13, 2004)

173 only presented in argument. EDI s position was that these factors would all have to be considered in determining whether the UA s proposal would in fact provide any benefits. EDI further stated that the UA s argument positions, characterized as Extraneous Price Signals, were merely statements of various positions which were unsupported by evidence or sound argument. EDI submitted that: Security lights should not be treated inconsistently from other lighting customers. EDI had already concurred with the proposition that peak demand be eliminated as a billing determinant for residential and small commercial customers without demand meters. Use of On- and Off-Peak energy charges had been dealt with in section of EDI s Final Argument. Diversity and loss factors were required in order to calculate billing determinants at the transmission POD and, on that basis, were certainly not extraneous. In response to the UA s suggestion for further tariff changes, EDI stated that the UA s proposals would simply re-introduce a number of failure points in its billing system, while providing no value to customers. EDI commented specifically in reply to the items proffered by the UA as follows: 1. The DAS and SAS rate schedules were separated for obvious and sound reasons, and could readily be consolidated by any party who wished to do so. 2. The UA had itself provided the classic example of why tariff charges were printed directly from the rates model, and were not transposed by hand to separate documents. In producing their own rate sheets, the UA had themselves at page A-7 erred in transposing the demand charge ($ ) and site charge ($ ) respecting small commercial customers, and had further introduced a number of apparent errors in producing their proposed rates schedules, including: omitting the Primary service option of Commercial/Industrial Service 150 kv.a to <5000 kv.a, whose rates differed considerably from the secondary service option shown; changing the demand charge for the 50 to < 150 kv.a rate class to a $/kw basis, even though these sites were in fact metered in kv.a; and omitting a key AESO invoice true up provision for Direct Connect transmission customers. Each Direct Connect transmission customer s transmission charges were shown separately on the AESO s invoices and EDI s practice was to true up these charges with these customers in the manner described on its Direct Connects to the Transmission System rate sheet (GTA Schedule DT Schedule 2, pp ), which maximized the accuracy of AESO tariff flow-through. 3. The definition of Normal Maximum Demand was provided in a comprehensive EDI document dealing with all aspects of demand determination. Fragmenting this information across various rate schedules served no useful purpose, and risked creating typographic inconsistencies between rate classes. EUB Decision (August 13, 2004) 167

174 4. Currency units were included on all tariff sheets. All monetary amounts were consistently in units of $. The UA s suggestion that some amounts be presented as $ while others were presented as simply increased the risk of error in using the data. 5. In general, EDI believed that Rider applications should be specified in the Rider itself, rather than creating confusing and redundant duplication in the Rate Sheets. This was also more efficient than reissuing all rate sheets, when only a single rider had changed. This principle should be applied to the Special Transmission Rider, EDI s only presently approved 2004 Rider. 6. EDI s SAS tariff specified that settlement was the basis upon which tariff calculations were made. This will continue to be the case, and EDI was mystified by the suggestion that this critical fact be removed from the Application Guide. The confusion only deepened when in Table 11, #10-12, it was recommended that EDI Specify that Settlement System will determine consumption in respect of its Distribution Tariff. 7. EDI also stated that the UA appeared not to understand the fundamentals of settlement calculations. EDI submitted that its clear evidence was that losses are added to it [meter data] in the settlement process. UFE is not included in this tariff calculation. EDI further summarized the settlement process and the losses/ufe process during the hearing and in information responses. EDI noted that notwithstanding this volume of clear evidence, Table 10, item 7 of the UA argument incorrectly stated that the tariff is calculated using a fixed loss factor representing both losses and UFE. EDI stated that the tariff calculation did not include UFE, and in any event UFE was not a fixed factor, but changed by hour. EDI submitted that the UA s lack of understanding demonstrated the importance of confirming to parties that the settlement and tariff values would in fact be identical, as the industry fundamentals were often not well understood, even by professionals. 8. Load settlement by definition calculates each site s contribution to energy at the AESO s aggregate POD level (Settlement System Code, section 6). Each site s contribution to demand at the AESO s aggregate Edmonton area POD demand is estimated using an appropriate load factor and coincidence factor. EDI s response in UA- EDI-15 described the difficulty of carrying out this calculation at a specified individual POD, which is of course not the same as the aggregate POD covering the whole city. 9. The effects of a leap year will be appropriately captured in the Board s development of SAS tariffs, and any variances will be captured in the deferral account. EDI stated that the balance of the UA s proposed changes were fraught with numerous errors and confusion. Among the most glaring were the following: The Uof A asserts that residential service should be qualified by the confusing statement that, The intent is that this rate is applicable to residential services that are on average 600 kwh per month, typically share a 37 or 50 kv.a transformer with about 12 other residential services and some streetlights. EDI submits that this is meaningless verbiage that does not belong in a rates schedule, as it provides no clarity but will only add confusion as to what qualifies and does not qualify as residential service. 168 EUB Decision (August 13, 2004)

175 The UA asserts that residential service should be further qualified with the statement that Residential sites may be eligible for Commercial Service only if the service is not typical of a residential service and at least one of the following parameters are met: (a) the service panel is larger than 200 amps, (b) the site does not share a transformer. Only very small, low energy consumption services receive a lower bill under the commercial rate. Small residences or low energy consumption residences do not qualify for Small Commercial Service. EDI submits that this superficial attempt at rates definition is entirely unhelpful and unrealistic. Firstly, residential sites do not apply for the commercial service rate, because as the definition itself points out their bill would be higher on the commercial rate. The challenge to EDI from an enforcement perspective is to keep small businesses from staying on or getting onto the residential rate. EDI s current eligibility definition does this by requiring that there be sleeping and cooking facilities, and that the use be primarily domestic. This eliminates most small businesses, which generally do not have sleeping facilities. EDI then allows that business may be conducted from a home situation, provided that the electric service does not rise above 200 Amps, the equivalent of 240 hundred watt light bulbs. Normal residences do not cross this threshold, and once the threshold is crossed, the business use of the property is clearly dominating the site s consumption of power. The converse requirement that small residences do not qualify for Small Commercial service is meaningless in practice. A quick calculation will indicate that the residential to commercial crossover is around 50 kwh per month, by which point the savings are mere pennies a month. The Special Transmission Rider was approved by the City of Edmonton as authorized under section 4.3 of the DT Regulation. This rider terminates on December 31, The UA s proposed Special Transmission Rider (A-25) states that the Special Transmission Rider will track the transmission charges of the AESO and 25 kv interchange charges of Aquila. There is no such charge in respect of 2004, as stated in CCA-EDI-2(a), and confirmed by the zero balance on Schedule D-22, Transmission Charge Deferral Account. Should a material transmission deferral account balance arise, EDI will make an appropriate application to the Board for its disposition. EDI can see no reasonable basis for taking steps to confuse any such deferral account rider with the Special Transmission Rider, which will be extinguished at the end of The statement that at A-3 Specific determinations by EPCOR Distribution are subject to appeal before the Alberta Energy and Utilities Board is both self-evident and misleading. It is self-evident that the Board has broad oversight and jurisdiction over EDI s actions in implementing the approved Tariff, and it may be useful to inform customers of this fact using appropriate language as determined by the Board. However, EDI submits that it would be misleading to characterize a party s rights as an appeal, which is a legal term having specific technical meaning. EDI noted that it had demonstrated its willingness to explore and adapt approaches to rate design that were consistent with the needs of its customers. EDI stated that it was unfortunate that the UA had adopted the approach of providing its tariff evidence in argument, and that the EDI reply argument had demonstrated this evidence was neither productive nor helpful. Views of the Interveners PICA PICA noted that EDI s rate design simply took the allocated costs by rate class for the various functions divided by the corresponding billing determinants to arrive at the rate components. EUB Decision (August 13, 2004) 169

176 PICA submitted that although the rates were designed to recover the exact costs as calculated for each function, this mechanical exercise ignored any economies of scale associated with serving larger demands versus smaller demand. PICA stated that for example, EDI s rate design assumed the transformer and service connection cost per KVA of serving a 4500 KVA customer was the same as was required to serve a 300 KVA customer, while on the other hand, Schedules DAS-26 and DAS-27 indicated transformer and service connection unit costs decreasing with increasing size of load. PICA was also concerned that the use of energy allocators to determine primary system costs resulted in larger customers with relatively high load factors paying more for primary system costs than smaller customers. PICA submitted EDI should be directed to review its cost of service study and rate design to take into account and reflect the economies of scale associated with serving various sizes of customers within each rate class, at the time of the next GRA. UA The UA noted the numerous iterations between EDI and other parties to understand how Mrs. Jones s Bill would be calculated. The UA suggested that all would generally agree that the proposed EDI tariff was more complex than most, and that similar Mrs. Jones scenarios were not required to understand the ENMAX Distribution Tariff during the same proceeding, nor was the UA aware that this was required for any other Board-regulated utility. The UA stated that it had a strong interest in clear pricing signals from rates other than the Greater than 5,000 kv.a rate class, as it receives service from EDI at a number of smaller sites in the Edmonton region, representing at least two other Commercial rate classes. The UA also noted that as a public institution, it also bore in mind the welfare of its staff and students who were residents in the EDI service area, many of whom also have residential service accounts with EDI. The UA stated that the EDI s proposed tariff was unnecessarily complex, and provided an alternative tariff format to demonstrate this assertion. The UA submitted that if this tariff was actually passed through by retailers, the additional complexity meant that the intended price signals would not necessarily be visible to customers. The UA further noted that EDI testimony suggested that until a proposed new billing system was implemented in October 2004, it was questionable that retailers could pass through the EDI tariff even if they wanted to. The UA stated that certain discussions on the transcript record indicated that EDI s current billing system made it very difficult on a fundamental structural level for a retailer to pass through tariff charges. It was the University s view that the complexity of EDI s tariff compounded upon the structural problem because twenty different retailers must make additional interpretations of EDI s tariff document and re-calculate the tariff from hourly settlement data. The UA stated that it had experienced continuous retail billing problems since 2001, claiming that with very few exceptions, it had not received monthly retailer invoices that on the first attempt correctly flowed-through the EDI tariff. The UA noted that it was not surprised to learn that EESI, a retailer affiliated to EDI did not even attempt to pass through the EDI tariff for RRT customers, instead relying on a simplified version of the EDI tariff for its own billing system. 170 EUB Decision (August 13, 2004)

177 The UA submitted that this was a symptom of a tariff that was so complex that it had no value for practical use. The UA s main concern was with the tariff formula itself because for all rate classes, EDI introduced parameters into the formula that on the surface appeared to be pricing signals, but in fact had nothing to do with an individual s metered consumption. The UA stated that these parameters were either fixed at the start of the tariff year or set by the rate class load profile, which was not determined at the same time the individual was consuming wires services. The UA considered it inappropriate and possibly misleading for the tariff schedule to include variables over which the individual customer has no control, including: A per-kw peak demand charge for energy metered customers. A per-kwh on-peak / off-peak energy charge for customers without an interval meter. A per-kwh energy charge for customers who are not metered at all. A diversity or coincidence factor that applies to all customers in a rate class. A loss factor that applies to all customers in a rate class. The UA disagreed that a simpler, more traditional rate structure added risk for the customer because regardless of the structure, EDI had to acquire Board approval to change its tariff. The UA stated that even by assuming all consumers were reasonably equipped to understand how EDI obtained values for formula parameters that had nothing to do with an individual s metered consumption, EDI had only obligated the customer to perform additional calculations that would traditionally be done once in the rate design process. The UA noted that if the customer did not understand how the tariff formula parameters were acquired, that EDI had significantly added to customer risk because the individual was no longer certain how his or her tariff charges varied with consumption. The UA noted that despite proposing the tariff structure that it has, EDI has also supported or suggested conflicting principles in its testimony, when it stated that: Any time you add more information to the customer s world, they tend not to be happy. I mean, that s the frank reality that we all know. So that s why I ve worked on this redux version, recognizing that, really, when you start seeing it from the customer s perspective, you shouldn t add anything that s not of value for them to see about the new world. The UA further noted the EDI discussion on a specific example of this principle: The other one of the on-peak and off-peak energy is -- has pros and cons from a customer s perspective. On the one hand, yeah, it s probably good to point out, yeah, energy has a real different price, different hours. The disadvantage of that approach is that it s not your individual use. It s -- that s the grazing of the commons. Well, if I cut my bill -- if I do my washing at night, do I get a reduction? Well, no you don t. That s a deficiency we all recognize. The UA stated that EDI s tariff application proposal to design and implement a new billing system in 2004 provided an excellent opportunity for the Board to closely examine how the EDI tariff schedules might be improved, and further, that EDI appeared open to this possibility, as expressed several times during the testimony of its witness panel. EUB Decision (August 13, 2004) 171

178 The UA expected that there would be positive direct and indirect benefits to a simpler tariff: A simpler tariff would be easier to program and troubleshoot in the new billing system, thus saving on development costs. Customer bills based on a simpler tariff would be easier for EDI to internally audit as part of its regular quality control programs, meaning either more accurate invoicing for the same cost or equally accurate invoicing for reduced cost. A simpler tariff may result in fewer inquiries from retailers and end-use customers, which should have an impact on administration and call centre costs. The UA noted a suggestion from the hearing that EDI could adopt the modified tariff structure used by EESI for RRT invoicing, but as it did not apply to all EDI rate classes, it would only be a partial measure. The UA suggested that this would not necessarily address all of the UA s concerns regarding the actual text of the tariff schedules. The UA stated that while it was useful to consider the EESI experience to improve the tariff, recommended that the Board direct EDI to re-write its tariff schedule to be consistent with specific principles. In general, the University advocated a simpler, more traditional tariff formula whose only variables were based on the individual s metered load. The University believed this could be achieved without sacrificing valid and desirable price signals. The following table summarizes what the UA considered to be extraneous price signals within the EDI tariff, as well as a recommended solution. Table 19. Extraneous Price Signals in Proposed EDI per UA EDI Charges Distribution Access System Access Solution Advocated by University Per-kWh energy charge for unmetered rate class comprised of a single customer and multiple sites Street Lights Traffic Control Lane Lights Street Lights Traffic Control Lane Lights None, addressed by settlement load profile Per-kWh energy charge for unmetered rate class comprised of multiple customers and multiple sites Per-kW peak demand charge for energy metered customers Security Lights Security Lights Convert to per-site fixed daily charge n/a Residential Com/Ind <50 kv.a Convert to per-kwh rate Per-kWh on-peak / off-peak energy charge for customers without an interval meter A diversity or coincidence factor that applies to all customers in a rate class A loss factor that applies to all customers in a rate class Residential Com/Ind <50 kv.a Com/Ind kv.a n/a n/a n/a All rate classes except Com/Ind >5,000 kv.a that opt in to DTP-04 (Totalization) All rate classes except: Com/Ind >5,000 kv.a Direct Connects Dist. Generators Convert to per-kwh rate Multiply all per-kw based rates by the diversity factor Multiply all per-kwh based rates by the loss factor The UA also noted that it had several concerns regarding the language and overall structure of the tariff. The table below outlines the general concerns that applied to all rate sheets, as well as offering proposed solutions. Table 20. General Structural Concerns with Proposed EDI Tariff per UA 172 EUB Decision (August 13, 2004)

179 # Concern Solution 1 Customer must refer to two separate tariff schedules (DAS and SAS) to calculate its total tariff charges. Combine EDI Schedules 1 and 2 into a single document 2 Tariff sheets do not contain actual rates. Customer must refer rate appendix table found at the end of the tariff schedule. Include actual rate on rate class tariff sheet. 3 Definition of Normal Maximum Demand is critical to understand how Commercial/Industrial customers qualify for a particular rate class. Definition is inappropriately located in middle of section titled Calculations of Demand Include definition at front of tariff schedule. Specify the rate classes to which the definition applies. Charges. 4 Definition of Normal Maximum Demand implies EDI has full discretion to determine a customer s rate class. Advise customer that while it is within the bounds of EDI to make such determinations, they may be appealed to the EUB. 5 Currency units not consistently included on all tariff sheets. Add currency units (i.e. $ or ) to all 6 Although tariff sheets refer to Terms and Conditions and the Franchise Fee, they do not refer to the Special Transmission Rider. 7 Rate sheets consistently refer to use of settlement data to determine line losses and UFE. However, the tariff is calculated using a fixed loss factor representing both losses and UFE. 8 Proposed SAS rates will over-recover in a leap year. Column I of SAS Revenue shows EDI has calibrated rate parameters based on a 365-days year. 9 Proposed SAS rates refer to applying the provincial transmission tariff to each site s contribution to energy and demand at the AESO s aggregate POD level, which from EDI evidence, we have learned this to be inaccurate. rates. Add reference to all rate sheets to state that the Special Transmission Rider may apply. Delete all references to Interim Settlement, Final Settlement, and Settlement s relationship to losses and UFE. This is not relevant to the tariff calculation. Re-design daily rates using a 366-day year. Delete all references from tariff sheets. In addition to these general concerns list above, the UA had several specific concerns within each of the Distribution Access schedules. The following table summarizes concerns with the Distribution Access document along with page references and proposed solutions. Table 21. Concerns with Proposed EDI DAS Tariff per UA Page Concern Solution 3 Applicable section is shorter than similar definition in the SAS schedule. Add missing text from SAS schedule. 3 On/Off peak charges for energy metered customer. Use all hours variable charge from EDI Schedule DAS-28 (Feb 23 Errata, Col. E, Line 11) 3,4,13 Reference to Calculations of Demand Charges is not applicable to Delete reference. proposed Distribution Access charges. Nor is it applicable to System Access charges under changes advocated by the University. 4 On/Off peak charges for energy metered customer. Use all hours variable charge from EDI Schedule DAS-28 (Feb 23 Errata, Col. E, Line 21) 5 On/Off peak charges for demand metered customer. Use all hours variable charge from EDI Schedule DAS-28 (Feb 23 Errata, Col. E, Line 31) 10,11,12 Not clear as to how on/off peak charges will be determined for an unmetered rate class comprised of a single customer. Specify that System Settlement will determine consumption. 13 On/Off peak charges for an unmetered customer. Calculate single per-site daily charge from EDI Schedule DAS-28 (Feb 23 Errata) Col. M, Line 102 divided by Col. C, Line 101. EUB Decision (August 13, 2004) 173

180 Page Concern Solution 13 $ per kwh riders may apply to an unmetered customer. Add clarification that if applicable, $ per kwh rate riders will be converted to a $ per day charge. 15 Appears as though unmetered customers will not receive credit for capital Add clarification of EDI s intent costs relating to metering infrastructure. 16 No information as to actual franchise fee. Add current franchise fee with appropriate disclaimers. 17,18 Definition of billing demand overly complicated. Delete references to inapplicable rate classes. Delete one of two definitions of Peak Monthly Demand. Specify what rate charges use billing demand and what rate charges use peak monthly demand. Change kv.a to kw to match billing units. 18 Billing demand ratchet implies a two-month lag in item i) only. Change to be consistent with items ii) through vi) and AESO tariff. 19 Confusing reference to limits on demand ratchet history. Specify that 60-month ratchet is not applicable to data prior to January 1, KW to kv.a conversion inconsistent with System Access. Use either 0.9 or 0.92 in both documents. The UA noted EDI s testimony that it was responsible under the System Settlement Code for actual and estimated meter reads. The UA suggested that if it were EDI s intention to bill demand charges on a two-month lag (while all other charges were on a more typical one-month lag), it would not be a reasonable burden to require the changes it had suggested in the above table. The UA stated that in the event that the timing of meter reads did not correspond with the month-end retail invoice, EDI was in the best position of all parties (with both the data and expertise) to reasonably estimate current monthly billing demand. The UA further stated that for weekly retail invoicing, weekly estimates of monthly billing demand might be trued-up at month-end to either a measured billing demand or a new estimate of billing demand that considered all information available for the entire month. The UA stated that under no circumstances would it consider it fair and reasonable to customers that demand charges be lagged two months while all other charges on the invoice were lagged by one month. It was the UA s position that EDI be required to re-file a tariff schedule that incorporated the solutions presented in the above tables. To facilitate this process, the UA provided as an attachment a sample tariff schedule that incorporated the solutions discussed above. The UA noted that the purpose of its sample tariff was to show the type of structure and format that the University considered appropriate. The UA further noted that the attachment also demonstrated that the type of changes advocated by the University were not overly burdensome to EDI and that it was possible to produce a simplified tariff document in a relatively short time frame. The UA noted in reply argument that it disagreed with EDI s statement from argument that No party led any evidence demonstrating that EDI s DAS rate structure is overly complex. The UA submitted that from the perspective of a customer who received invoices for EDI services every month, it disagreed with any suggestions that the EDI tariff structure was uncomplicated. 174 EUB Decision (August 13, 2004)

