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Decision 2005-096

Alberta Electric System Operator (AESO) 2005/2006 General Tariff Application August 28, 2005

ALBERTA ENERGY AND UTILITIES BOARD Decision 2005-096: Alberta Electric System Operator (AESO) 2005/2006 General Tariff Application Application No. 1363012 August 28, 2005 Published by Alberta Energy and Utilities Board 640 – 5 Avenue SW Calgary, Alberta T2P 3G4 Telephone: (403) 297-8311 Fax: (403) 297-7040 Web site: www.eub.gov.ab.ca

EUB Decision 2005-096 (August 28, 2005) • i

Contents

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

2 2005 OWN COST OUTSTANDING MATTERS .............................................................. 2 2.1 Incentive Compensation Program Parameters ............................................................... 2 2.2 Disallowance of Costs.................................................................................................... 3

3 2005 PHASE I REVENUE REQUIREMENT ................................................................... 4 3.1 2005 Revenue Requirement and Deferral Account Treatment ...................................... 4

4 2006 PHASE I REVENUE REQUIREMENT ................................................................... 5 4.1 2006 Own Costs Process................................................................................................ 5 4.2 Forecast Methodology.................................................................................................... 6

4.2.1 Key Forecast Inputs .......................................................................................... 6 4.3 TFO Wires Related Costs............................................................................................... 8 4.4 Non-Wires Costs ............................................................................................................ 9 4.5 Ancillary Services Forecast.......................................................................................... 12 4.6 Transmission Losses .................................................................................................... 13

5 RATE DESIGN ................................................................................................................... 13 5.1 Legislative Requirements............................................................................................. 13 5.2 Rate Design Principles ................................................................................................. 15 5.3 Transmission Wires Cost Causation Study (TCCS) .................................................... 17

5.3.1 Functionalization of Costs .............................................................................. 19 5.3.2 Classification of Costs .................................................................................... 21

5.4 Ancillary Services Cost of Service Study .................................................................... 24 5.4.1 Classification of Ancillary Services................................................................ 25

5.5 Demand Transmission Service Rate Design ................................................................ 25 5.5.1 Unbundling ..................................................................................................... 25 5.5.2 Classification of Costs .................................................................................... 26 5.5.3 Ratchet ............................................................................................................ 29 5.5.4 Standby Tariffs................................................................................................ 30

5.6 Supply Transmission Service Rate (STS) .................................................................... 30 5.7 Fort Nelson BC Rate .................................................................................................... 30 5.8 Export Rates ................................................................................................................. 33

5.8.1 Firm Export/Import Rates ............................................................................... 33 5.8.2 Generator Remedial Action Scheme (GRAS) ................................................ 36 5.8.3 Opportunity Import and Export Rates............................................................. 37

5.9 Primary Service Credit and Finalization of COS Credits ............................................ 38 5.10 Opportunity Service Rates ........................................................................................... 40 5.11 Rate Riders ................................................................................................................... 41

5.11.1 Rider B.......................................................................................................... 41 5.11.2 Rider C.......................................................................................................... 41 5.11.3 Rider E .......................................................................................................... 41

6 TERMS AND CONDITIONS – CONTRIBUTION POLICY........................................ 42 6.1 Customer Contribution Policy ..................................................................................... 42

6.1.1 High Level Policy Principles .......................................................................... 42 6.1.2 Designation of System-Related Costs............................................................. 47

ii • EUB Decision 2005-096 (August 28, 2005)

6.1.3 “Standard” and “Optional” Interconnection Facilities.................................... 49 6.1.3.1 AESO Standard Service Definition ................................................................ 49

6.1.4 Maximum Investment Formula....................................................................... 55 6.1.5 Contribution Waivers for Expansion at Multiple Customer PODs ................ 58 6.1.6 Other Contribution Policy Issues .................................................................... 60

6.1.6.1 Application of Contribution Policy to Dual-Use Sites ................................... 60 6.1.6.2 Staged Load .................................................................................................... 62 6.1.6.3 Distribution vs Transmission Interconnections .............................................. 62 6.1.6.4 Discount Rates ................................................................................................ 63 6.1.6.5 Common Facilities .......................................................................................... 63 6.1.6.6 Conditions for Customer Contribution Adjustments ...................................... 66 6.1.6.7 Pre-Paid Operations and Maintenance Charge ............................................... 66

6.2 Generator System Contribution ................................................................................... 69 6.3 Contribution Policy Next Steps.................................................................................... 73

6.3.1 Contribution Policy Implementation Timing.................................................. 73 6.3.2 Disco/AESO Contribution Policy Harmonization .......................................... 73

6.4 TransCanada Standard Interconnection Facilities Complaint...................................... 73

7 TERMS AND CONDITIONS – OTHER ......................................................................... 74 7.1 System Access Applications ........................................................................................ 74 7.2 Right of “Set-Off” ........................................................................................................ 75 7.3 TFO Investment in Optional Facilities Constructed for Distribution Facility Owners (Discos) ................................................................................................................................. 76 7.4 Merchant Transmission Interconnections .................................................................... 78 7.5 Contract Term, Reductions, and Termination.............................................................. 80 7.6 Letters of Credit Security in Respect of Construction Projects ................................... 83 7.7 Consistency, Business Practice Documents and Other T&C Issues ............................ 84

8 OTHER MATTERS ........................................................................................................... 88 8.1 Disposition of Outstanding Board Directions .............................................................. 88

9 REFILING OF APPLICATION ....................................................................................... 91

10 ORDER ................................................................................................................................ 91