181 The UA submitted that on the contrary, the record before the Board was replete with discussions about the complexity of EDI s rate structure as it was converted to billing information for the end use customer. The UA stated that it did not know what EDI deemed to be sufficient evidence to prove that EDI s tariff was either simple or complex, but the UA submitted that the only conclusion that the Board could reach on this matter was that the tariff complexity was adequately demonstrated. The UA, in addition to its own frustration with the current complexity and administration of the tariff expressed in its argument, also referenced how the evidentiary record indicated other parties have had difficulty in understanding the tariff and how it would be implemented. The UA submitted that its argument demonstrated that the EDI tariff proposal was unnecessarily complex in the sense that the UA s suggested structure provided an identical pricing signal with fewer mathematical terms appearing on the tariff sheet. Views of the Board The Board considers that EDI s proposed DAS rates are overly complex, especially given the nature of the billing data available to EDI. In the Board s view, the effort to accurately recover demand and billing costs from each customer based on their on-peak/off-peak consumption and billing demand is undermined by the fact that the on-peak/off-peak consumption and billing demand are estimates based on a load shape determined from the load settlement system. Further, the complexity of the EDI billing proposal appears to be more than retailers are presently able to handle. The Board notes that even EESI, EDI s appointed RRT provider, repackages EDI s rates rather than flow them through directly to customers. The Board is concerned that customer confusion would likely result should a retailer choose to flow through EDI s proposed rates directly to customers. The Board notes EDI s request that, should it be directed to simplify its rates, it be given until January 1, 2005 for implementation to allow it time to update its billing system. The Board concludes that EDI s DAS rates should be simplified in line with the practices of the other electric distribution utilities in Alberta. However, the Board will approve continuation of EDI s proposed DAS rate structures until December 31, The Board directs EDI to apply, no later than November 1, 2004, for simplified DAS rates to be effective on an interim basis January 1, Customer-Specific Rates Views of the Applicant EDI proposed to update the >5000 kv.a cost of service calculations with original cost-based information in its next GTA. EDI concurred with PICA and CCA that a single fully allocated embedded cost of service study for the entire system was a reasonable alternative to having separate cost of service studies for the >5000 kv.a class and for all other rate classes. EUB Decision (August 13, 2004) 175

182 EDI noted that their customer specific rates were derived based on the Replacement Cost New (RCN) value of the underlying dedicated and shared facilities that serve the customer, and that this approach had been approved by EDI s previous regulator commencing with EDI s 2001 DT. EDI stated that their customer specific rates for 2004 were unchanged from 2003 levels. These 2003 rates were derived from those approved for EDI for 2001, escalated in accordance with the Performance Based Regulation (PBR) plan in EDI s previously approved tariff. EDI proposed to maintain its 2003 customer service rates for 2004 as a transitional step toward a new vintage-based original cost method (involving a Capital Asset Review study, or CAR study), which would be reflected, in its next Tariff application. EDI felt that the UA s request to have EDI update the return, capital structure, and cost of debt assumptions in their refiling was clearly inappropriate for two reasons: Firstly, conceptually, customer-specific rates were calculated based on CRF x RCN. Both CRF and RCN values were last determined for use in the 2001 EDI rates and had not been updated since that time. EDI felt that updating only the CRF, without concurrently updating the RCN, would produce invalid results and incorrectly lower the UA s rate to the detriment of other customers. Secondly, EDI also stated that the 11.2% CRF was irrelevant because it was only used to develop the 2001 customer specific rate, and had not been used since then. The UA s current rate was calculated based on the 2001 rate, escalated by 85% of inflation from 2001 to EDI further noted that the UA proposed that the Board direct EDI to discontinue its standby service to the UA effective March 29, 2004, to allow the consequent rate revenue impact to be adjusted against all other rate classes. EDI noted that Article 12 of EDI s Terms and Conditions for Distribution Service Connections would apply in this situation. EDI agreed with the UA s position that the rate revenue loss from the Rossdale and Meadowlark standby sites should be made up by all other rate classes, who are in fact using those facilities at present. EDI stated that the UA s existing per-day 2003 unit rates were not developed by taking an annual revenue requirement and dividing by the number of days, but rather were developed by escalating existing per-day unit rates. As such, EDI did not believe that large customers should get a free day of service during a leap year. EDI stated cost of service studies for customer-specific rates were confidential and that any customer-specific rate customer who wanted to obtain the details of its own rate could make the request to EDI. Accordingly, EDI stated that they would be developing customer specific rates by individual feeder, would be billing on that basis, and would disclose that information to the affected customers. 176 EUB Decision (August 13, 2004)

183 EDI also noted that totalized customers such as the UA would be billed as a single site, and their individual feeder charges consolidated into a single daily charge. Views of the Interveners CCA The CCA supported PICA on the issue dealing with the need to undertake a separate COSS for customers taking service at greater than 5000 kv.a. The CCA stated that it appeared that for customers, for whom EDI provides totalized service, that EDI had not reflected administrative costs for data management and that these costs should be included in EDI s next application. The CCA noted that EDI had indicated during the hearing that the UA was receiving totalized service and that some $500,000 per annum of SAS charges were being transferred to the balance of customers as a result. The CCA further noted that EDI had indicated that while only one customer had taken this service, totalization was available to the other 16 large (>5000 kv.a) customers and the potential transfer to the rest of EDI s customers was between $250,000 and $500,000. The CCA felt that this issue required full testing in a later hearing. The CCA submitted that the customer specific rate reflected a number of items that may go to either reduce or increase the calculated rates. The CCA felt that all of these factors suggested that it was inappropriate to engage in the selective exercise proposed by the UA of only identifying instances where its rate may have been over-stated. The CCA noted that the UA s indication that on March 15, 2004 it had notified EDI to discontinue standby service on its Meadowlark and Rossdale feeders, was new evidence that should properly be ignored by the Board. The CCA submitted that the UA had submitted significant changes that it wished to incorporate into its rates, and the rates of other customers in its rate class. The CCA felt that while the UA had provided calculations that affect it, adoption of its recommendations would also affect the other 16 customers in the Greater than 5000 kv.a class and that the total impact on EDI s costs, to be paid by other distribution customers, therefore could not be quantified. The CCA felt that there may be merit in examining this issue in EDI s next rate case, either by EDI or the UA providing evidence, so that the Board and other parties could make a proper assessment on the proposals advanced by the UA in this proceeding through Argument. PICA PICA stated that it understood that EDI s reason for separate treatment of the 17 large customers in the >5000 kv.a category was that these customers did not rely on the main primary system, but instead had their own dedicated primary system. PICA was concerned that the use of a 11.2% capital recovery factor may, or may not have, appropriately reflected the cost responsibility of the >5000 kv.a customers for O&M and other costs on a fully allocated basis within the test year. PICA noted that Exhibit showed that the 11.2% capital recovery factor reflected a levelized cost rate based on certain assumptions as EUB Decision (August 13, 2004) 177

184 to O&M, return on, and return of, capital. PICA further noted that this derivation was not based on EDI s 2004 revenue requirement. Based on this, and for purposes of the next GRA, PICA recommended that EDI be directed to provide a fully allocated embedded cost of service study encompassing the entire system, including the customer specific class, so the Board and customers would be in a position to assess the reasonableness of cost recovery for this class on a basis similar to other customer classes as a result of this study. UA The UA submitted that the concept of a customer-specific rate based on specifically assigned assets was appropriate and in keeping with Board-approved principles. However, the UA felt the EDI method broke down in principle as it failed to recognize asset vintage (depreciation) and past customer contributions, which conflicted with generally accepted regulatory principles. The UA stated that EDI did not follow through with customer-specific contributions or customerspecific depreciation in calculating the University s customer-specific rate. The UA stated that although customer contributions were not considered at all, EDI s method did incorporate an annual depreciation expense, averaged over the life of an undefined asset. The UA stated that this same calculation was applied to all customers in the Greater than 5,000 kv.a rate class, even though the assets serving each of the seventeen customers were known to be different, and that this violated a principle confirmed by the Board in Decision , wherein the Board ruled that it was unduly discriminatory to treat two customers the same when it is known that they were different. However, the UA was resigned to the possibility that the basic methodology might need to be continued into The UA recommended improving the accuracy and fairness of what the UA submitted was a flawed method. The UA noted that if either RCN or the Capital Recovery Factor were inaccurate, that EDI would under-recover or over-recover embedded costs from the Greater than 5,000 kv.a rate class and that there would be an unnecessary cross-subsidy between rate classes. The UA noted that their interpretation of the detailed calculation of the CRF was that it was an attempt to measure the ratio of revenue requirement, including capital and operating costs, to gross plant. The UA considered that multiplying the CRF by the RCN value of a customer s distribution assets was intended by EDI to be equivalent an embedded cost revenue requirement. The UA noted that to calculate the current rate, the original 2001 CRF RCN calculation was adjusted for inflation, presumably to update RCN for current day costs. The UA considered that this indicated that the CRF had not changed in the three years since it was first introduced. The UA noted that the EDI CRF calculation included approximations for an average depreciation rate and three percent of gross plant to represent total operating, maintenance, and administration costs, and that neither of these measures could be verified. The UA also noted that since the EDI distribution assets serving the University were mainly conduit and cable, it would expect specific operating and maintenance costs to be relatively low compared to other rate classes. The UA further noted that the difference between three percent and specific operation and maintenance would have had to represent an allocation of general operations, maintenance, and 178 EUB Decision (August 13, 2004)

185 administration, but that, without knowledge of operations and maintenance on customer-specific assets, general costs could be either too high or too low. The UA stated that it had showed that EDI had provided evidence that it had calculated Distribution Access rates for the Greater than 5,000 kv.a rate class using a cost of capital greater than that which it used to calculate total revenue requirement. The UA noted that EDI had reconfirmed that it did not intend to update the CRF for 2004 rates. The UA believed that this information suggested that capital costs charged to the Greater than 5,000 kv.a rate class would almost certainly vary from the Board-approved level and that since the revenues from this rate class were treated as an offset to the total revenue requirement, that the overall capital costs would have to balance out to the Board approved level. The UA considered that in doing so, EDI s method would have the effect of recovering more than the Board-approved amount from one group and recovering less than the Board-approved amount from the other group. The University submitted that this practice was unfair and unduly discriminatory, and recommended that the Board direct EDI in its re-filing to update the CRF return, capital structure, and cost of debt assumptions to be consistent with Board-approved levels. The UA noted that EDI had interpreted a system planning document to suggest that all cable lengths serving the UA should be longer than what is in the original cost of service document, and that it could reasonably interpret the same system planning document to suggest an opposite conclusion. The UA concluded that regardless of which interpretation was correct, however, the fact remained that the basis of the rate proposed for it was inaccurate. The UA stated that, ultimately, it would be satisfied to pay its fair share based on accurate information. The UA believed that, for the 2004 tariff year, it was necessary to ensure that its customerspecific rate was appropriately unbundled into active and standby feeder components. The UA stated that this was made necessary because on March 15, 2004, the University had formally notified EDI that it wished to discontinue standby service to the University on its Rossdale and Meadowlark feeders. The UA noted that on March 29, 2004, the University received EDI s formal confirmation of receipt of the disconnect notice; therefore, the University was left to assume that for rate design purposes, EDI considered standby service was discontinued on this date. The UA noted that, with respect to its customer-specific rate itself, it had sought to understand how the rate was calculated since it was introduced in The UA stated that from January 1, 2001 to December 31, 2003, for example, the University had paid over $921,000 in Distribution Access charges, and that this amount already exceeded what it would cost to build five new distribution voltage feeders of equivalent capacity. The UA noted that EDI had not unbundled the UA s Distribution Access rate into active and standby components, but that after two requests, EDI did provide sufficient information for the University to unbundle the daily rate itself, which had yielded two interesting conclusions: $ per day of the proposed Distribution Access rate represented cost recovery for the University s five active feeders; $ per day represented cost recovery for standby feeders. EUB Decision (August 13, 2004) 179

186 The UA noted that this was different from EDI s current breakdown of the Distribution Access rate, which simply prorated the daily charge into active and standby by the number of feeders. The UA stated that EDI was currently charging it $ per day (five-sevenths of $859.50) for active feeders and $ per day (two-sevenths) for standby feeders. The UA considered that its rates should be based on cost of service. The UA noted that $ of the proposed Distribution Access rate represented cost recovery of standby feeder duct and cable and that EDI had testified that these feeders were shared with other customers. The UA noted that Exhibit showed 100% of the standby cable cost being directly assigned to the UA. Therefore, the UA believed that this $ per day should be allocated to all customers receiving service from the R23 and M25 standby feeders (including the UA). The UA noted that EDI s calculation of its rate involved dividing the annual revenue target by twelve months and again by an assumed day month, was not related to 2004 being a leapyear. As such the UA proposed that its 2004 rate, along with those of the other 16 large customers, should be adjusted downwards slightly to account for the extra day in The UA submitted that EDI should be directed to re-file the University s daily Distribution Access rate unbundled into active and standby components, as per the results of its own cost of service study. The UA noted that the Board might also wish to direct EDI to unbundle active feeder rates from standby feeder rates for all customers in the Greater than 5,000 kv.a rate class. The UA also noted that it had only been able to unbundle its own rate after four years of effort, time, and expense. The UA noted that it was inappropriate that the UA pay for the full 4 km of wire composing the Meadowlark and Rossdale feeders given that it had not received full and exclusive access to these feeders. The UA noted that during the hearing, EDI had testified that the University s R23 and M25 standby feeders were in fact shared with the University LRT station, a small amount of residential load, and a standby service for a large building and a small 4160 substation. The UA proposed that the total feeder capacity should first be divided into active and standby customers. The UA noted that because standby customers could only count on capacity that active service customers could not possibly use, the apportionment should be based on subtracting the sum of annual peak demands of active customers from the total feeder capacity. The UA further suggested that capacity for active customers should then be allocated on the peak demand of each customer. Finally, the UA suggested that remaining capacity for standby customers should be allocated on a measure of commitment, such as minimum billing demand. The UA noted that for a multiplefeeder customer such as itself, however, minimum billing demand should be adjusted to recognize that it would be impossible to draw the full minimum billing demand through a single feeder. 180 EUB Decision (August 13, 2004)

187 Views of the Board The Board notes that both the CCA and PICA recommended that a comprehensive COSS, including customers 5000 kv.a and larger, be undertaken for the 2005 test year. In its reply argument, EDI concurred with this position. Therefore, the Board directs EDI to perform a comprehensive COSS for the next GTA, including all of EDI s customers. The Board notes the uniqueness of the individual rates for EDI s 5000 kv.a and larger distribution connected customers, in contrast to the practice of other utilities to group these customers in a single rate class. For the purposes of this Decision, the Board will approve the use of individual customer rates for these large customers. However, the Board directs EDI to assess the appropriateness of continuing the use of individual rates in EDI s next GTA, with the benefit of the data from the comprehensive COSS. While the Board concurs with the UA that the CRF is based on different values than those proposed for customers less than 5000 kv.a, the Board is not persuaded that it is appropriate to change the CRF in isolation, given that each levelized customer specific rate was determined based on RCN, CRF and a PBR adjustment factor. The Board agrees with EDI that changing only the CRF would not properly consider all of the factors that go into the development of the customer specific rates. The Board also agrees with CCA that all aspects of the individual customer rates should be taken into account, not just those that might lower the UA s rate. For the same reasons, the Board does not agree with the UA that the UA s individual rate must be adjusted during a Leap Year. The Board notes that standby service to UA was discontinued effective March 29, The Board agrees with UA that the rate charged to UA effective March 29, 2004 should be reduced to $243.88/day. The Board also notes that EDI agreed with UA that the revenue loss from the Rossdale and Meadowlark standby sites should be made up by all other rate classes, who are in fact using those facilities at present. The Board considers this approach to be reasonable for the purposes of this Decision. The Board also directs EDI, at the time of its refiling, to advise the Board of its plans discontinue the physical supply of standby to UA. The Board is not persuaded that it would be appropriate to direct EDI to unbundle all of the customer specific rates into active and standby components, at this time. The Board notes EDI s commitment to provide the cost of service studies for the customer-specific rates to each affected customer upon request. The Board expects EDI to cooperate fully with any such requests. The Board considers that design and continuation of the customer-specific rates should be further addressed following completion of the next COSS Lifeline Rates The CCG raised the issue of including lifeline rates in both EESI s Regulated Rate Tariff (RRT) application and in EDI s DT application. Lifeline rates are reduced rates for certain groups of individuals for any of a number of reasons, but who share the characteristic of lower EUB Decision (August 13, 2004) 181

188 income and reduced ability to pay. Lifeline rates are not based on the cost of serving these customers, but are typically much lower than cost of service. Therefore, offering lifeline rates to these customers would require that they be subsidized by the remaining EESI and EDI customers and service providers in order for EESI and EDI to be kept whole with respect to their revenue requirements. Neither EESI nor EDI included lifeline rates in their applications for 2004 and have not previously had such rates approved in their tariffs. In Decision , the Board indicated that it would address the matter of lifeline rates for both the EESI RRT and EDI DT applications in this Decision. The following section sets out the Board s ruling on this issue for both the EESI RRT and the EDI DT. Views of the Applicants Both EESI and EDI opposed lifeline rates. EDI stated that the power company was not the best place to administer social programs. EDI considered that to do so it would have to get into activities such as means tests, age tests, or disability tests, that would just duplicate what other arms of government do. EDI stated that if it was to be a provincial policy to use utility rates for other means, that it would be the Province s decision, not EDI s, to do so. EDI felt that EDI was not be the right organization to administer such a policy direction. EESI in its argument also submitted that the implementation of lifeline rates would be so administratively complex that it would outweigh any implementation benefits. In reply argument, EDI responded to the CCG suggestion that certain groups be exempt from a franchise fee by stating that the franchise fee charged by EDI was a matter to be determined by Edmonton City Council and was beyond the Board s authority. Views of the Interveners CCG The CCG filed similar arguments in the EESI RRT and the EDI DT proceedings. The CCG reiterated from its EESI reply argument a request for the Board to direct that EPCOR and ENMAX re-examine their Terms and Conditions of Service in order to further ensure that those who were financially incapacitated due to age or disability might be assisted to maintain essential electrical service. The CCG stated that simply providing Notice or Warning of Disconnection or providing Service Limiters was not enough. The CCG noted that EESI had committed that, prior to making its 2005 RRT filing, it would commence a consultative process with customer representatives to discuss and negotiate its RRT Terms and Conditions. This consultative process could accommodate a focused review of the specific provisions of the EESI RRT Terms and Conditions that may be of concern to the CCG and that no further direction may be necessary. The CCG also acknowledged that special government involvement would also be required to assist those institutions who had assumed the obligation to care for the old and disabled but also 182 EUB Decision (August 13, 2004)

189 had to meet the burden of rising utility costs while maintaining an acceptable level of care. The CCG felt this would invite the participation of the Utilities Consumer Advocate. The CCG, while supportive of the submission filed on behalf of the Consumer Group, had two supplemental observations in addition which were of unique concern to CCG. Firstly, with respect to the issue of EDI s Terms and Conditions of Service as they apply to Lifeline Rates and Other Options, the CCG noted that although the EDI counsel did not oppose a written process to deal with lifeline rates, the EESI counsel had taken some exception to the inclusion of an excerpt from a substantial study of the National Regulatory Research Institute (NRRI) entitled Alternatives to Utility Service Disconnection. The CCG noted that this 168 page study identified 17 alternatives to Service Disconnection used in the energy sector of various states of the U.S.A. The CCG noted that this was also a public document issued by U.S. Department of Health and Human Resources, as part of a report to Congress for fiscal year The CCG submitted that these 17 alternatives to disconnection had been studied or examined as part of Low Income Home Energy Assistance Program (LIHEAP) in the U.S. The CCG felt that in contrast, the EDI Terms and Conditions of Service allowed disconnection for non-payment after appropriate notice of disconnection, with allowance for the application of a load limiting device instead of disconnection. The CCG considered, however, that little if any aid was offered by EDI or the current regulations, such as deferral arrangements that could be worked out for those suffering financial incapacity. The CCG felt that certain of the deferral or other financial arrangements did not lead to cross-subsidization, but more to a hands-on connection between consumer and the utility provider. The CCG submitted that hence a further review of the EDI policy was warranted. The CCG further noted that it was generally acknowledged that by the Regulated Default Supply Regulation, AR 162/2003, additional prohibitions to disconnection have been legislated where winter conditions and low temperatures prevail, and that this regulation was to become effective no later than October 15, The CCG also submitted that the above matters related to institutions charged with the responsibility of providing a safe home for those who generally were unable to care for themselves for various reasons, including financial circumstances. The CCG noted that these care centres were subject to the pressures of high utility costs just as individuals were, but that disconnection seldom resulted as these care centres paid their utility bills. However, the CCG considered that the sharp jump in electricity bills in recent years, coupled with cutbacks in government subsidization, had forced these organizations into potentially having to raise the charges that their residents must pay, reduce the level of care for their residents and/or close facilities. With respect to EDI s Local Access Fee, the CCG noted that some concern had been expressed by the CCA and PICA over the level of this Fee. The CCG stated that this Local Access Fee had a significant impact on the operational costs of the Not-for-Profit institutions represented by CCG (St. Michael s and Good Samaritan). EUB Decision (August 13, 2004) 183

190 The CCG noted that many such institutions were exempt from property and other forms of taxation by legislation (Municipal Government Act, Nursing Home Act, Alberta Housing Act, city bylaws, etc.), and that the CCG had currently filed objections in applications by the City of Edmonton and ATCO Gas and Pipelines Ltd., asking for total exemption from the tax imposed by the Natural Gas Franchise Agreement. The CCG requested disallowance of the EDI Local Access Fee for the Not-for-Profit institutions affected by this Application. The CCG further requested that if the Board decided that it did not have the jurisdiction to disallow this Fee, then the Board should recommend that this matter be dealt with in proceedings before the Edmonton City Council. Views of the Board The Board finds the following characterization of lifeline rates to be helpful: While the lifeline concept has been subject to various interpretations, the major premise of those advocating lifeline rates is that low-income and elderly customers can no longer pay for basic utility services, and, since such basic services are both essential and inelastic, they should be provided at an affordable rate, even if that rate is below the cost of service. 273 Lifeline rates are a specific case of rates based not on economic principles of regulation such as cost of service, but on the social principle of a customers ability to pay. 274 While the Board has some sympathy for the residents of the institutional customers represented by the CCG, it also agrees with EESI and EDI that Board consideration of a specific tariff application is an unsuitable forum within which to address the social issues raised by programs such as lifeline rates. The Board also recognizes the administrative complexities that could result from the implementation of such a program in a utility s billing system. 275 Further, in the absence of express language in the EUA authorizing the Board to set rates according to customers ability to pay, rather than according to the cost of serving those customers, lifeline rates may contravene section 121(2)(b) of the EUA. That section requires the Board to ensure that a tariff is not unduly preferential, arbitrarily or unjustly discriminatory. 276 For all of these reasons, therefore, the Board is not persuaded that it would be appropriate to implement lifeline rates for EESI or EDI. 9.3 Fee Schedule Views of the Applicant EDI noted that, with the exception of fees for providing reports respecting historical consumption to retailers, EDI s Fee Schedule was uncontested Phillips, The Regulation of Public Utilities: Theory and Practice (3d ed. 1993), at 449 [citation omitted] Bonbright, Principles of Public Utility Rates (2d ed. 1988), pp These complexities have been noted by Bonbright, at 170. See the discussions in Bonbright, supra, at , and Phillips, supra, at , as to whether lifeline rates may be unduly preferential or discriminatory in the regulatory context. 184 EUB Decision (August 13, 2004)

191 EDI included a $25 charge in its fee schedule for providing retailers with reports respecting historical consumption. EDI submitted that the evidence demonstrated that the $25 charge was reasonable, having regard to the effort required to provide the information. EDI noted that once the RDS Compliance Project is operational, the collection of historical consumption data would be automated and the charge would no longer be necessary. EDI noted that it would not be opposed to recovering these costs through its distribution tariff provided the Board is satisfied that the costs associated with retailers requests for historical customer data constitute transitional costs arising from structural changes in the electric industry and therefore should be borne by all customers, and provided that EDI is permitted to establish a deferral account for the period of time during which it is extracting historical customer information on a mechanical basis. EDI was agreeable to CG s recommendation that the Board direct EDI to review the cost of providing the fee-based services and propose any appropriate changes at its next GTA. Views of the Interveners CG CG did not propose any changes to any of the fees. However, CG expressed concern that the proposed fees might not adequately reflect the true cost of providing the services, to the advantage of some customer classes and to the disadvantage of other customer classes. CG submitted that the appropriate level of these fees should be thoroughly considered at EDI s next GTA. CG recommended that the Board direct EDI to review the cost of providing these services and propose any appropriate changes in EDI s next GTA. CCA CCA agreed with DEP s proposal to recover the costs associated with providing retailers with historical information in EDI s revenue requirement and to set up a deferral account in respect of these costs. However, CCA did not agree that these costs should be recovered from all customers through EDI s DT rates. CCA submitted that these costs would be occasioned by customers who are more attractive for retailers; if these customers were primarily the larger, non mass-market type customers, then having costs spread to all customers would result in an undue amount of costs being paid by mass-market (Residential) customers. CCA submitted that the customers that are the least attractive for competitive retailers, and who are most likely to stay with the incumbents, would pay costs for those larger, more attractive customers who are likely to exit the system. CCA therefore submitted that the costs in the deferral account should be tracked by customer class and the true-up undertaken on a customer-class basis. DEP DEP submitted that costs associated with the provision of historic customer information should be recovered through the system wide distribution tariff and thus be borne by all distribution customers. EUB Decision (August 13, 2004) 185

192 DEP noted EDI s testimony that recovery of such costs through the DT would be acceptable to EDI, provided that it was permitted to establish a deferral account for the period in time during which it is extracting historical customer information on a mechanical basis. DEP submitted that the Board should direct EDI to: 1. Remove Section from the EDI Terms and Conditions and any charges associated with the provision of historical customer data to retailers 2. Include in the DT revenue requirement the costs associated with the provision of such historical customer data; and 3. Establish a deferral account to accrue variances between forecast and actual costs for the provision of such data, to be utilized until EDI's proposed automated data extraction process is implemented. DEP submitted that the acquisition and review of historic customer consumption information by a prospective retailer is an essential step in the process of providing a customer with a competitive retail offer. DEP submitted that EDI s costs for the provision of customer information constitute transitional costs arising from structural changes in the electric industry and therefore should be recovered from all customers through EDI s DT rates. DEP submitted that the Board provided its view of the appropriate mechanism for the recovery of transition costs of this nature in Decision respecting AE s proposed processing and handling charge for customers switching from RRO service to competitive retail service. At page 36 of that Decision, the Board stated: If the Board were to be persuaded in the future of the necessity to charge a process and handling fee in addition to the DT switching fee, the Board considers that since there is a benefit to all consumers in developing a competitive retail market that provides choice to customers these costs should be borne as system wide costs and charged to all DT customers. Accordingly, the Board directs AE, if it applies for this fee in the future, to apply for the allocation of these costs as system wide costs and charged to all DT customers. DEP submitted that EDI s charge for the provision of customer information was a processing and handling fee to allow retailers to access required information in order to facilitate customer choice and respond to customer requests for competitive services. DEP submitted that the Board should apply the same rationale and parameters to EDI s charge for historic information as it applied to AE s proposed processing and handling charge in Decision , and direct EDI to allocate the costs associated with the provision of this information to all customers through its DT rates. DEP also submitted that the inclusion of costs associated with the provision of historic customer data in the DT revenue requirement would be consistent with the practices of both AE and Aquila Networks Canada (Alberta) Ltd. (now FortisAlberta Inc.) Views of the Board The Board notes that no party objected to DEP s proposal to eliminate the fee for the provision of historic customer information. The Board is persuaded that it would be appropriate to temporarily eliminate this fee on the basis that the provision of customer information constitutes 186 EUB Decision (August 13, 2004)

193 transitional costs arising from structural changes in the electric industry. However, the Board does not consider that this fee should be eliminated indefinitely, and the Board is concerned about the potential for significant costs to be incurred. Therefore, the Board directs EDI, in its refiling, to leave the fee for the provision of historic customer information on the fee schedule, but to show the fee as zero at the present time. The Board also directs EDI, at the time of its next GTA, to identify the number of requests for the provision of historic information, by retailer. The Board also considers that Section of EDI s DAS T&Cs should be retained at the present time. The Board approves the establishment of a deferral account to accrue the differences between forecast and actual incremental costs included in EDI s revenue requirement for the provision of historic customer information. The Board agrees with CCA that the deferral account should be tracked and trued-up by customer class. The Board directs EDI, in its refiling, to identify the incremental costs, if any, included in its revenue requirement for the provision of historic customer information and to confirm the incremental cost per request that will be accrued in the deferral account. The Board notes EDI s evidence that the incremental cost per request was expected to be approximately $10 until the automated data extraction process is implemented. 277 The Board considers the other fees proposed by EDI to be reasonable, and the Board approves the other fees as proposed. The Board notes EDI s commitment to review the costs of providing the fee-based services and propose any appropriate changes at its next GTA. 9.4 Terms and Conditions Views of the Applicant EDI s Terms and Conditions of Service (Terms and Conditions) are comprised of Terms and Conditions for Distribution Access Service (DAS T&Cs), which deal with the relationship between EDI and Retailers, and Terms and Conditions for Distribution Connection Services (DCS T&Cs), which deal with the relationship between EDI and end customers. With the change in regulatory jurisdiction over EDI, EDI undertook a complete review and revision of its Terms and Conditions to ensure general consistency with other Board-regulated utilities. During the proceeding, EDI proposed amendments to its Terms and Conditions to deal with the new requirements of the DT Regulation, which are expected to become effective in October EDI s Retailer Handbook, Customer Guides and tariff policies are incorporated by reference into EDI s Terms and Conditions. 277 Tr. p EUB Decision (August 13, 2004) 187

194 EDI s Retailer Handbook sets out the detailed mechanics for the various business transactions between EDI and retailers, pursuant to the Settlement System Code. EDI submitted that it was unreasonable and unnecessary for EDI to be required to obtain Board approval prior to making any changes to its Retailer Handbook. EDI noted that the Settlement System Code is continually being revised, and EDI submitted that it must be in a position to react to changes to the Settlement System Code quickly. EDI also noted that the Board is currently engaged in a tariff standardization process, which may eliminate the need for portions of EDI s Retailer Handbook. EDI s Customer Connection Guide sets out processes and technical engineering requirements designed to ensure that all facilities relating to a customer s physical connection to EDI s system are properly constructed to applicable codes and standards, are safe, and will not result in harm to EDI s or other parties facilities. Although relatively few revisions are made to EDI s Customer Connection Guide on an ongoing basis, EDI submitted that there is no practical reason for requiring Board approval of changes. EDI submitted that requiring such approval would effectively cast the Board in the role of consulting engineer. EDI indicated that it would not object to filing for information its Retailer Handbook and Customer Guides. EDI indicated that it would not object to changes to EDI s tariff policies requiring Board approval. EDI noted CG s comparison of the limitation of liability in Section 10.2 of EDI s DAS T&Cs with the limitation of liability provisions in Section 2.9 of the Settlement System Code. EDI submitted that under the Settlement System Code it is carrying out the mandated functions of load settlement agent and meter data manager for the benefit of the Alberta electricity industry. EDI submitted that its liability for the performance of those functions should be limited in the same manner as AE s liability is limited under Section 13.2 of its Terms and Conditions of Distribution Access Service. EDI noted CG s suggestion that the 180-day limitation periods under Section 11.1 of EDI s DAS T&Cs and Section 14.1 of EDI s DCS T&Cs be deleted. EDI submitted that CG misinterpreted these sections and that all that is required within the 180-day limitation period is to give notice of a claim. EDI submitted that having regard to the fact that EDI s liability is limited to direct property damage under its Terms and Conditions, it was difficult to see how a retailer or customer would not be aware of such damage within 180 days of its occurrence. EDI also submitted that it was reasonable and appropriate that claims be brought to its attention to permit them to be investigated and addressed in a timely manner. EDI disagreed with AE s assertion that the effect of Section 8.1 of EDI s DAS T&Cs was to require financial security from RRT providers. EDI noted that under Section 8.1 of EDI s DAS T&Cs a retailer is only required to provide the security deposit required under the DT Regulation, and that the DT Regulation does not require RRT providers to provide a security deposit. EDI submitted that the contribution levels under EDI s policy have been established on a reasonable basis and provide appropriate incentives to developers. EDI submitted that the policy has been in place for a considerable period of time (since 2000 on the residential side and since the early 1990s on the commercial and industrial side), and reflects the historical practice in 188 EUB Decision (August 13, 2004)

195 neighboring distribution service areas. EDI submitted that its contribution policy should be approved as applied-for. EDI noted CG s submission that EDI should be directed to undertake a review of the contribution policies and practices of other distribution utilities in Alberta for its next GTA. EDI indicated that this was EDI s intention. EDI disagreed with CG s argument that EDI s disclosure of customer information to a third party research company was unlawful because it was not authorized by EDI s Terms and Conditions, the Code of Conduct Regulation, or the Personal Information Protection Act (PIPA). EDI submitted that in Alberta, the use and disclosure of personal customer information is governed by PIPA. EDI submitted that its collection, use and disclosure of personal information about its customers fully accords with PIPA. EDI submitted that since PIPA applies to every organization and in respect of all personal information, no useful purpose would be served by amending EDI s Terms and Conditions to authorize the release of personal information to a third party research company. EDI also submitted that the Code of Conduct Regulation is not intended to apply in this context, but rather to situations in which an owner proposes to provide information to one or more retailers. Views of the Interveners AE AE submitted that there was a reasonable argument that Section 8.1 of the DAS T&Cs could be interpreted as mandating EDI to require security from its RRT provider. AE noted that it sought the right to require security from an appointed RRT provider via an amendment to its Terms and Conditions, and was expressly denied this right in Decision AE submitted that the Board should accord similar treatment to all Board-regulated utilities. CG CG submitted that EDI should be required to file with the Board any minor changes to the Retailer Handbook, as long as EDI confines those changes to minor items that arise out of matters such as changes in legislation or that are necessitated by changes to the Settlement System Code. For policy type changes to the Retailer Handbook, CG submitted that Board approval should be obtained. CG submitted that where any cost increases to retailers are anticipated as a result of changes to the Retailer Handbook, EDI should be directed to have prior consultations with retailers. CG also submitted that the Board should consider implementing a province wide standard review of all Retailer Handbooks issued by regulated distribution companies. CG submitted that any costs forming part of EDI s 2004 revenue requirement should not be shifted to Retailers via changes to the Retailer Handbook. CG submitted that EDI should be required to file its Customer Guides with the Board, with clear identification of any changes and highlighting reasons for the changes. CG submitted that based on Section 10.2 of EDI s DAS T&Cs, EDI would not be liable for any damages directly or indirectly resulting from performing its meter reading obligations under the Settlement System Code. CG submitted that Section 2.9 of Version 9.3 of the Settlement System EUB Decision (August 13, 2004) 189

196 Code is intended to only cover errors in estimations developed, and not errors resulting from actual meter reads. CG submitted that a wire services provider should not be absolved from performing its statutory responsibilities under the Settlement System Code, one of which is performing actual meter reads, if it does so negligently, even if done in good-faith. CG submitted that a more appropriate wording for EDI s Article 10.2 would be similar to Section of Aquila s T&Cs and should therefore read: The process of Retailer load estimation involves statistical samples and estimating error. EDI shall not be responsible for any sampling or estimating errors and shall not be liable to any Retailer or Customer for any costs that are associated with such errors. CG noted that EDI acknowledged that in Section 11.1 of the DAS T&Cs and in Section 14.1 of the DCS T&Cs, the words or omission should be included after the words or willful act. CG submitted that EDI should be directed to include these words in its refiling. CG submitted that the second paragraph in Section 11.1 of the DAS T&Cs and the second paragraph in Section 14.1 of the DCS T&Cs, containing the 180-day limitation period, ought to be deleted. CG submitted that the 180-day period was unfair, not reciprocal and not necessary. CG submitted that the Limitations Act prescribes a 2-year limitation period, which is sufficient. CG noted that there was no 180-day time limit in AE s T&Cs. CG submitted that absent demonstrated exigent circumstances, customers and EDI should be entitled and subject to the full limitation period provided by the Limitations Act. CG submitted that the Board should amend the definition of Customer in Section 2.1 of the DCS T&Cs to read includes a Load Customer and a Distributed Generation Customer. CG noted that EDI agreed to this amendment. 278 CG noted that EDI acknowledged that it would not object to inserting the word new before the words multiple dwelling in Section 8.3 of the DCS T&Cs. CG submitted that EDI should be directed to incorporate this change in its refiling. CG submitted that EDI s disclosure of customer information to a third party research company was not authorized by EDI s Terms and Conditions, the Code of Conduct Regulation or PIPA. CG submitted that the Code of Conduct Regulation exceptions to the disclosure of customer information without customer consent do not specifically allow disclosure to a third party research company. Similarly, CG submitted that PIPA does not have an exception governing disclosure to a third party research company. CG submitted that EDI s Terms and Conditions need to be amended and proper and informed customer consent needs to be obtained. Views of the Board The Board notes that EDI did not object to filing for information its Retailer Handbook and Customer Guides. The Board considers that it would be appropriate for EDI to file its Retailer Handbook and Customer Guides with the Board for information. 278 Tr. pp EUB Decision (August 13, 2004)

197 Therefore, the Board directs EDI, at the time of its refiling, to file for information its Retailer Handbook and each of its Customer Guides. The Board also directs EDI to file for information any future revisions to its Retailer Handbook or Customer Guides. The Board notes that EDI did not object to the requirement for Board approval of changes to EDI s DT policies. The Board agrees that changes to EDI s DT policies should be subject to Board approval. The Board directs EDI, in its refiling, to append each of its DT policies to its Terms and Conditions. The Board notes that EDI did not object to the wording changes proposed by CG with respect to the definition of Customer in Section 2.1 of the DCS T&Cs, with respect to the addition of the word new in Section 8.3 of the DCS T&Cs, or with the addition of the phrase or omission in Section 11.1 of the DAS T&Cs and in Section 14.1 of the DCS T&Cs. The Board notes that some of these changes had already been incorporated by EDI during the course of the proceeding. In any event, the Board agrees with these proposed changes and directs EDI to incorporate these changes in its refiling. With respect to Section 4.2 of the DCS T&Cs, the Board notes that EDI was not concerned about the legal age requirement for mass-market customers. 279 The Board considers that there should be no legal age requirement for residential customers, and the Board directs EDI, in its refiling, to amend Section 4.2 to clarify that the legal age requirement does not apply to residential customers. The Board notes that EDI did not object to amending Section 6.10 of the DAS T&Cs to clearly set out that EDI had the right to disconnect service in the event of unauthorized use. 280 The Board considers that this would be a useful clarification and directs EDI to incorporate this clarification in its refiling. With respect to Section 8.1 of the DAS T&Cs, the Board agrees with EDI that retailers are only required to provide the security deposit required under the Distribution Tariff Regulation, and that the Distribution Tariff Regulation does not require RRT providers to provide a security deposit. The Board does not consider that any changes or clarifications are required to Section 8.1 of the DAS T&Cs. With respect to Section 10.2 of the DAS T&Cs regarding liability, the Board notes that EDI s proposed clause is the same as the Board has previously approved for AE. The Board is not persuaded that a change to Section 10.2 of the DAS T&Cs is required at this time, but the Board directs EDI to address the concerns raised by CG with respect to liability for meter reading at the time of EDI s next GTA application. With respect to the 180-day limitation in the second paragraph of Section 11.1 of the DAS T&Cs and the second paragraph of Section 14.1 of the DCS T&Cs, EDI has not persuaded the Board that the circumstances of EDI s DT warrant a departure from the general statutory limitation period of 2-years. The Board directs EDI, in its refiling, to delete the second paragraph of Section 11.1 of the DAS T&Cs and the second paragraph of Section 14.1 of the DCS T&Cs Tr. pp Tr. p EUB Decision (August 13, 2004) 191

198 The Board notes EDI s intention to undertake a review of the contribution policies and practices of other distribution utilities in Alberta for its next GTA. The Board considers that such a review would be useful and encourages EDI to specify, to the greatest extent possible, the practices used in determining contribution policies. The Board encourages EDI to consider in its review the ease with which customers are able to understand the contribution policy and how it is applied. The Board notes CG s submission that disclosure of customer information to a third party research company was not authorized by EDI s Terms and Conditions, the Code of Conduct Regulation or PIPA. In the Board s view, the disclosure of customer information is governed by the terms of the Code of Conduct Regulation and any exemptions from the restrictions on disclosure of that are within the discretion of the Market Surveillance Administrator, not the Board SYSTEM ACCESS SERVICE TARIFF 10.1 SAS Cost of Service The Board will address general EDI SAS Cost of Service Study issues in this section. The Board notes that the SAS costs incurred by EDI result from charges imposed by the AESO. Views of the Applicant EDI stated that it did not complete a cost of service study (COSS) to determine its SAS rates. EDI noted that the Board had directed distribution utilities to flow the cost of transmission through to their customers, and to achieve this objective, EDI had designed its System Access Service (SAS) rates to match the AESO s rates and charges as closely as possible. EDI noted that its transmission costs come from two sources: either through the AESO s DTS tariff and riders or (for the Annexation area PODs) through Aquila Networks Canada (Alberta) Inc. s (now FortisAlberta) Distribution Tariff (in lieu of the AESO s charges at the 25 kv interchange points). EDI stated that Aquila s tariff had separate components for transmission and distribution, and only the transmission component was treated as a transmission cost by EDI. EDI noted that the distribution component of Aquila s tariff was included in EDI s DAS revenue requirement. EDI stated that both the AESO rates and Aquila rates applicable to EDI were subject to approval by the EUB, and therefore, it was EDI s view that subjecting these rates to another cost of service study would be redundant. EDI s submitted that its formula-based conversion of the AESO s rates to the SAS rates did not require a cost of service study, and thus no such study was conducted. EDI submitted that no party had taken issue with EDI s approach in this regard, and that the record demonstrated that EDI s approach was appropriate and reasonable. 281 In the Board s view, the Code of Conduct Regulation governs the use that can be made of customer information by the owners of electric distribution systems and their affiliated retailers, including their RRT providers. EDI suggested that the Personal Information Protection Act (PIPA) had some application, but the Board does not share that view. In any event, disclosure of information under PIPA is within the discretion of the Information and Privacy Commissioner, not the Board. 192 EUB Decision (August 13, 2004)

199 In reply EDI noted that for the purposes of EDI s 2004 GTA, PICA considered that EDI s proposed SAS COSS reflected a reasonable approach to flowing AESO charges through to customers. EDI noted PICA s submission that in EDI s COSS the ratio of AESO billing demand to AESO peak demand by class was not fully supported and recommended that such an analysis should be provided at EDI s next GTA. EDI emphasized that the COSS (Schedule SAS-1) reviewed by PICA was strictly for illustrative purposes. EDI submitted that substituting different values for the AESO billing demand to AESO peak demand ratios (Schedule SAS-1, column E) would have absolutely no impact on the determination of the SAS rates. EDI stated that the only two other required elements in EDI s SAS rate design methodology, namely the diversity factors and distribution loss factors, were fully supported by the Load Diversity Study (Application, Appendix N) and the Distribution Loss Study (Application, Appendix M) filed in this proceeding. EDI stated that, for these reasons, PICA s recommendation should not be adopted by the Board. Views of the Interveners PICA PICA noted that EDI set out the revised SAS cost of service and revenues in Exhibit PICA submitted that the cost of service study indicated how the billing determinants at the customer meter were converted to billing determinants at the POD using statistical methods. PICA further submitted that the AESO tariffs were then applied to calculated billing determinants at the POD. PICA submitted that two of the key factors used in converting billing determinants at the customer meter to billing determinants at the POD were coincidence factors by rate class (Column I of Exhibit ) and the ratio of billing to peak demand. (Column E of Exhibit ) PICA stated that Appendix N, the load diversity study, showed how coincidence factors were calculated by rate class. PICA noted EDI s explanation that the ratio of billing to peak demand for each rate class was calculated by reference to historical ratios. PICA suggested that the ratio of billing to peak demand used in the SAS cost of service study was not fully supported by any analysis. PICA believed such an analysis should be provided at the time of the next GRA to examine the appropriateness of the ratios. PICA stated that for the purposes of this proceeding, PICA considered EDI s proposed SAS cost of service study reflected a reasonable approach to flowing AESO charges to the various classes of customers. Views of the Board The Board has dealt with the complexity of the EDI SAS rates in the following section of this Decision. In that section, the Board directs EDI to develop simpler rates more in line with the precision of the billing data available to EDI. The Board notes that these simplified rates will differ from the more complex AESO rates. To support the development of these simplified SAS rates, the Board considers that a SAS COSS is required. EUB Decision (August 13, 2004) 193

200 Therefore, the Board directs EDI to develop a SAS COSS, which demonstrates how all components of the AESO tariff will be allocated to EDI s rate classes and to include this SAS COSS in its November 1, 2004 application for simplified rates effective January 1, SAS Rate Design Complexity of Method The majority of the Views of the Applicant and Views of the Interveners on the complexity of the EDI tariff design are contained in Section of this Decision. For brevity, the Board will not reiterate those views in this section but will instead include views that pertain specifically to the proposed EDI SAS tariff. Section and this section are meant to work together such that the complexity of the overall tariff is addressed. Views of the Applicant EDI submitted that its SAS rates were designed to match, as closely as reasonably possible, the AESO s transmission charges, and that coupled with EDI s applied-for Transmission Charge Deferral Account, the design of EDI s SAS rates would ensure that each customer paid its fair share of the AESO s approved costs of providing transmission service while ensuring that EDI was kept revenue neutral in the process. EDI noted that its Special Transmission Rider was approved by the City of Edmonton as authorized under section 4.3 of the DT Regulation, and that this rider terminates on December 31, EDI noted that the UA s proposed Special Transmission Rider (A-25) stated that the Special Transmission Rider would track the transmission charges of the AESO and 25 kv interchange charges of Aquila. EDI stated that there was no such charge in respect of 2004, as it had stated in CCA-EDI-2(a), and that this was further confirmed by the zero balance on Schedule D-22, Transmission Charge Deferral Account. EDI submitted that should a material transmission deferral account balance arise, EDI would make an appropriate application to the Board for its disposition, but that EDI could see no reasonable basis for taking steps to confuse any such deferral account rider with the Special Transmission Rider, which would be extinguished at the end of Views of the Interveners UA The following table lists the UA concerns with the proposed EDI SAS tariff: Table 22. Concerns with Proposed EDI SAS Tariff per UA Page Concern Solution 5 With changes proposed in Table 10, reference to Normal Delete reference. Maximum Demand is redundant. 6 Demand charges as same for three rate class, two of which are energy metered. Re-allocate transmission costs in EDI spreadsheet SAS Revenue using rate class load data from DAS-11. Re-calculate an energy only rate for 6 Time of use Operating Reserve Charge for non-interval metered customers. energy metered rate classes. Recover as per-kwh charge using revenue target from EDI spreadsheet SAS Revenues and rate class load data from DAS EUB Decision (August 13, 2004)

201 Page Concern Solution 6 With suggested changes, reference to diversity and line Delete reference. loss factors is redundant. 6,8,10,12 Reference to calculation of billing demand page is Add reference missing for demand metered rate classes. 8,10,12 Diversity and line loss factors apply to all customers in rate class. Rate sheet not explicitly show how line loss factors are used. Multiply Demand Charge and Other System Support Charge by diversity factor. Multiply Variable and Operating Reserve charges by line loss factor. 8,10,12 Calculation of Operating Reserve Charge is confusing. Clarify that percentage rate is applied to the wholesale value of energy, as determined by the hourly spot market. Add mathematical formula. 10 Title of rate class and latter half of Applicable section is inconsistent with Distribution Access document. Delete Primary and Secondary from title. Delete latter half of Applicable section (whether or not a transformer is included is addressed in customerspecific rate) 10 Redundant definition of Peak Monthly Demand. Delete reference. 10 Missing reference to Totalization Policy Add reference. Specify different rate based on 100% diversity factor. 14,16 Demand and variable charges for unmetered customers. Where rate class is a single customer, convert to per-kwh charge. Where rate class is many customers, convert to per-site daily charge. Use revenue target from EDI spreadsheet SAS Revenues and rate class load data from DAS Franchise not applicable to pass-through of transmission Delete reference. charges. 20 Definition of billing demand overly complicated. See changes to Distribution Access in Table 11. Confusing ratchet. 20 kw to kv.a conversion inconsistent with System Access. Use either 0.9 or 0.92 in both documents. 24 Application guide unnecessary Delete reference. It was the UA s position that EDI be required to re-file a tariff schedule that incorporated the solutions presented in the above table. To facilitate this process, the University provided as an attachment to their argument a sample tariff schedule that incorporated the solutions discussed above. In Reply, the UA noted that Section of the EDI argument suggested that its proposed tariff structure was the best means to flow-through provincial transmission costs. The UA stated that its suggested tariff structure was equally proficient in flowing through provincial transmission costs, and that this could be mathematically proven using the following equation representing the total charges ( C ) paid by an energy-metered customer: Where: C = p d D + p c E p d and p e were the demand and energy charges, respectively. D and E represented billing demand and energy consumption. However, because D was not measured for an energy-metered customer, it must be estimated using an assumed ratio that was constant for all customers in the rate class. Therefore, the equation could be expanded as follows: C = p d [ExL] + p c E EUB Decision (August 13, 2004) 195

202 Where L was EDI s assumed conversion factor that converted energy consumption into a deemed billing demand. In this example, L would likely be a load factor percentage divided by the number of hours in a month. The UA noted that what it had done in its simplified tariff example was to group terms into those determined independently from the individual s actions and that which is based on individual consumption. C =[Lp d + p c ] x E The UA stated that whereas EDI conceptually proposed to charge a two-part rate with prices p d and p e, the UA proposed to simplify the formula such that the customer observed a single price that was mathematically equivalent to Lp d +p e. The UA noted that the amount in dollars paid by a customer did not change and therefore, the pricing signal remained identical. The UA noted that tariff structures that used on and off-peak energy charges for a customer that could not be metered on a time-of-use basis could and had been simplified in the UA s tariff example in the exact same manner. The UA submitted that the same principle also applied to coincidence and loss factor terms that applied to all customers in a rate class. The UA stated that it had identified specific examples in Table 9 of its argument. The UA noted that because of EDI s continued assertion that too much simplification could in itself create barriers to entry, the UA too would reiterate that a simplified tariff does not constitute a barrier to retailer entry. The UA further reiterated that a complex tariff increased administrative costs to retailers (and to customers including the University) and in this sense, would be a barrier to entry. Views of the Board For the same reasons as set out in a previous section regarding the complexity of the DAS rates, the Board considers that the proposed SAS rates submitted by EDI are overly complex, especially given the nature of billing data available to EDI. The Board notes EDI s request that, should it be directed to simplify its rates, it be given until January 1, 2005 for implementation to allow it time to update its billing system. The Board concludes that EDI s SAS rates should be simplified in line with the practices of the other electric distribution utilities in Alberta. However, the Board will approve continuation of EDI s proposed SAS rate structures until December 31, The Board directs EDI to apply, no later than November 1, 2004, for simplified SAS rates to be effective on an interim basis January 1, EUB Decision (August 13, 2004)

203 11 FRANCHISE FEE EDI has been granted the right by the City of Edmonton (City) to provide electric distribution service within the municipal boundaries of the City for some time. This right has been granted by way of a franchise agreement pursuant to section 45 of the Municipal Government Act, RSA 2000, c. M-26 (MGA), which obliges EDI to pay a franchise fee to the City in exchange for the right. When EDI filed its Application, its existing franchise agreement had been in place for several years. During the hearing, EDI advised the Board that the old agreement had expired on December 31, 2003 according to its terms. In particular, EDI advised the Board that the old agreement provided that it would expire upon a change in regulatory authority. 282 As of January 1, 2004, the Board became EDI s regulatory authority rather than City Council. Accordingly, EDI filed a copy of its new Franchise Agreement with the City as an attachment to Exhibit (Agreement). Section 5.1 of the Agreement obliges EDI to pay a franchise fee (Fee) to the City in the following terms: 5.1 Subject to Section 5.3 herein, in consideration of the rights granted to EDI by the City pursuant to this Agreement, EDI agrees to pay the City during the term of this Agreement, the amounts calculated pursuant to Schedule A attached hereto and forming part of this Agreement. The amounts payable by EDI to the City pursuant to this Section 5.1 shall be referred to in this Agreement as the Fee. As set out in Schedule A to the Agreement, the Fee for 2004 is $26,658,000 (or such other amount as may be determined by the City and notified in writing to EDI). The Fee is to be collected by EDI on a fractional dollar amount per kwh of electric power (i.e. /kwh) distributed to customers and recorded on meters each month. The fractional dollar amount is to be communicated in writing by the City to EDI from time to time. Schedule A also describes such matters as the manner in which the Fee shall escalate from year to year and the City s discretion to set a different Fee or Rate. The term of the Agreement is 20 years Board Jurisdiction Views of the Applicant EDI submitted that subsection 138(3) of the EUA empowers a municipality to impose in respect of an electric distribution system of the municipality amounts that are in addition to the rates approved by the Board provided that the amounts imposed satisfy the requirements of paragraphs 138(3)(a) and (b). Moreover, since such amounts may be imposed... notwithstanding... anything in this Act, the Board has no jurisdiction to address either the magnitude of those amounts or the manner in which they are to be collected. EDI submitted that, for the following reasons, the franchise fee set by the City of Edmonton is an amount imposed in respect of the EDI electric distribution system in accordance with subsection 138(3) of the EUA and should therefore not be considered in this proceeding. EDI is required, by virtue of subsection 102(2) of the EUA and section 4 of the DT Regulation to apply to the Board for approval of its distribution tariff. The EDI distribution system is therefore an electric utility as defined in paragraph 1(1)(o) of the EUA. In addition, the EDI system is a 282 Tr. p. 1522; Exhibit EUB Decision (August 13, 2004) 197

204 distribution system of a municipality as that phrase is used in section 138(3). In this regard, it is noteworthy that, in contrast to subsection 138(1), subsection 138(3) of the EUA does not require direct municipal ownership of the system in question. This makes it clear that the words distribution system of a municipality have a broader meaning than distribution system owned by a municipality. No reasonable interpretation of section 138(3) would exclude EDI from the application of the section. In reply EDI noted that contrary to the position advanced by EDI in its argument, each of the CCA, PICA and the UA argue that it is within the jurisdiction of the Board to address both the magnitude of the franchise fee imposed under the Franchise Agreement and the manner in which the related amounts are to be collected from customers. Despite its position concerning jurisdiction, the CCA makes no specific recommendation in respect of the EDI Franchise Agreement or the franchise fee. Rather, the CCA suggests that... it would not be unreasonable for the Board to require, in future, utilities to summarize [their negotiations with their parent municipalities]. Both PICA and the UA advocate changes to the method through which the franchise fee is to be collected from customers. There is the further suggestion that changes to the method could be adopted even if the Board were to determine that it lacks jurisdiction to approve or modify any portion of the Franchise Agreement. EDI noted that both the CCA and the UA acknowledge that, pursuant to paragraph 139(1)(b) of the EUA, no approval is required from the Board in respect of a right to distribute electricity granted by a municipality to its subsidiary. PICA did not advance a separate argument concerning jurisdiction but supported the CCA comments and recommendations in that regard. Nevertheless, the CCA and the UA both say that the Board may review the reasonableness and appropriateness of the costs to customers of the franchise fee. The CCA cites no statutory basis for such jurisdiction other than section 5 of the DT Regulation while the UA relies on section 360 of the MGA or, alternatively, section 102 of the EUA. Curiously, neither the CCA nor the UA makes any mention of subsection 138(3) of the EUA, which was discussed at some length in the EDI Argument. Similarly, the CCA and UA have not cited subsection 28.1(2) of the EUA (sic MGA) which states that, in the event of an inconsistency between the EUA and the MG Act in respect of a municipal tariff matter, the EUA prevails. In that regard, there can be no doubt that the collection by EDI of the franchise fee is a municipal tariff matter as defined in paragraph 28.1(1)(a) of the EUA (sic MGA). Subsection 360(1) of the MG Act empowers a municipal council to make a tax agreement with an operator of a public utility but subsection 360(3) of the Act says that any such agreement with an operator who is subject to regulation by the Public Utilities Board is of no effect unless it is approved by the Public Utilities Board. EDI noted that section 5.4 of the Franchise Agreement expressly states that the franchise fee is not in lieu of taxes or local improvement charges and the UA acknowledges that prima facie that would appear to exclude any power in the Board to approve or disapprove the Franchise Agreement. Undeterred, the UA argues that the Franchise Agreement is in substance a tax 198 EUB Decision (August 13, 2004)

205 agreement and that the Board therefore has jurisdiction to review and approve it. Simply stated, the UA does not overlook section 5.4 of the Franchise Agreement. It simply urges the Board to ignore it. With all due respect to the UA, the Board cannot be nearly so cavalier. It would be entirely unreasonable and unfounded to conclude, as the UA would have the Board do, that EDI and the City of Edmonton have engaged in a subterfuge and that section 5.4 was included in the Franchise Agreement merely to conceal the parties true intentions. It is particularly noteworthy that the UA was unable to cite any evidence to support its position. Rather, it offered only rank speculation that some unstated portion of the franchise fee must be in lieu of property taxes payable in respect of the licenses granted to EDI. Moreover, there is no explanation from the UA as to how the Franchise Agreement satisfies the requirement in subsection 360(3) of the MGA that a tax agreement... provide that the municipality accepts payment of the amount calculated under the agreement in place of the tax and other fees or charges specified in the agreement. The fact is that there is no such provision in the Franchise Agreement and certainly no reason that it could be supplied by implication. There is simply no basis upon which to conclude that section 360 of the MG Act affords the Board any jurisdiction in respect of the Franchise Agreement. There is similarly no basis for the Board to conclude that either its plenary jurisdiction under section 102 of the EUA (to approve a distribution tariff) or its general jurisdiction under section 5 of the DT Regulation (to consider the reasonableness of costs) empowers it to consider either the franchise fee or the method for its collection. EDI submitted that the franchise fee set by the City of Edmonton is an amount imposed in respect of the EDI electric distribution system in accordance with subsection 138(3) of the EUA. The effect of subsection 138(3) of the EUA is to remove the jurisdiction of the Board to consider additional amounts such as the franchise fee in this case that are imposed by a municipality so long as the requirements of paragraphs 138(3)(a) and (b) are satisfied. Views of the Interveners CCA The CCA submitted that while the LAF agreements may not appear to require Board approval, the costs arising from those agreements and charged to customers are within the EUB s jurisdiction and mandate. Like any other cost EDI proposes to include in its final tolls and charges, the LAF should be subject to the Board's review to determine whether it is reasonable and prudently incurred. While it is arguable agreements between a Municipal government and its wholly owned utility may not require approval of the agreement by the EUB, the CCA submits the EUB does have the jurisdiction and responsibility to assess the reasonableness of the costs included in the utility's revenue requirement and final tolls and charges resulting from such agreements. With regard to approval of the agreements, section 139 of the new Electric Utilities Act [S.A c. E-5.1] and its predecessor, s. 61 of the then EUA [S.A as amended] state: s.139(1) A right to distribute electricity granted by a municipality b) to a subsidiary of the municipality does not require Board approval. EUB Decision (August 13, 2004) 199

206 s.61(4) Where a municipality grants a right under subsection (1) to its subsidiary, the grant need not be approved by the Board. Consequently, the CCA stated that it appears evident Board approval may not be required to enter into the agreements. However, what is at issue in this proceeding is the reasonableness of the costs included in EDI s final rates, including the LAF. In CCA s submission, that is clearly within the Board's jurisdiction. As section 5 of the DT Regulation states: 5. When considering an application for approval of a distribution tariff under section 102 of the Act the Board must examine the reasonableness of the owner's billing costs, and other costs the Board considers appropriate in the prevailing circumstances, without regard to any overall increase in costs due to the separation of distribution access service and the provision of electricity services. CCA notes there is no limitation on the types of costs to be considered by the Board except that they should be considered appropriate in the prevailing circumstances. In CCA s submission, the franchise fee is analogous to other costs incurred by EDI. For example, EDI's corporate costs are allocated to EDI from the parent corporation. While the Board may not have jurisdiction in relation to the parent company and any arrangements it may have with EDI, it does have jurisdiction over the reasonableness and appropriateness of the costs allocated to EDI and included in its final rates. Similarly, EDI may not require EUB approval to enter into a contract for goods or services with a third party. However, the costs associated with the contract and included in the utility's revenue requirement are a matter of Board jurisdiction and review. Therefore, based on the foregoing, the CCA submits the EUB does have jurisdiction to review and determine the reasonableness of the costs arising from Franchise Fees. In the end, these are regulated utilities incurring costs ultimately paid by ratepayers. The EUB is the regulator of these utilities. The role of the regulator is to review the costs and allow recovery of those costs that are reasonable and prudently incurred. Finally, the CCA submits, in the absence of any review of the costs related to the franchise fee, there is no accountability by the utility in ensuring it is negotiating in the best interests of its customers. The absence of such review would also leave customers in serious doubt as to whether these agreements were truly the result of negotiations, or merely a placid acceptance of the terms of the agreements by the utility. As costs must be not only reasonable, but prudently incurred, the absence of any review of the circumstances leading to the final agreement or any evidence to support the reasonableness of the terms, raises questions as to the prudence of the associated costs. In the CCA s submission, it would not be unreasonable for the Board to require, in future, utilities to summarize such negotiations and provide evidence supporting the terms agreed upon under these Local Access Fee Agreements/Franchise Fee Agreements. 200 EUB Decision (August 13, 2004)

207 PICA PICA has reviewed the CCA s Argument and supports the comments and recommendations set forth in that submission. In particular, while the franchise fee agreements do not appear to require Board approval, PICA submits the costs arising from those agreements and charged to customers are within the EUB s jurisdiction and mandate. Like any other cost EDI proposes to include in its final tolls and charges, the franchise fee should be subject to the Board's review to determine whether it is reasonable and prudently incurred. UA The UA noted that on February 24, 2004, the Council of the City of Edmonton (the City) approved an agreement permitting EDI to distribute electric power within Edmonton pursuant to the terms of a franchise fee agreement between the City and EDI. 283 The agreement attached as Schedule A to the Bylaw replaced an original franchise fee agreement that was eight years old. 284 The City further directed that the fee for 2004 would be $26,658, to be collected from customers on the basis of a fractional dollar amount per kwh of electric power distributed to Customers. 285 The Franchise fee is described in section 5.4 of the Franchise Agreement as a charge for the use of the City Lands and is not in lieu of taxes (including, without limiting the generality of the foregoing, business, property and linear property taxes). 286 Section 45 of the MGA 287 authorizes the granting of a franchise and section 61 authorizes the imposition of fees, tolls and charges for the use of City lands. Section 45(5) specifically exempts the requirement for Board approval in the case of agreements between a municipality and its subsidiary. That exemption is confirmed in section 139 (1)(b) of the EUA. 288 The issue before the Board is whether it has any jurisdiction with respect to the level of the franchise fee and the collection from customers. There are two possible sources of jurisdiction with respect to the franchise fee agreement. First, Section 360 of the MGA provides that a tax agreement provided for under that section, with an operator of a public utility subject to regulation by the Board, has no effect unless it is approved by the Board. This section is no doubt the successor to section 14 of the Municipal Taxation Act 289 (now repealed) dealing with special franchises. EDI stated 290 and the agreement expressly states that the fee does not include any sums in lieu of property taxes. Prima facie that would appear to exclude any power in the Board to approve or disapprove the franchise fee agreement. The property and linear taxes paid by EDI are set out in Schedule D-3 of EDI s filing, and EDI stated that it is responsible for property taxes on all of its facilities. 291 That schedule shows a forecast total linear property tax of $4.9 million (linear property does not Attachment to Exhibit , Bylaw Exhibit , response to Undertaking at Tr. pp Exhibit , Schedule A to Bylaw Exhibit , Franchise Fee Agreement, section 5.4 RSA 2000, c. M-26 RSA 2000, c. E-5.1 RSA 1980, c. M-31 UA-EDI-4 IPCAA-EDI-17 EUB Decision (August 13, 2004) 201

208 include land and buildings). 292 Clearly that sum does not include any taxes that might be payable by reason of EDI s license to use City lands. Those taxes must be found in the Property tax line. EDI forecasts a total property tax payment of $300,000 for It is reasonable to conclude, based on the modest amount, that most if not all of that tax assessment relates to the Service Centre land and building shown on Schedule D-5 of EDI s filing, lines 41 and 42 as having a total value of over $29 million and the substation land and buildings shown on lines 28 and 29 (value $0.5 million). The UA submits that a reasonable reading of the application is that none of the property tax forecast relates to the other City lands, namely roads, streets, lanes, public utility lots etc specifically referred to in the franchise agreement and over which EDI is specifically granted a license. 293 Generally speaking such land is assessable. 294 Property that is non-assessable is described in section 298 of the MGA. The only relevant provision is section 298(1)(i) which excludes roads from assessment, except road rights of way held under license from the municipality and used for another purpose. Certainly EDI does hold a license to use road rights of way (in addition to other City lands) under the franchise fee agreement and does use them for a purpose other than as a road. Therefore the University submits that the franchise fee, notwithstanding the express provisions of section 5.4 of the agreement, must be at least in part in lieu of otherwise properly payable property taxes. In substance, although not in form, the University submits that the franchise fee agreement is a tax agreement, and the Board has jurisdiction pursuant to section 360 (5) of the MGA to review and approve the agreement. If the franchise fee agreement is not a tax agreement, the UA submits that there is a second basis for the Board s jurisdiction. EDI is regulated by the Board pursuant to section 102 of the EUA. The tariff to be approved by the Board is for the recovery of the prudent costs of providing distribution access service. If the franchise fee agreement does not constitute a tax agreement, it is at the very least a contract for the use of City owned facilities pursuant to section 61 of the MGA. While the Board may not have any jurisdiction to set aside the contractual arrangement between the City and EDI, it does, the UA submits, retain jurisdiction to determine whether the costs are such that the customers should bear them, that is, that they are prudently incurred costs. Furthermore, the Board, which has the jurisdiction to determine the rates to be charged to EDI s customers, must retain the jurisdiction to determine how the franchise fee is to be borne by customers. To find otherwise creates a potential absurdity. While the Board has been delegated the authority to regulate EDI s rates to its customers, the benefits of that could be effectively eliminated if the City could enter into an arrangement with its solely owned subsidiary without any recourse to customers to examine that agreement. This would be equivalent to AE arguing that any arrangement that it makes for the use of Canadian Utilities lands and buildings must be accepted by the Board and passed on to customers. For if the arrangement is not a tax agreement subject to the specific provisions of section 360 of the MGA, it is simply a contract which deserves no higher deference than any other contract entered into by the utility. The test for all such contracts is that they are prudent contracts MGA, section 284(1)(k)(i) Franchise Fee Agreement, section 2.4 MGA sections 289, 290 and EUB Decision (August 13, 2004)

209 The Board clearly has the jurisdiction to determine the prudence of costs incurred by the utility under any contract. This one should be treated no differently. In that regard, the UA is not suggesting that the Board has the jurisdiction to set aside any such contract. It is not suggesting that the Board has such jurisdiction or that it should set aside such contract. It is however suggesting that the Board can determine whether the customers should bear the full burden of the contract or bear it in the fashion that EDI has suggested. Views of the Board The Board will consider its jurisdiction in relation to the Agreement and the franchise fee payable by EDI to the City with regard to the following issues: Does the Board have jurisdiction to approve the Agreement under section 45 of the MGA? In substance, is the Agreement a tax agreement and, if so, does the Board have jurisdiction to approve the Agreement under section 360 of the MGA? Does the Board otherwise have jurisdiction under any provision of the EUA to review and approve the Fee payable by EDI to the City pursuant to the Agreement, or the manner in which the Fee is collected from customers? Does the Board have jurisdiction to approve the Agreement under section 45 of the MGA? Unlike the agreement between the City of Calgary and ENMAX, the agreement between the City of Edmonton and EDI is made expressly pursuant to section 45 and 61 of the MGA only. In other words, it purports only to be a franchise agreement and does not purport to be a tax agreement pursuant to section 360 of the MGA. In most cases, Board approval of a franchise agreement is required by section 45 of the MGA. The exception is in the case of an agreement between a municipality and a subsidiary of the municipality, as subsidiary is defined in section 1(3) of the EUA: MGA, section 45(5). Section 1(3) of the EUA defines subsidiary by incorporating by reference section 2(4) of the Alberta Business Corporations Act. The Board is of the view that EDI satisfies this definition of subsidiary since EDI is wholly-owned by the City, which is clearly a municipality as defined in section 1(1)(ii) of the EUA. In the present case, the Agreement is between the City, a municipality, and EDI, its whollyowned subsidiary. Therefore, as all parties have agreed, Board approval of the Agreement is not required and the Board has no jurisdiction to approve it. 295 Below, the Board will address the remaining question of whether the Board has any residual jurisdiction in relation to the Fee provided for in the Agreement. In substance, is the Agreement a tax agreement and, if so, does the Board have jurisdiction to approve the Agreement under section 360 of the MGA? The UA submitted that the Agreement is, notwithstanding its terms, a tax agreement within the meaning of section 360 of the MGA and, therefore, the Board has jurisdiction to approve it pursuant to section 360(5). In the Board s view, the hallmark of a tax agreement is reflected in sections 360(2) and 360(3): 295 This view is consistent with section 139(1)(b) of the EUA, which provides that a right to distribute electricity granted by a municipality to a subsidiary of the municipality does not require Board approval. EUB Decision (August 13, 2004) 203

210 (2) Instead of paying the tax imposed under this Division and any other fees or charges payable to the municipality, the tax agreement may provide for an annual payment to the municipality by the operator calculated as provided in the agreement. (3) A tax agreement must provide that the municipality accepts payment of the amount calculated under the agreement in place of the tax and other fees or charges specified in the agreement. [Emphasis added.] In the Board s view, section 5.4 of the Agreement is quite clear: 5.4 The Fee is a charge for the use of the City Lands and is not in lieu of taxes (including, without limiting the generality of the foregoing, business, property and linear property taxes) or local improvement charges payable to the City, and, subject to any other agreement between the City and EDI, EDI shall pay to the City all taxes properly assessable under the taxing authority of the City. [Emphasis added.] The Board has also held that a municipality has a right to charge both franchise fees and municipal taxes. 296 The Board considers that clear language would be required in an agreement to affect the right of the municipality to do both. Indeed, the Board considers that section 360(3) of the MGA is intended to ensure that any agreement by which the municipality suspends its separate rights to charge taxes and other fees is clear and express to that effect. The Board finds no such language in the Agreement, and finds that section 5.4 of the Agreement is clearly to the contrary, namely that the Agreement is only in respect of franchise fees under sections 45 and 61 of the MGA, not taxes otherwise chargeable by the municipality. Since the Agreement does not provide that the Fee is in lieu of all charges, including taxes, owing to Edmonton by EDI, the Board concludes that the Agreement is not a tax agreement within the meaning of section 360 of the MGA. Therefore, the Agreement does not require Board approval and the Board has no jurisdiction to consider the Fee pursuant to section 360(5) of the MGA. Does the Board otherwise have jurisdiction under any provision of the EUA to review and approve the Fee payable by EDI to Edmonton pursuant to the Agreement, or the manner in which the Fee is collected from customers? The fees charged by a municipality for the right to provide utility service within the municipality are referred to generically as franchise fees. 297 Section 45 of the MGA does not refer to franchise fees, but the right to charge such fees is expressly conferred on the municipality by section 61 of the MGA: 61(1) A municipality may grant rights, exclusive or otherwise, with respect to its property, including property under the direction, control and management of the municipality Decision , Alberta Urban Municipalities Association, Standard Electric Franchise Agreement with ATCO Electric Ltd. And UtiliCorp Networks Canada (June 19, 2001), p. 6. Local Access Fees (LAFs) and Municipal Consent and Access Fees (MCAFs) may refer either to franchise fees alone or to the charges payable by a utility to a municipality pursuant to a tax agreement under section 360 of the MGA. 204 EUB Decision (August 13, 2004)

211 (2) A municipality may charge fees, tolls and charges for the use of its property, including property under the direction, control and management of the municipality. The Board has confirmed the right of the municipality to charge franchise fees when granting a right to provide utility service to a public utility. 298 However, the Board has also held that municipalities do not have an unfettered right to impose these fees. In other words, when considering a franchise agreement for approval pursuant to section 45 of the MGA, the Board has a duty to review and approve franchise fees to ensure that customers of the utility are not exposed to unreasonable costs. 299 By the same token, Board review of the franchise fee ensures that a utility does not bind itself to an imprudent contract with a municipality, the costs of which the Board might later find to be unreasonable and, therefore, uncollectible from customers in the context of a tariff application. In exercising its jurisdiction to approve the level of the fee under the MGA, the Board has the ability to influence the relationship between the municipality and the utility directly. In other words, the exercise of the Board s MGA jurisdiction can affect the amount of the fee actually payable by the utility to the municipality. In the present case, since the Board has concluded that it does not have general jurisdiction to approve the Agreement pursuant to either section 45 or section 360 of the MGA, the Board likewise has no specific jurisdiction under those sections to review the Fee payable by EDI under the Agreement. The Board notes that an investor-owned utility usually seeks approval of a rider to collect the franchise fee payable by the utility to the municipality at the same time as the municipality and the investor-owned utility jointly seek approval of, or amendment to, the franchise agreement between them. In this way, the Board has the opportunity to consider whether the fee is prudently incurred by way of the franchise agreement and is reasonable, while also considering whether to allow the utility to recover the fee from customers. As clearly spelled out in section 122 of the EUA, the Board does have jurisdiction over the rates to be charged by a utility to its customers, including the level of costs that a utility is entitled to collect from customers through the utility s revenue requirement. Some of these costs flow from the terms of agreements between the utility and third parties, such as suppliers. Although the Board typically does not have jurisdiction over these types of agreements, so that it has no power directly to affect the financial obligations of the utility to the third party, the Board may conclude that the costs under the agreement are not prudent or reasonable and should not be fully collectible from customers. In that case, the Board will approve some lesser amount, which the utility will be entitled to collect from customers through its tariff, without lessening the utility s obligation to the third party. Notwithstanding the Board s lack of jurisdiction to review or approve the Agreement under the terms of the MGA, some parties argued that the Board nevertheless has jurisdiction to review the Fee for prudence and reasonableness as being just another cost or expense of EDI under section 122 of the EUA Decision , pp. 5-6 Decision , p. 8 The Board does not consider that section 5 of the DT Regulation adds to its consideration of this question. In the Board s view section 5 only clarifies that when considering billing and other appropriate costs, the Board must do so without regard to any overall increase in costs due to the separation of distribution access service and the provision of electricity services. In other words, section 5 is proscriptive, not prescriptive. EUB Decision (August 13, 2004) 205

212 Absent any other factors, it might be open to the Board to conclude that, while it does not have jurisdiction to influence the relationship between the City and EDI through reviewing the Agreement, it could influence the relationship between EDI and its customers through reviewing the reasonableness of the Fee. However, in a case where the Board does not have the jurisdiction to review and approve a franchise fee under sections 45 and 61 of the MGA, the Board considers that it cannot take jurisdiction over the franchise fee under section 122 of the EUA. The Board cannot do indirectly what it is prohibited from doing directly. Therefore, the Board cannot review the reasonableness of the Fee under section 122 of the EUA and cannot approve collection of the Fee in the tariff approved by the Board under section 124 of the EUA. The Board s conclusion that it lacks jurisdiction to approve the Fee is consistent with section 138 of the EUA, which makes it clear that such a Fee does not form part of a Board-approved tariff: 138(1) Any municipality that owns an electric distribution system may, by bylaw, provide that the system is an electric utility under this Act. (2) The bylaw passed has no effect unless it is approved by the Lieutenant Governor in Council. (3) If a bylaw has been passed and approved under this section or if the electric distribution system of a municipality is an electric utility under this Act, the municipality may, notwithstanding the bylaw or anything in this Act, impose amounts in respect of its electric distribution system that are in addition to the rates approved by the Board if the bills submitted to customers [emphasis added] (a) (b) clearly distinguish between the rates approved by the Board and the additional amounts imposed by the municipality, and identify the additional amounts imposed by the municipality as a surcharge or tax. EDI argued that section 138 applied to it even though it is a wholly-owned corporate subsidiary of the City, so that the municipality itself does not directly own an electric distribution system. EDI submitted that the phrase electric distribution system of a municipality must be construed to include a system owned by a municipal subsidiary. That being the case, EDI submitted that the City was entitled to impose any charges in respect of EDI s electric distribution system that are in addition to Board-approved rates, provided those charges are indicated clearly and separately on customers bills. The Board notes that predecessors of section 138(3) of the EUA referred only to a municipal system that had been brought under the EUA by way of municipal bylaw. 301 Prior to the enactment of the current EUA on June 1, 2003, an electric distribution system owned directly by a municipality or by a municipal subsidiary were not included in the definition of electric utility under the EUA and were not subject to tariff regulation by the Board unless a bylaw to that effect had been enacted and approved by the Lieutenant Governor in Council. 301 See, for example, section 60 of RSA 2000, c. E-5, and section 60 of SA 1995, c. E EUB Decision (August 13, 2004)

213 This general exemption of municipal systems from the EUA and Board regulation was modified to some extent when the definition of electric utility was altered in the new EUA. That definition is set out in section 1(1)(o) and now reads: electric utility means an electric distribution system that is used (i) (ii) directly or indirectly for the public, or to supply electricity to members of an association whose principal object is to supply electricity to its members, the owner of which (iii) (iv) (v) is required by this Act or the regulations to apply to the Board for approval of a tariff is permitted by this Act or the regulations to apply to the Board for approval of a tariff, and has applied for that approval, or passes a bylaw that has been approved by the Lieutenant Governor in Council under section 138 [emphasis added]. By virtue of section 102(2)(b) of the EUA and section 4 of the DT Regulation, EDI became obliged to apply to the Board for approval of its tariffs rather than to Edmonton City Council. Therefore, EDI became an electric utility within the meaning of the EUA generally and section 138(3) specifically. In the Board s view, these legislative changes, including the specific change to section 138(3), were made with knowledge that the electric distribution systems within Calgary and Edmonton are owned and operated by wholly-owned municipal subsidiaries. These changes were also made against the backdrop of section 45 of the MGA and the predecessors of section 139 of the EUA, which clearly exempt from Board scrutiny any franchise agreements between municipalities and their subsidiaries, such as EDI. In the Board s view, reading these provisions of the EUA together in light of their history, the Board agrees that the system owned by EDI is a distribution system of a municipality as that phrase is used in section 138(3). Therefore, the Board concludes that the City is entitled to impose amounts in respect of EDI s electric distribution system in addition to amounts approved by the Board, provided that paragraphs (a) and (b) of section 138(3) are satisfied. The Board notes that the Agreement (section 5.2 and Schedule A) clearly expresses both the level and the method of collection of the Fee imposed by the City in respect of EDI s electric distribution system. Provided the bill presentation requirements of sections 138(3)(a) and (b) are met, the Board concludes that it has no jurisdiction to review or approve the Fee contemplated by the Agreement, including the manner in which that Fee is allocated to and collected from customers by EDI. The Board will address bill presentation issues in the next section of this Decision. EUB Decision (August 13, 2004) 207

214 11.2 Bill Presentation Views of the Applicant EDI noted that Board staff asked whether the amount that EDI pays to the City of Edmonton by way of property taxes could be included in the franchise fee shown on EDI s bills. EDI submits that it would be inconsistent with the applicable legislation for the Board to direct that EDI include property taxes in the franchise fee line item on its bills to retailers. Unlike EDI s franchise fee, which is dealt with under subsection 138(3) of the EUA as described above, section 122 of the EUA includes taxes among the costs and expenses that the owner of an electric distribution system is to have a reasonable opportunity to recover. The two are treated as entirely different types of costs under the legislation and, therefore, cannot be consolidated. Indeed, adding a property tax amount to the franchise fee line on EDI s bills would be inconsistent with the requirement under subsection 138(3) of the EUA that the franchise fee be shown as a separate line item. Accordingly, EDI submits that the Board cannot direct that EDI include property taxes in the franchise fee line item on its bills. EDI agrees with the CCA that full disclosure of the franchise fee is reasonable, however, EDI submitted that it would be more appropriate to achieve full disclosure by posting the franchise fee rate on its web-site, as well as notifying all registered retailers in advance of any changes to the rate. EDI submitted the reasons for not including the franchise fee rate on EDI s rate schedule include: The level and effective date of the franchise fee rate is governed by the City of Edmonton and is subject to change during a tariff year. The City of Edmonton s time frame for finalizing the franchise fee rate may not be the same as the Board s timeframe for finalizing the rate sheets. It is quicker and more administratively efficient to disclose the franchise fee rate and changes on EDI s web-site. When combined with notifications to all registered retailers in advance of any changes, the object of full disclosure is achieved. Views of the Interveners The CCA noted that the current rate schedule dealing with franchise fees does not contain any mention of the applicable rate. In the CCA s view, in the interests of full disclosure, the franchise fee levy should be specifically identified in the rate schedule Franchise Fee and that this be incorporated in EDI s 2004 Refiling. The CCA noted that the rate schedule entitled Franchise Fee does not mention the cents per kilowatt hour charge. The CCA questioned EDI s witnesses on this point as follows: Q. But is it EPCOR s -- or, rather, EDI s intention to start to post that charge in its rate schedules shortly after it's levied by the City council? A. MR. COWBURN: We certainly don t have a problem with posting it. I just don t know where it should show up. It would seem that if it shows up in the rate schedules, 208 EUB Decision (August 13, 2004)

215 then, as approved by this Board, we'd have to be coming back to this Board to modify them. But it s certain that customers would want to know what that charge is. And I would imagine it should be communicated as part of the distribution tariff, much like the way we communicate GST. It's not in the Board-approved tariff, but it isn't an additional charge. [T2799] The CCA submitted that, in the interests of full disclosure, the franchise fee levy should be specifically identified in the rate schedule Franchise Fee and that this be incorporated in EDI s 2004 Refiling. Views of the Board As noted earlier, section 138(3) of the EUA imposes the following bill presentation requirements in respect of amounts imposed by the municipality in addition to the rates approved by the Board: 138 (3) If a bylaw has been passed and approved under this section or if the electric distribution system of a municipality is an electric utility under this Act, the municipality may, notwithstanding the bylaw or anything in this Act, impose amounts in respect of its electric distribution system that are in addition to the rates approved by the Board if the bills submitted to customers (a) clearly distinguish between the rates approved by the Board and the additional amounts imposed by the municipality, and (b) identify the additional amounts imposed by the municipality as a surcharge or tax. Some parties argued that the property taxes payable by EDI to the City should be included in the separate line item contemplated by section 138(3) of the EUA. However, the Board agrees with EDI that property taxes and franchise fees are subject to entirely different treatment under the applicable legislation. In particular, as the Board has concluded, the Fee is an amount that the City is entitled to impose and which EDI is entitled to collect from customers without Board approval. Property taxes of the City, however, are an item of cost that the Board is obliged and entitled to review in the course of determining EDI s revenue requirement under section 122 of the EUA. The Board can affect the amount that EDI may recover from customers in respect of property taxes; it cannot do so in relation to the Fee. Therefore, in the Board s view, it would be inappropriate to consolidate the two amounts for billing purposes. Indeed, since one amount is Board-approved and one is not, consolidating the two would contravene section 138(3)(a) of the EUA. The Board considers that section 138(3) of the EUA reflects an important policy, namely that Board approved rates ought not to be confused with municipally-imposed amounts that have not been scrutinized for their prudence or reasonableness by the Board. In this way, the municipal council responsible for imposing additional fees and charges can also be held clearly accountable by municipal taxpayers for doing so. In the Board s view, customers would also benefit by an understanding of the basis of the separate line item. EUB Decision (August 13, 2004) 209

216 The Board notes, of course, that EDI is not responsible for preparing bills for end-use customers. That responsibility belongs to retailers according to section 112 of the EUA unless one of the exceptions mentioned in that section applies. Accordingly, the Board directs EDI, in its refiling, to propose wording, to appear on all bills prepared by retailers for customers in the EDI service area, to: 1. Identify the Fee as an additional amount imposed by the City as a surcharge or tax, in accordance with section 138(3) of the EUA; 2. Indicate clearly that the Fee is being imposed by the City and is not approved by the Board; and 3. Indicate how the Fee has been calculated for that customer. Once the Board has approved the wording, EDI is directed to communicate the Board s directions and the approved wording to all retailers serving customers in the EDI service area. The CCA also suggested that EDI s Board-approved rate schedules should disclose the franchise rate, but the Board has some difficulty with that suggestion. The Board notes that EDI s rate schedule currently reads as follows: Franchise Fee Applicable: All services interconnected to EPCOR s distribution system and located within the City of Edmonton. Rate: EPCOR DISTRIBUTION will apply the Franchise Fee that the City of Edmonton directs EPCOR DISTRIBUTION to collect. The Board agrees with EDI that the City s timeframe for determining the Fee and the Rate contemplated by Schedule A of the Agreement may not be the same as the Board s timeframe for finalizing EDI s tariff. In the Board s view, it would be impractical to incorporate in the EDI tariff reference to a rate over which the Board has no jurisdiction yet would require modification from time to time according to the City s administrative processes. Therefore, the Board does not consider it reasonable to incorporate the franchise rate in EDI s Board-approved rate schedules. However, in light of section 138 of the EUA, the Board directs EDI, in its refiling, to include the following note in all rate schedules that refer to the Fee: 1. Note: This Franchise Fee is imposed by the City of Edmonton and is not approved by the Alberta Energy and Utilities Board Level of Method of Collection of the Fee Given the Board s conclusion that it has no jurisdiction to review or approve the Fee under either the MGA or the EUA, it is unnecessary for the Board to address the arguments of interested parties respecting the level and method of collecting the Fee. 210 EUB Decision (August 13, 2004)

217 12 REFILING PROCESS The Board directs EDI to revise its forecast 2004 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 September 3, The refiling directions are summarized in the following section of this Decision for the convenience of all parties. The Board directs EDI, in its refiling, to forecast the difference between the revenue collected on interim rates and the revenue that would have been collected on final rates for the period January 1, 2004 to September 30, The Board directs EDI to file a method of collecting or refunding this difference from customers, on a rate class instead of individual customer basis. For reasons similar to those contained in previous sections of this Decision, concerning the Complexity of EDI's DAS and SAS rates, the Board is of the view that a rate class rider is a more practical and appropriate form to use. The Board further directs EDI, in its refiling, to file a summary of typical DT billings (broken down by DAS and SAS) to retailers comparing the existing 2004 DT rates with the 2004 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 EDI, in its refiling, to collaborate with EESI and file a summary of typical residential RRT and commercial RRT billings comparing the existing 2004 EESI RRT rates (including the existing 2004 interim EDI DT rates) with the 2004 EESI RRT rates (including the 2004 refiled EDI DT rates) using the Board s standard rate comparisons by low, average and high use customers in each rate class. The Board considers that it would be appropriate to provide for a short written process to ensure that EDI s refiling complies in all respects with the Board s directions. Accordingly, the Board sets down the following refiling schedule: Event Date EDI Refiling September 3, 2004 Comments from Interested Parties, if any September 10, 2004 Reply from EDI (including second refiling, if necessary, to correct any errors or omissions) September 17,2004 Board Final Distribution Tariff Decision September 24, 2004 EDI Implementation of Rates October 1, 2004 The Board emphasizes that comments from interested parties are restricted to comments that will assist the Board in determining if the EDI refiling complies in all respects to the Board s refiling directions. 13 SUMMARY OF BOARD DIRECTIONS RESPECTING THE REFILING 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. Considering all of the above, the Board is not persuaded that it should allow EDI to charge for catch-up expenses relating to maintenance that should have been performed in prior EUB Decision (August 13, 2004) 211

218 years. Accordingly, the Board directs EDI, in its refiling, to reduce its revenue requirement for the $200,000 of distribution operations catch-up type expenditures For similar reasons as for the other catch-up expenses dealt with earlier, the Board directs EDI, in its refiling, to reduce its revenue requirement for the $250,000 of metering O&M catch-up type expenditures According, the Board directs EDI, in its refiling, to reduce bad debt expense for 2004 by $92, Accordingly, the Board directs EDI, in its refiling, to reduce its labor costs by $776, Accordingly, the Board directs EDI, in its refiling, to reduce its forecast revenue requirement by the amount of $160,000, which is 50% of the Net Income component related to the At Risk compensation for management employees In addition, the Board directs EDI to provide, in its refiling, the forecast level of hourly and salaried FTEs for 2004, reflecting the Board s findings in this Decision The forecast of the timing of each year s provision to, and Board approved payments from, the HCR will still have a small working capital impact due to its effect on the mid-year HCR balance. The Board directs EDI, in its refiling, to provide a schedule indicating the forecast opening and closing HRC balances using the provision and forecast of costs to be paid out of the HRC. EDI should provide a schedule in the same form for subsequent GTAs. The forecast mid-year balance should be used in EDI s necessary working capital calculation Accordingly, the Board directs EDI in its refiling, to reduce operating expenses by $0.3 million and to include the approved provision of $2.0 million for the HCR Accordingly, the Board directs EDI, in its refiling, to remove the $273,312 total of sponsorships and charitable donations from its 2004 revenue requirement Accordingly, the Board directs EDI, in its refiling, to provide a copy of all filings with the MSA under the Code of Conduct Regulation to date in 2004 and to provide a copy of all future Code of Conduct filings with the MSA on a going forward basis Accordingly, the Board directs EDI, in its refiling, to establish a transmission access charge deferral account that records changes in transmission access costs due to changes in AESO rates only. The Board also directs EDI to implement a process to true up the deferral account on a quarterly basis and collect/refund the previous quarter s balances in this deferral account on a per kwh basis over the subsequent quarter The Board will therefore allow 50% of the forecast costs, or $2.9 million, to be included in the forecast 2004 capital additions in respect of the RDS project. Accordingly, the Board directs EDI, in its refiling, to remove $2.9 million from 2004 forecast capital additions Accordingly, the Board directs EDI, in its refiling, to reduce its forecast 2004 capital additions by $1.1 million for the MDM project Accordingly, the Board directs EDI to, in its refiling, use a vehicle replacement forecast of $2.9 million EUB Decision (August 13, 2004)

219 15. EDI agreed with CG that the errors in EDI s necessary working capital Schedule D-10 of EDI s Application should be corrected to reflect a decrease to working capital of $1.2 million. EDI indicated that it would reflect this correction in its refiling and the Board directs EDI, in its refiling, to do so The Board has examined EDI s lead/lag study and the other portions of its NWC calculation and accepts that the methodology is appropriate. The Board directs EDI, in its refiling, to recalculate its necessary working capital using the same methodology and lead/lag parameters to reflect the affects of the Board s findings in other sections of this Decision Accordingly, the Board directs EDI, in its refiling, to revise the proposed depreciation expense for Account to reflect EDI s proposed amortization periods of 6 years for minor assets and 10 years for major EDI investment in IS software Therefore, the Board directs EDI, in its refiling, to use a rate of return on common equity of 9.60% and a capital structure of 39% equity and 61% debt as determined in Decision Considering all of the above, the Board directs EDI, in its refiling, to use a debt cost of 7.55% as the rate for the 61.0% of EDI s rate base that was not deemed to be funded by equity per Decision Therefore, the Board directs EDI to allocate $930,000 of load centre costs to the intervalmetered rate classes as part of its refiling Therefore, the Board directs EDI, in its refiling, to use a 50/50 weighting of class NCP and on-peak energy to allocate primary distribution system costs. In Appendix 3, the Board has provided its approved allocators Therefore, the Board directs EDI, in its refiling, to design rates that achieve a 100% revenue to cost ratio for each rate class, while not exceeding an overall 10% combined DAS and SAS rate increase for any rate class The Board recognizes that it may be more difficult to achieve 100% revenue cost ratios by rate component given the revisions to the COSS. Therefore, the Board also directs EDI, in its refiling, to determine a rate structure that moves towards a 100% revenue to cost ratio for the customer, demand and energy cost components of each rate class. The Board directs EDI to use its judgment in determining which components can be moved to 100% in the refiling and which components should move towards 100% over a period of time in future GTAs The Board directs EDI to apply, no later than November 1, 2004, for simplified DAS rates to be effective on an interim basis January 1, The Board notes that standby service to UA was discontinued effective March 29, The Board agrees with UA that the rate charged to UA effective March 29, 2004 should be reduced to $243.88/day. The Board also notes that EDI agreed with UA that the revenue loss from the Rossdale and Meadowlark standby sites should be made up by all other rate classes, who are in fact using those facilities at present. The Board considers this approach to be reasonable for the purposes of this Decision. The Board also directs EDI, at the time of its refiling, to advise the Board of its plans discontinue the physical supply of standby to UA EUB Decision (August 13, 2004) 213

220 26. Therefore, the Board directs EDI, in its refiling, to leave the fee for the provision of historic customer information on the fee schedule, but to show the fee as zero at the present time The Board directs EDI, in its refiling, to identify the incremental costs, if any, included in its revenue requirement for the provision of historic customer information and to confirm the incremental cost per request that will be accrued in the deferral account. The Board notes EDI s evidence that the incremental cost per request was expected to be approximately $10 until the automated data extraction process is implemented Therefore, the Board directs EDI, at the time of its refiling, to file for information its Retailer Handbook and each of its Customer Guides. The Board also directs EDI to file for information any future revisions to its Retailer Handbook or Customer Guides The Board notes that EDI did not object to the requirement for Board approval of changes to EDI s DT policies. The Board agrees that changes to EDI s DT policies should be subject to Board approval. The Board directs EDI, in its refiling, to append each of its DT policies to its Terms and Conditions The Board notes that EDI did not object to the wording changes proposed by CG with respect to the definition of Customer in Section 2.1 of the DCS T&Cs, with respect to the addition of the word new in Section 8.3 of the DCS T&Cs, or with the addition of the phrase or omission in Section 11.1 of the DAS T&Cs and in Section 14.1 of the DCS T&Cs. The Board notes that some of these changes had already been incorporated by EDI during the course of the proceeding. In any event, the Board agrees with these proposed changes and directs EDI to incorporate these changes in its refiling With respect to Section 4.2 of the DCS T&Cs, the Board notes that EDI was not concerned about the legal age requirement for mass-market customers. The Board considers that there should be no legal age requirement for residential customers, and the Board directs EDI, in its refiling, to amend Section 4.2 to clarify that the legal age requirement does not apply to residential customers The Board notes that EDI did not object to amending Section 6.10 of the DAS T&Cs to clearly set out that EDI had the right to disconnect service in the event of unauthorized use. The Board considers that this would be a useful clarification and directs EDI to incorporate this clarification in its refiling With respect to the 180-day limitation in the second paragraph of Section 11.1 of the DAS T&Cs and the second paragraph of Section 14.1 of the DCS T&Cs, EDI has not persuaded the Board that the circumstances of EDI s DT warrant a departure from the general statutory limitation period of 2-years. The Board directs EDI, in its refiling, to delete the second paragraph of Section 11.1 of the DAS T&Cs and the second paragraph of Section 14.1 of the DCS T&Cs Therefore, the Board directs EDI to develop a SAS COSS, which demonstrates how all components of the AESO tariff will be allocated to EDI s rate classes and to include this SAS COSS in its November 1, 2004 application for simplified rates effective January 1, The Board directs EDI to apply, no later than November 1, 2004, for simplified SAS rates to be effective on an interim basis January 1, EUB Decision (August 13, 2004)

221 36. Accordingly, the Board directs EDI, in its refiling, to propose wording, to appear on all bills prepared by retailers for customers in the EDI service area, to: Identify the Fee as an additional amount imposed by the City as a surcharge or tax, in accordance with section 138(3) of the EUA; Indicate clearly that the Fee is being imposed by the City and is not approved by the Board; and Indicate how the Fee has been calculated for that customer Once the Board has approved the wording, EDI is directed to communicate the Board s directions and the approved wording to all retailers serving customers in the EDI service area However, in light of section 138 of the EUA, the Board directs EDI, in its refiling, to include the following note in all rate schedules that refer to the Fee: Note: This Franchise Fee is imposed by the City of Edmonton and is not approved by the Alberta Energy and Utilities Board The Board directs EDI to revise its forecast 2004 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 September 3, The refiling directions are summarized in the following section of this Decision for the convenience of all parties The Board directs EDI, in its refiling, to forecast the difference between the revenue collected on interim rates and the revenue that would have been collected on final rates for the period January 1, 2004 to September 30, The Board directs EDI to file a method of collecting or refunding this difference from customers, on a rate class instead of individual customer basis. For reasons similar to those contained in previous sections of this Decision, concerning the Complexity of EDI's DAS and SAS rates, the Board is of the view that a rate class rider is a more practical and appropriate form to use The Board further directs EDI, in its refiling, to file a summary of typical DT billings (broken down by DAS and SAS) to retailers comparing the existing 2004 DT rates with the 2004 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 EDI, in its refiling, to collaborate with EESI and file a summary of typical residential RRT and commercial RRT billings comparing the existing 2004 EESI RRT rates (including the existing 2004 interim EDI DT rates) with the 2004 EESI RRT rates (including the 2004 refiled EDI DT rates) using the Board s standard rate comparisons by low, average and high use customers in each rate class EUB Decision (August 13, 2004) 215

222 14 SUMMARY OF BOARD DIRECTIONS REPECTING THE NEXT GTA 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 has reviewed the method used by EDI to determine the forecast energy use per residential customer and considers the approach to be reasonable for the purposes of this Decision. The Board recognizes that EDI s adjustment for price and energy conservation is an exercise in judgment into which many factors enter. The Board will accept EDI s forecast based on that judgmental adjustment for the purposes of this Decision. However, the Board directs EDI to monitor energy use per residential customer and report on its forecast track record in this regard at the time of EDI s next GTA The Board also notes that in other sections of this Decision the value of benchmarking is discussed. For comparability purposes, the Board directs EDI in the next GTA, to file its general inflation factors by the following categories: salaries and wages, materials, contractors and other To provide better support for future compensation increase forecasts, the Board directs EDI, in its next GTA, to provide an independent testable market-based assessment of the reasonableness of its compensation levels for its management, professional, CUPE, and IBEW employees. The assessment should consider each of the Exempt levels (i.e. Executive, Director, Manager, Supervisor, Non-Management, Corporate Allocated) as well as the two types of Non-Exempt (i.e. CUPE, IBEW). In addition to salaries and wages, the overall compensation packages including pension and other benefits should be assessed for each category Accordingly, the Board directs EDI, in its next GTA, to include a comprehensive explanation, including calculations, of the derivation of the number of FTEs and cost per FTE for each of the functions of EDI s DT service Accordingly, the Board directs EDI to provide a reconciliation clearly showing the amounts forecast to be paid out in 2004 and the actual amounts paid out in 2004, as part of its next GTA, by level of employee and including details of how the incentive compensation was calculated Accordingly, the Board directs EDI to commence tracking vacancy rates, commencing in the 2004 test year, for use in future GTAs Therefore, the Board directs EDI, at the time of its next GTA, to provide the estimated cost of preparing an executive compensation study, similar to that to be filed by ATCO in its next GTA The Board directs EDI, in its next GTA, to include the forecast for EUB Assessment as part of the HCR The Board also directs EDI, at its next GTA, to separately forecast its expected claims and expected recoveries from the hearing cost reserve accounts of other utilities and include as a separate line item in its revenue requirement EUB Decision (August 13, 2004)

223 10. Further, while there is no evidence that there are donations and community support costs included in the direct EDI costs (as opposed to corporate pass-down costs from EUI), the Board directs, in its next GTA, to separate out and exclude direct donations and community support costs The Board directs EDI to implement a better system of recording time spent on affiliate transactions using time sheets or more frequent time estimates and report on the progress in its next GTA Accordingly the Board directs EDI to initiate and collaborate with EPC to work on approaches that would allow reasonable and appropriate benchmarking studies and to include a high level benchmarking study with the types of benchmarking data included in Exhibit at the time of the next GTA Accordingly, the Board directs EDI, in its next GTA, to demonstrate that it has established procedures, which include a requirement for senior management approval, to ensure the following criteria are followed prior to making a claim against the self-insurance reserve:.. 90 the claim must exceed a materiality threshold of $100,000 (costs of such items as emergency repairs and replacements less than this value are to be considered as normal operating costs); the claim must arise from or relate to an event that is sudden and accidental; the claim will represent the deductible payable if the claim is otherwise insured or the full amount if insurance is either unavailable or EDI elects to self-insure because insurance premiums are prohibitively expensive; the claim is outside management s control and could not reasonably have been foreseen or prevented; the claim is not one for which EDI is compensated through its return on equity; and.. 90 the claim arises from or relates to an event that is low probability and has a high dollar impact (i.e., exceeding $100,000) Further, the Board directs EDI, in its next GTA, to demonstrate that any claims against the self-insurance reserve are removed from the bases used to forecast maintenance and repair expenses so that there is no possibility of double compensation to EDI The Board directs EDI, in the next GTA, to file its 2005 opening balance for gross plant, calculated by starting from its 2004 gross plant level and then adding its actual 2004 capital additions. Similarly, the Board directs EDI, in its next GTA, to file its 2005 opening balance for accumulated depreciation, calculated by starting from its 2004 opening accumulated depreciation balance and adding the actual Board approved 2004 depreciation As to the future evolution of EDI s capitalization policy, the Board directs EDI to consider the determinations that the Board has made in this Decision and the capitalization policies of other Alberta utilities in the policy it recommends in its next GTA Nevertheless, the Board agrees with CG and AE that to ensure a full record, consistent with that required for other utilities, EDI should in its next GTA provide certain material for all capital expenditures in excess of $500,000. Accordingly, the Board directs EDI, in its next GTA, to provide appropriate business cases for capital expenditures in excess of $500,000 clearly showing: The reasons/need for the proposed expenditure; EUB Decision (August 13, 2004) 217

224 The alternatives examined; The incremental capital and operating costs associated with each alternative examined for a minimum 10 year period; The discount or investment rate used to compare alternatives and the basis for its use; 105 The annual costs of each alternative for the period analyzed; The rationale for choosing a specific alternative, including any qualitative considerations used in choosing the alternative; and The date of preparation and the date of approval The Board noted earlier that the prudence of actual 2004 additions will be tested at the time of the next GTA. The Board directs EDI to file, at the time of its next GTA, a comprehensive business case justifying actual 2004 costs for the RDS project, for the purposes of establishing the opening 2005 rate base Accordingly, the Board directs EDI to undertake a review of the contribution policies and practices of other distribution utilities in Alberta with a goal of developing terms consistent with industry practices, and to file the review and EDI s policy as part of its next GTA The Board directs EDI, at the time of its next GTA, to propose a simplified method of determining its depreciation expense considering the views expressed by the Board in this Decision. The Board expects EDI s proposal to consider whether the basic form (or other basic forms) would be appropriate in EDI s circumstances. Further, the Board expects that EDI will only add those complexities to its proposal that EDI considers would be cost efficient and appropriate considering the data and circumstances of the EDI system Accordingly, the Board directs EDI, in its next GTA, to provide evidence respecting EUI s actual cost rate of issuing the 2004 debt including an appropriate allocation of any out of pocket issue expenses passed down to EDI from EUI Further, the Board agrees with the CG that for future tariff applications, EDI should examine an appropriate method to allow EUI to mirror down actual, specific future debt issues made on behalf of EDI. The Board expects that using this approach, EUI can take advantage of economies of scale and make larger debt issues, which can then be allocated to EDI and other EUI subsidiaries. Accordingly, the Board directs EDI, in its next GTA, to examine an appropriate method to allow EUI to mirror down actual, specific future debt issues made on behalf of EDI The Board also directs EDI to review the weighting factors used for billing costs in its next GTA Therefore, the Board directs EDI to implement the CAR in its next GTA The Board considers that the issue of the appropriate allocator for the primary distribution system costs should be further addressed at EDI s next GTA. Therefore, the Board directs EDI, in its next GTA, to further examine this issue, including an assessment of the use of both NCP and CP allocators. The Board also directs EDI to examine the use of a narrower definition of on-peak hours for the purposes of allocating primary distribution system costs, such as the critical hours within 5 or 10% of the system CP EUB Decision (August 13, 2004)

225 26. The Board directs EDI, at the time of the next GTA, to provide the following data for each rate class to assist in the evaluation of an appropriate allocator for primary distribution costs: Forecast load for every hour of the year Forecast NCP Forecast CP Forecast on-peak energy Forecast off-peak energy The Board considers that there may be merit in undertaking both a minimum system study and a zero intercept study for the primary distribution system as a future refinement to the COSS. To assist the Board in making an assessment as to whether such a refinement would be beneficial, the Board directs EDI, at its next GTA, to identify the costs and the pros/cons of undertaking both a minimum system study and a zero intercept study for the primary distribution system Therefore, the Board directs EDI to examine the cost allocation and rate design of Apartment Rates in its next GTA and make a proposal whether a separate rate design should be applicable to Apartments The Board also directs EDI, in its next GTA, to include an analysis of the revenue by component (energy, demand, and fixed charge) compared to the cost by component, for both its existing and applied for DAS and SAS rates In an earlier section of this Decision, the Board directed EDI to further examine, at its next GTA, the appropriate allocator for primary distribution system costs. The Board directs that EDI s refiled rate structures reflecting the 50% NCP/50% On-peak energy cost allocation should be revisited at the next GTA and made consistent with the results of the further examination of the appropriate allocator for the primary distribution system costs Therefore, the Board directs EDI to perform a comprehensive COSS for the next GTA, including all of EDI s customers For the purposes of this Decision, the Board will approve the use of individual customer rates for these large customers. However, the Board directs EDI to assess the appropriateness of continuing the use of individual rates in EDI s next GTA, with the benefit of the data from the comprehensive COSS The Board also directs EDI, at the time of its next GTA, to identify the number of requests for the provision of historic information, by retailer With respect to Section 10.2 of the DAS T&Cs regarding liability, the Board notes that EDI s proposed clause is the same as the Board has previously approved for AE. The Board is not persuaded that a change to Section 10.2 of the DAS T&Cs is required at this time, but the Board directs EDI to address the concerns raised by CG with respect to liability for meter reading at the time of EDI s next GTA application EUB Decision (August 13, 2004) 219

226 Dated in Calgary, Alberta on August 13, ALBERTA ENERGY AND UTILITIES BOARD (original signed by) N.W. MacDonald, P.Eng Presiding Member (original signed by) R. G. Lock, P. Eng. Member (original signed by) J. I. Douglas, FCA Member 220 EUB Decision (August 13, 2004)

227 APPENDIX 1 HEARING PARTICIPANTS Principals and Representatives (Abbreviations Used in Report) Witnesses ENMAX Power Corporation (EPC) and ENMAX Energy Corporation (EEC) L. A. Cusano D. M. Wood EEC EPC Ed Overcast Stuart Berry James Joyce Bob Cummings Brad Thompson Allan Buchignani Gordon Edwards Scott Stoness Shelley Radway Kevin Phillips Brad Thompson Allan Buchignani Larry Kennedy Roy Nesbitt Jack Li Wes Kadonaga Harold Johansen Scott Stoness EPCOR Energy Services Inc. (EESI), EPCOR Energy Services (Alberta) Inc. (EESAI) and (EDI) J. M. Liteplo D. E. Crowther Kellie Johnston EESI/EESAI Bryan DeNeve Brian Gerdes David Asquin Jay Baraniecki John Dunnett EDI Rick Cowburn Bryan DeNeve John Bryon Ken Rowes Ken Grimes Vern Mentai Thomas Peterson Dale Urban John Spanos Pat Wong ATCO Electric Limited (AE) L. G. Keough Kristen Lozynski Calgary Industrial Group and Calgary Building Owners Coalition (CIG/CBOC) L. L. Manning Consumers Coalition of Alberta (CCA) J. A. Wachowich Azad Merani EUB Decision (August 13, 2004) 221

228 Principals and Representatives (Abbreviations Used in Report) Witnesses Direct Energy Preferred (DEP) K. F. Miller Industrial Power Consumers Association of Alberta (IPCAA) M. S. Forster Dan B. Macnamara Public Institutional Consumers of Alberta (PICA) Nancy J. McKenzie Raj Retnanandan The City of Calgary D. I. Evanchuk The Cities of Lethbridge, Red Deer, and University of Alberta Phyllis A. Smith Aquila Networks Canada (Alberta) Ltd. (ANCA) T. Dalgleish Utilities Consumer Advocate (UCA) C. R. McCreary Board Panel N. W. MacDonald, P. Eng. R. G. Lock, P. Eng. J. I. Douglas, FCA Board Counsel Allan Domes Board Staff Brian Ploof Derrick Ploof Wayne Taylor Robert Litt Shawn Allen Kim VanKosh 222 EUB Decision (August 13, 2004)

229 APPENDIX 2 EXAMPLE OF A BASIC FORM OF SIMPLIFIED DEPRECIATION METHOD In the case of existing plant units within the account, the gross investment and the fixed period would be reduced by the factor of net plant divided by gross plant to recognize the accumulated depreciation already paid by customers. 302 In the case of new plant units being added each year the fixed period would be aligned with current service life expectations of the facilities in the account. However, no depreciation would be taken on the facilities during the year in which they were installed. Depreciation would commence in the year after the facilities were installed to reflect the amount to be amortized in the current year. This approach would eliminate the need for a depreciation rate for each account. When property units are retired, the gross plant account balance would be reduced by the actual retirement unit cost and the accumulated depreciation reserve would be charged with the actual retirement unit cost at the time of retirement thereby ensuring that no more than the original cost of the property unit is recovered. A basic simplified method assumes that the actual retirement unit is fully depreciated at the time of retirement thereby eliminating any need for depreciation adjustments to account for differences between the theoretical reserve and the actual reserve. The spreadsheet below illustrates the characteristics of a basic simplified depreciation system applied to existing property units. The spreadsheet below also illustrates how this basic simplified method can be used when moving from 2004 depreciation calculations to 2005 depreciation calculations. EDI Basic Depreciation Example (Consists of 3 pages) 302 Assume the property units in an account were to be allocated over a fixed 10 year period. A new property unit added to the account with a gross investment of $100 would be amortized over a fixed 10 year period at $10 per year. However, an existing property unit with a gross investment of $100 already has been depreciated to some extent. If the ratio of net plant to gross plant were 0.7 for the account, the deemed accumulated depreciation for a $100 property unit would be $30 and the net plant would be $70. Applying the net plant to gross plant factor of 0.7 to both the $100 gross investment and the 10 year fixed amortization period would result in a remaining net plant amortization of $10 per year for 7 years for an amount of $70. EUB Decision (August 13, 2004) 223

230

231 APPENDIX 3 BOARD PRIMARY SYSTEM ALLOCATION ANALYSIS "EDI Primary Distribution Allocation (Consists of 10 pages) EUB Decision (August 13, 2004) 225

232 Basic Simplified Amortized Method Appendix 2 Asset Account Account Description Account Gross Amortization Period Net Plant to Gross Plant Factor Account Remaining Amortization Period Net Book Value 2005 Simplified Amortization EDI Wires Aerial Customer Services ,516, , Aerial Distribution System ,134,325 1,748, Underground Ducts and Vaults ,892, , Power Cables ,144,383 1,265, URD Distribution (Terminal Account) ,527, , URD Distribution System ,089,910 1,699, Pole Mounted Transformers ,461, , Underground Transformers ,590,469 1,436, Meters ,343,199 1,230, Interval Meters ,947, , Aerial Capital Rebuilds ,672, , UID System ,001, , Underground Services ,459, , Network Distribution System ,963,763,,, 291,242, EDI Substation Substation Building ,092 8, Substation Switchgear ,278,467 40, Substation Regulators Fully Amortized -2,706 (2,706) Substation Transformers ,966 17, Substation Communications ,140 67, Substation Meters ,977 2, Substation Protection Control ,883 13, Substation SCADA , 186,450, 25,860, EDI Miscellaneous ROW and Easements ,741 3, Service Center Building ,662, , Un-metered Services ,075 88, Security Lighting ,389, , EDI/ETI Instruments , , EDI/ETI Tools ,107 99, EDI Tools ,533 26, EDI Instruments , 340,165,, 37,877, EDI Supporting Assets I/S MeterDataManagement/Settlement/Other Reg Compliance ,629,723 1,204, I/S Worksations/Y2K/Other ,367,148 1,441, Tariff Analysis System , , AIMMS ,988, , WISE ,522,086 1,126, Furniture , , Leasehold Improvements ,317 2, Work Management System ,512, ,457 26,238,446 4,783, Composite Expense Per Simplified Method 18,168,064 Jan 1, 2005 Net Plant 348,343,265 Jan 1, 2005 Gross Plant 527,272, Composite Rate Per Simplified Method 3.45% EUB Decision (August 13, 2004) Page 1 of 3

233 Basic Simplified Amortized Method Appendix 2 Asset Account Account Gross Net Plant to Gross Plant Account Remaining Amortization 2005 Simplified 2004 per EDI Corrected Account Description Amortization Period Factor Period Net Book Value Amortization for I/S Amortization EDI Wires Aerial Customer Services ,307, , , Aerial Distribution System ,327,678 1,657,696 1,597, Underground Ducts and Vaults ,430, , , Power Cables ,692,486 1,271,676 1,137, URD Distribution (Terminal Account) ,195, , , URD Distribution System ,217,961 1,536,800 1,565, Pole Mounted Transformers ,311, , , Underground Transformers ,929,073 1,345,101 1,302, Meters ,648,578 1,192,115 1,088, Interval Meters ,802, , , Aerial Capital Rebuilds ,897, , , UID System ,908, , , Underground Services ,799, , , Network Distribution System ,351,317,,, 270,830,, 262,554, EDI Substation Substation Building ,788 5,585 6, Substation Switchgear ,315,352 41,164 36, Substation Regulators Fully Amortized -3,043 (3,043) (338) Substation Transformers ,703 17,944 16, Substation Communications ,817 69,026 60, Substation Meters ,113 2,294 2, Substation Protection Control ,348 13,193 12, Substation SCADA , 207,573, 27,167, 21,123, EDI Miscellaneous ROW and Easements ,117 3,464 3, Service Center Building ,608, , , Un-metered Services ,365 83,096 76, Security Lighting ,540, , , EDI/ETI Instruments , , , EDI/ETI Tools , ,233 90, EDI Tools ,498 13,299 19, EDI Instruments , 176,255,, 18,677,, 28,089, EDI Supporting Assets I/S MeterDataManagement/Settlement/Other Reg Compliance ,582, , , I/S Worksations/Y2K/Other ,425,696 1,322,087 1,381, Tariff Analysis System , , , AIMMS ,252, , , WISE ,648,295 1,126,209 1,126, Furniture ,620 92,239 97, Leasehold Improvements ,899 2,582 2, Work Management System ,600, , ,857 22,016,945 3,825,012 4,304, Composite Expense Per Simplified Method 16,645,347 16,447,247 (Corrected for I/S) 2004 Composite Expense Per EDI (Corrected for I/S) 16,447,247 Jan 1, 2004 Net Plant 329,163,961 Jan 1, 2004 Gross Plant 497,173, Composite Rate Per Simplified Method 3.35% Per EDI 2004 Corrected 3.31% EUB Decision (August 13, 2004) Page 2 of 3

234 2004 Depreciation Expense Per Board Appendix Dec 31,2004 Asset Opening Asset Asset Asset Year end Depreciation Opening Reserve Redistributed 2004 Reserve Closing Net Book Account Balance Additions Transfers Retirements Balance Rate Reserve Redistribution Opening Reserve Depreciation Transfers Reserve Value EDI Wires Aerial Customer Services 22,211,953 1,755,000 - (216,638) 23,750, % 5,942,577 (38,232) 5,904, ,256-6,233,963 17,516, Aerial Distribution System 66,307,823 4,404,000 - (776,382) 69,935, % 20,868, ,197 20,980,145 1,597,353-21,801,116 48,134,325 Underground Ducts and Vaults 34,644,481 1,124,000 - (292,538) 35,475, % 16,368,578 (154,804) 16,213, ,633-16,583,869 18,892, Power Cables 48,323, ,000 - (805,459) 48,107, % 21,818,190 (186,990) 21,631,200 1,137,102-21,962,843 26,144, Underground Res Dist 29,614, (585,795) 29,028, % 15,555,625 (136,283) 15,419, ,906-15,501,453 13,527, Underground Res Dist System 58,398,418 6,437,000 - (263,943) 64,571, % 11,113,909 66,548 11,180,457 1,565,051-12,481,566 52,089, Pole Mounted Transformers 15,590, ,000 - (359,697) 15,789, % 6,034, ,841 6,279, ,878-6,328,312 9,461, Padmount, Vault & Sub Trans 47,078,533 3,964,000 - (754,387) 50,288, % 15,019, ,014 15,149,460 1,302,604-15,697,676 34,590, Meters 29,802,877 1,783,000 - (823,447) 30,762, % 13,118,142 36,157 13,154,299 1,088,379-13,419,230 17,343, Interval Meters 3,688, ,000-7,857 3,988, % 949,783 (63,047) 886, ,905-1,041,498 2,947, Aerial Capital Rebuilds 12,825,014 88,000 - (79,340) 12,833, % 1,913,486 14,252 1,927, ,823-2,161,221 10,672, Underground Ind Dist System 11,190, ,000 - (93,095) 11,471, % 3,295,474 (13,880) 3,281, ,485-3,469,984 8,001, Underground Services 34,286,712 2,507,000 - (156,949) 36,636, % 8,475,391 12,236 8,487, ,723-9,177,401 27,459, Network Dist System 9,479, ,000 - (160,578) 10,193, % 3,149,745 (22,010) 3,127, ,554-3,229,710 6,963,763 Total EDI Wires 423,442,743 24,751,000 - (5,360,393) 442,833, ,623, ,623,582 10,826, ,089, ,743,506 EDI Substation Substation Building 279, ,000 - (1,899) 432, % 53, ,480 6,696-58, , Substation Switchgear 1,852, (26,008) 1,826, % 551,068 (14,044) 537,024 36, ,902 1,278, Substation Regulators 43, (4,605) 38, % 48,503 (2,000) 46,502 (338) - 41,560 (2,706) Substation Transformers 717, (8,228) 709, % 143,313 (269) 143,044 16, , , Substation Communications 1,035, (16,160) 1,019, % 325,897 12, ,571 60, , , Substation Meters 91, (258) 91, % 19, ,648 2,137-21,527 69, Substation Prot Control 527, (1,443) 526, % 91,390 1,981 93,370 12, , , Substation SCADA 407, (19,612) 387, % 198, ,938 21, , ,450 Total EDI Substation 4,955, ,000 - (78,212) 5,032,018 1,431,578 (0) 1,431, ,383-1,509,749 3,522,269 EDI Miscellaneous ROW and Easements 173, (206) 172, % 32,111 (43) 32,067 3,376-35, , Service Center Building 27,018,085 1,646,000 - (154,782) 28,509, % 7,467,668 (58,116) 7,409, ,887-7,846,657 20,662, Un-metered Services 1,495, ,000 - (94,673) 1,584, % 765,467 11, ,357 76, , , Security Lighting 4,102,826 38,000 - (191,035) 3,949, % 2,523,387 39,404 2,562, ,503-2,560,259 1,389, EDI / ETI Instruments 1,846, (156,337) 1,690, % 845,577 6, , , , , EDI / ETI Tools 1,042, (49,747) 992, % 544,150 (1,629) 542,521 90, , , Tools 132, , , % 6, ,489 19,965-27, , Instruments 186, , , % 9,339 1,180 10,518 28,089-38, ,165 Total EDI Miscellaneous 35,998,553 2,195,000 - (646,780) 37,546,773 12,194,348 (0) 12,194,348 1,160,161-12,707,729 24,839,044 EDI Supporting Assets Information Systems 11,964,995 2,965,000 5,880,379 (113,705) 20,696, % 5,513,964 (557,123) 4,956,841 2,721,805-7,564,942 13,131, A Information Systems (Major) 4,032,473 2,200,000 5,880,379 (66,183) 12,046, % 1,612,989 (162,974) 1,450, ,957 2,416,946 9,629, B Information Systems (Minor) 7,932, ,000 (47,522) 8,650, % 3,900,975 (394,149) 3,506,826 1,381,877 5,282,852 3,367, Tariff Analysis System 2,684,134 2,684, % 697,875 1,008,272 1,706, ,413-1,974, , AIMMS 2,639,768 2,639, % 416,427 (29,209) 387, , ,195 1,988, WISE 11,262, (0) 11,262, % 2,912,611 (298,812) 2,613,799 1,126,209-3,740,008 7,522, Furniture 737,912 79, , % 265,621 (34,329) 231,292 97, , , Leasehold Improvements 25, , % 4,623 (1,698) 2,925 2,582-5,507 20, Work Management System 3,462, , ,734, % 949,232 (87,101) 862, ,857-1,221,988 2,512,582 Total EDI Supporting Assets 32,777,297 3,316,000 5,880,379 (113,705) 41,859,971 10,760,352-10,760,352 4,840,021-15,486,668 26,373,302 22,016,945 Grand Total 497,173,823 30,417,000 5,880,379 (6,199,090) 527,272, ,009,861 (0) 168,009,861 16,983, ,793, ,478,121 EUB Decision (August 13, 2004) Page 3 of 3

235 Appendix 3 Board Primary System Allocation Analysis using 2002 and 2004 data from EDI Application Schedule DAS 11 (Revised) and Appendix D Allocation Method (2002 Data) Residential <50 kv.a kv.a kv.a kv.a Pr Street Lights Traffic Lights Lane Lights Security Lights TOTAL Class NCP 335, ,217 95, , ,900 16,100 1,000 1,900 2,300 1,008,517 Average 3250 On-peak Hours 214,968 93,032 70, ,055 82,282 1, ,369 Six Top Monthly Hours 279, ,431 81, ,456 91,914 7, ,571 Allocation Factors (2002 Data) Residential <50 kv.a kv.a kv.a kv.a Pr Street Lights Traffic Lights Lane Lights Security Lights TOTAL Class NCP 33.3% 13.1% 9.4% 31.6% 10.5% 1.6% 0.1% 0.2% 0.2% 100.0% Average 3250 On-peak Hours 30.4% 13.2% 10.0% 34.3% 11.6% 0.3% 0.1% 0.0% 0.0% 100.0% 50% NCP / 50% On-peak Hours 31.8% 13.1% 9.7% 32.9% 11.1% 0.9% 0.1% 0.1% 0.1% 100.0% Six Top Monthly Hours 33.0% 12.7% 9.7% 32.6% 10.9% 0.9% 0.1% 0.0% 0.0% 100.0% Allocation Method (2004 Forecast) Class NCP 332, ,804 97, , ,200 15,500 1,000 1,400 1,800 1,013,204 Average 3250 On-peak Hours 224,875 94,269 72, ,343 83,043 1, ,492 Allocation Factors (2004 Forecast) Class NCP 32.8% 13.0% 9.6% 32.3% 10.3% 1.5% 0.1% 0.1% 0.2% 100.0% Average 3250 On-peak Hours 30.7% 12.9% 10.0% 34.7% 11.3% 0.3% 0.1% 0.0% 0.0% 100.0% 50% NCP / 50% On-peak Hours 31.8% 12.9% 9.8% 33.5% 10.8% 0.9% 0.1% 0.1% 0.1% 100.0% Notes: 1 The Board notes that the six top monthly hours occur in the winter months of Jan Nov &Dec and the summer months of Jun July and August and the lowest hourly demand in this representative sample is within 7% of the yearly peak system demand. In the absence of hour by hour loads by rate class the Board considers these six monthly hours to fairly represent the critical coincident peaks which could potentially influence primary system sizing requirements 2 The Board has allocated the six top monthly hours for 2002 into Residential, <50kV.A and kV.A based upon Class NCP. The Board notes that these rate classes in aggregate account for 55.4% of the eligible top monthly hours (Tables excludes Direct Connect and >5000 kv.a) whereas the Board recommended allocation results in an aggregate share of 54.7%. EUB Decision (Auggust 13, 2004) Page 1 of 10

236 Appendix 3 From Appendix D of EDI filing and DAS-11(revised) of EDI DT filing Direct Connect On-pk % On-pk hours NCP/CP NCP/CP Energy (kw.h) 482,206, ,561,000 Ave hour On-peak Energy (kw.h) 51,378 52, % 3250 CP (kw) 60, , NCP (kw) 70, ,700.0 > 5000 Primary kv.a (Cust Specific) Energy (kw.h) 854,279, ,626,000 Ave hour On-peak Energy (kw.h) 110, , % 3250 CP (kw) 145, , NCP (kw) 154, , to 4999 kv.a (TOU Primary) Energy (kw.h) 599,251, ,794,000 Ave hour On-peak Energy (kw.h) 82,282 83, % 3250 CP (kw) 105, , NCP (kw) 105, , to 4999 kv.a (TOU) Energy (kw.h) 1,691,215,000 1,777,068,000 Ave hour On-peak Energy (kw.h) 242, , % 3250 CP (kw) 313, , NCP (kw) 318, ,500.0 Streetlights Energy (kw.h) 56,952,000 58,335,000 Ave hour On-peak Energy (kw.h) 1,850 1, % 3250 CP (kw) NCP (kw) 16, ,500.0 EUB Decision (August 13, 2004) Page 2 of 10

237 Appendix 3 Traffic Lights Energy (kw.h) 8,591,000 6,829,000 Ave hour On-peak Energy (kw.h) % 3250 CP (kw) 1, NCP (kw) 1, ,000.0 Security Lights Energy (kw.h) 6,828,000 6,566,000 Ave hour On-peak Energy (kw.h) % 3250 CP (kw) NCP (kw) 2, ,800.0 Lane Lights Energy (kw.h) 5,334,000 5,285,000 Ave hour On-peak Energy (kw.h) % 3250 CP (kw) NCP (kw) 1, ,400.0 Small Commercial Unmetered Energy (kw.h) 3,441,000 3,348,000 Ave hour On-peak Energy (kw.h) % 3250 CP (kw) NCP (kw) to 149 kv.a (Medium Commercial) Energy (kw.h) 528,213, ,831,000 Ave hour On-peak Energy (kw.h) 70,823 72, % 3250 CP (kw) 89, , NCP (kw) 95, ,400.0 EUB Decision (August 13, 2004) Page 3 of 10

238 Appendix 3 <50 kv.a (Small Commercial) Energy (kw.h) 701,070, ,528,000 Ave hour On-peak Energy (kw.h) 92,578 93, % 3250 CP (kw) 118, , NCP (kw) 131, ,400.0 Residential Energy (kw.h) 1,576,357,000 1,649,003,000 Ave hour On-peak Energy (kw.h) 214, , % 3250 CP (kw) 232, , NCP (kw) 335, ,600.0 EDI Total Energy (kw.h) 6,513,737,000 6,682,774,000 Ave hour On-peak Energy (kw.h) 2,823,936,635 2,897,220, % 3250 CP (kw) 1,066, ,059, NCP (kw) 1,233, ,232,204.0 EUB Decision (August 13, 2004) Page 4 of 10

239 From Appendix D of EDI filing Appendix Direct Connects to T.A. Energy (MWh) 477, , , ,561 Growth % Y/Y n.a Customers Growth % Y/Y n.a Coincident Peak (MW) Growth % Y/Y n.a Non-Concident Peak by Rate (MW) Growth % Y/Y n.a Non-Concident Peak by Site (MW) Growth % Y/Y n.a > 5000 kva Primary (Customer Specific) Energy (MWh) 858, , , ,626 Growth % Y/Y n.a Temperature Adjusted Energy (MWh) 858, , , ,626 Growth % Y/Y n.a Customers Growth % Y/Y n.a Coincident Peak (MW) Growth % Y/Y n.a Non-Concident Peak by Rate (MW) Growth % Y/Y n.a Non-Concident Peak by Site (MW) Growth % Y/Y n.a to 4999 kva Primary (TOU Primary) Energy (MWh) 600, , , ,794 Growth % Y/Y n.a Temperature Adjusted Energy (MWh) 600, , , ,794 Growth % Y/Y n.a Customers Growth % Y/Y n.a Coincident Peak (MW) Growth % Y/Y n.a Non-Concident Peak by Rate (MW) Growth % Y/Y n.a Non-Concident Peak by Site (MW) Growth % Y/Y n.a to 4999 kva (TOU) Energy (MWh) 1,669,220 1,691,215 1,738,921 1,777,068 Growth % Y/Y n.a Temperature Adjusted Energy (MWh) 1,670,644 1,687,827 1,733,824 1,777,068 Growth % Y/Y n.a Customers ,349 1,400 1,434 Growth % Y/Y n.a Coincident Peak (MW) Growth % Y/Y n.a Non-Concident Peak by Rate (MW) Growth % Y/Y n.a Non-Concident Peak by Site (MW) Growth % Y/Y n.a EUB Decision (August 13, 2004) Page 5 of 10

240 Appendix Street Lights Energy (MWh) 57,754 56,952 57,850 58,335 Growth % Y/Y n.a Coincident Peak (MW) Non-Concident Peak by Rate (MW) Growth % Y/Y n.a Non-Concident Peak by Site (MW) Growth % Y/Y n.a Traffic Lights Energy (MWh) 8,976 8,591 8,474 6,829 Growth % Y/Y n.a Coincident Peak (MW) Growth % Y/Y n.a Non-Concident Peak by Rate (MW) Growth % Y/Y n.a Non-Concident Peak by Site (MW) Growth % Y/Y n.a Security Lights Energy (MWh) 6,921 6,828 6,635 6,566 Growth % Y/Y n.a Customers 2,309 2,282 2,266 2,235 Growth % Y/Y n.a Coincident Peak (MW) Non-Concident Peak by Rate (MW) Growth % Y/Y n.a Non-Concident Peak by Site (MW) Growth % Y/Y n.a Lane Lights Energy (MWh) 5,556 5,334 5,268 5,285 Growth % Y/Y n.a Coincident Peak (MW) Non-Concident Peak by Rate (MW) Growth % Y/Y n.a Non-Concident Peak by Site (MW) Growth % Y/Y n.a Small Commercial Unmetered Energy (MWh) 3,487 3,441 3,352 3,348 Growth % Y/Y n.a Customers 1,165 1,163 1,125 1,123 Growth % Y/Y n.a Coincident Peak (MW) Growth % Y/Y n.a Non-Concident Peak by Rate (MW) Growth % Y/Y n.a Non-Concident Peak by Site (MW) Growth % Y/Y n.a EUB Decision (August 13, 2004) Page 6 of 10

241 Appendix to 149 kva (Meduim Commerical) Energy (MWh) 509, , , ,831 Growth % Y/Y n.a Temperature Adjusted Energy (MWh) 510, , , ,831 Growth % Y/Y n.a Customers 2,077 2,157 2,240 2,293 Growth % Y/Y n.a Coincident Peak (MW) Growth % Y/Y n.a Non-Concident Peak by Rate (MW) Growth % Y/Y n.a Non-Concident Peak by Site (MW) Growth % Y/Y n.a < 50kVA (Small Commerical) Energy (MWh) 685, , , ,528 Growth % Y/Y n.a Temperature Adjusted Energy (MWh) 688, , , ,528 Growth % Y/Y n.a Customers 24,290 24,465 24,778 25,245 Growth % Y/Y n.a Coincident Peak (MW) Growth % Y/Y n.a Non-Concident Peak by Rate (MW) Growth % Y/Y n.a Non-Concident Peak by Site (MW) Growth % Y/Y n.a Residential Energy (MWh) 1,501,294 1,576,357 1,624,209 1,649,003 Growth % Y/Y n.a Temperature Adjusted Energy (MWh) 1,517,892 1,555,269 1,610,401 1,649,003 Growth % Y/Y n.a Customers 245, , , ,327 Growth % Y/Y n.a Coincident Peak (MW) Growth % Y/Y n.a Non-Concident Peak by Rate (MW) Growth % Y/Y n.a Non-Concident Peak by Site (MW) Growth % Y/Y n.a EUB Decision (August 13, 2004) Page 7 of 10

242 Appendix 3 upings Total Annual MWh in group Substation Coincident MW Non-coincident total Metered MVA Class Non- Coincident Metered MW Peak by site Sum of Annual Metered Peaks MW Total On-peak MWh On-peak % Residential 1,649, , , , % < 50kVA 713, , , % 50 to 149 kva 543, , , % 150 to 499 kva 873, , , % 500 to 999 kva 622, , , % 1000 to 1499 kva 204, , % 1500 to 2499 kva 39, , % 2500 to 4999 kva 38, , % 150 to 499 kva 27, , % 500 to 999 kva 73, , % 1000 to 1499 kva 56, , % 1500 to 2499 kva 111, , % 2500 to 4999 kva 336, , % 5000 to kva 355, , % >10000 kva - Primary 468, , , % Direct Connects to T.A. 492, , % Street Lights 58, , % Traffic Lights 6, , % Lane Lights 5, % Security Lights 6, % Total 6,682,776 1,060 2,432 2,105 21,965 2,897, % EUB Decision (August 13, 2004) Page 8 of 10

243 Appendix 3 DAS-12: Allocation of Primary Costs to Customer Classes < 5000 kva Column Reference A B C D E F G H I=SUM(E:H) Line Reference Customer Segment Total On-peak kwh Total Off-peak kwh Customers <5000 kva On-peak kwh Customers <5000 kva Off-peak kwh Customers <5000 kva On-Peak Primary Cost ($) Customers <5000 kva Off-Peak Primary Cost ($) Customers <5000 kva On-Peak Contributions ($) Customers <5000 kva Off-Peak Contributions ($) per DAS-11 per DAS-11 Based on col. C Based on col. D DAS-14.1 DAS-14.1 Total Primary Cost Allocated to Customers <5000 ($) 1 Residential 730,842, ,160, ,842, ,160,815 10,921,231 1,767,717 (487,689) (78,785) 12,122,473 2 < 50kVA 306,374, ,501, ,374, ,501,757 4,578, ,555 (46,396) (7,495) 5,308, to 149 kva 236,979, ,851, ,979, ,851,986 3,541, ,776 (35,887) (5,797) 4,090, to 499 kva 406,190, ,341, ,190, ,341,629 6,069, ,763 (63,515) (10,261) 6,895, to 999 kva 290,755, ,553, ,755, ,553,793 4,344, ,334 (49,198) (7,948) 4,926, to 1499 kva 93,280, ,720,835 93,280, ,720,835 1,393, ,169 (17,938) (2,898) 1,586, to 2499 kva 19,659,219 19,471,777 19,659,219 19,471, ,774 37,489 (10,695) (1,728) 318, to 4999 kva 16,727,276 21,365,823 16,727,276 21,365, ,961 41,135 (24,704) (3,991) 262, to kva - - Customer Specific Direct Connects to T.A. 170,564, ,997,324 Customer Specific to Primary to Primary 13,227,142 14,576,159 13,227,142 14,576, ,658 28, , to Primary 34,120,810 38,889,625 34,120,810 38,889, ,879 74, , to Primary 25,171,694 30,883,159 25,171,694 30,883, ,149 59, , to Primary 50,963,735 60,686,765 50,963,735 60,686, , , , to Primary 146,406, ,868, ,406, ,868,363 2,187, , ,553, to Primary 156,569, ,347,852 Customer Specific >10000 kva - Primary 189,488, ,219,923 Customer Specific Street Lights 6,158,687 52,176,701 6,158,687 52,176,701 92, ,455 (933) (151) 191, Traffic Lights 2,502,836 4,326,653 2,502,836 4,326,653 37,401 8,330 (379) (61) 45, Lane Lights 550,619 4,734, ,619 4,734,403 8,228 9,115 (83) (13) 17, Security Lights 686,296 5,879, ,296 5,879,334 10,256 11, , Total 2,897,220,847 3,785,554,677 2,380,598,149 2,984,989,577 35,574,093 5,746,941 (737,416) (119,128) 40,464, Ratio of Off-peak Energy to Total Energy 55.6% Before Amort. Amortization Net 25 Total Primary Costs 42,975,960 (856,544) 42,119, Less: Portion related to Customer Segments >= 5000 kva 1,654,927-1,654, Primary Costs to Customer Segments <5000 kva 41,321,033 (856,544) 40,464, % Attributable to all Kwh 25% 25% 29 Off-Peak Primary Costs to Customers Classes <5000 kva (Line 27*Line 28*Line 24) 5,746,941 (119,128) 5,627, On-Peak Primary Costs to Customers Classes <5000 kva (Line 27- Line 29) 35,574,093 (737,416) 34,836,677 EUB Decision (August 13, 2004) Page 9 of 10

244 Appendix 3 Jan-02 Nov-02 Dec-02 Jun-02 Jul-03 Aug-03 Average CP Res,Scomm,Mcomm ,305 Interval Secondary ,456 Interval Primary ,914 Direct Connect ,000 Customer Specific ,182 Night Lights ,925 Cont Lights Total EUB Decision (August 13, 2004) Page 10 of 10