APPENDIX A – RATE DESIGN SPREADSHEET ................................................................ 92

APPENDIX 1 – HEARING PARTICIPANTS......................................................................... 93

APPENDIX 2 – SUMMARY OF BOARD DIRECTIONS ..................................................... 95

APPENDIX 3 – ABBREVIATIONS ....................................................................................... 101

EUB Decision 2005-096 (August 28, 2005) • 1

ALBERTA ENERGY AND UTILITIES BOARD Calgary Alberta ALBERTA ELECTRIC SYSTEM OPERATOR (AESO) Decision 2005-096 2005/2006 GENERAL TARIFF APPLICATION Application No. 1363012 1 INTRODUCTION

On October 3, 2004, the Alberta Electric System Operator (AESO) filed a Phase I and II General Tariff Application (GTA) requesting approval of its 2005 Forecast revenue requirement amounts for wire costs, ancillary services, transmission line losses and AESO own costs for future rate setting purposes. The AESO also requested approval of both new rate schedules and changes to the terms and conditions of providing system access service. On October 29, 2004, the Board issued correspondence in which it established a schedule to hear the Own Cost portion of the 2005 Phase I GTA. On March 4, 2005 the Board issued Decision 2005-015 which, subject to a few directions, approved the Own Cost request of the AESO 2005 GTA. On December 2, 2004, the Board issued correspondence noting that the Transmission Regulation enacted by the Provincial Government required the AESO to file with the Board an application with respect to a 2006 tariff no later than February 1, 2005, with a decision regarding the tariff to be rendered by the Board no later than September 1, 2005. In consideration of these matters, the Board determined that it would be most efficient to combine the proceedings of the balance of the 2005 GTA with the forthcoming 2006 GTA, and directed the AESO to file a 2006 GTA by February 1, 2005. The correspondence also set out a schedule for the processing of the combined 2005/2006 GTA. On February 4, 2005 the AESO filed a 2006 Phase I and II GTA (the Application or GTA) with the Board. The AESO stated that the Application included all the matters required by the Transmission Regulation to be included in the 2006 tariff effective January 1, 2006. The AESO requested that the Application replace the 2005 Phase II filing of October 3, 2004 in its entirety. The Application requested, inter alia, the following:

(a) Approval of its 2006 forecast revenue requirement amounts for wire costs, ancillary services, transmission line losses, and AESO own costs for future rate setting purposes;

(b) Confirmation from the Board that the AESO’s entire 2006 forecast revenue requirement would be subject to deferral account treatment;

(c) Approval of both new rate schedules and changes to the terms and conditions of system access service. The AESO requested that its proposed tariff become effective January 1, 2006;

(d) Confirmation from the Board that the AESO would continue to employ its existing Rate Riders B and C and annual deferral account reconciliation process for the calculation of

2005/2006 General Tariff Application Alberta Electric System Operator

2 • EUB Decision 2005-096 (August 28, 2005)

rates and the recovery of all actual incurred costs excluding losses until such time as the Board approved changes to those processes;

(e) Approval of a new Rider E for transmission system losses;

(f) Confirmation from the Board of its acceptance of the AESO’s responses to outstanding matters; and

(g) Such other relief as the Board deemed appropriate. The Application was heard by way of an oral hearing which commenced April 11, 2005 and adjourned April 20, 2005. The venue of the hearing was the Board’s hearing room in Edmonton, Alberta. The panel hearing the Application was comprised of Mr. R. G. Lock as Presiding Member and Mr. J. I. Douglas and Mr. M. W. Edwards as Members. Written argument was received from the parties on May 16, 2005, and written reply was received on May 30, 2005. The Board therefore considers the close of record for this proceeding to be May 30, 2005. 2 2005 OWN COST OUTSTANDING MATTERS

2.1 Incentive Compensation Program Parameters The Board notes that when the AESO’s own costs for 2005 were originally dealt with in Decision 2005-015, the parameters for the 2005 employee incentive program had not been finalized. As noted by FIRM in its argument, the dollar amount set aside for incentive payments was not disclosed at that time. As disclosed in evidence during this proceeding, the parameters remain incomplete. FIRM submitted that the incentive parameters should be addressed through the consultative process and addressed as part of the subsequent AESO 2006 Own Costs filing. The 2005 amounts previously approved as a placeholder would continue in place and serve as the basis for the 2006 incentive program consultation and subsequent filing. FIRM suggested that, as the goals still had not been defined and established, it would not be possible to assess performance in meeting those goals or determine the correspondingly appropriate amount of compensation. Accordingly, FIRM recommended these matters be addressed as part of a future deferral account proceeding. TransCanada Energy Ltd. (TCE) noted that in Exhibit 02-008, the AESO described cost management objectives contained in the AESO’s employee incentive program. Achieving cost savings through reduced ancillary services costs is one performance objective upon which the AESO provides financial incentives to certain employees.1 TCE stated the AESO was in a unique position in that it not only operates the transmission system, power pool and related functions, but also has rulemaking authority over how market participants interact with the AESO and each other.2 Providing certain staff with an incentive to drive down the cost of ancillary services may on its own not necessarily be a concern. However, TCE maintained that, when it is combined with the rulemaking powers of the AESO and the access that other AESO employees have respecting the offer behaviors and maintenance forecasts of generators, it can become problematic. This was less of a concern when the AESO functions were fulfilled by two separate organizations, the Transmission Administrator (TA) and the Power Pool. In TCE’s view, it is a 1 Exhibit 02-008, IPPSA.AESO-005 (a) IV 2 Alberta Electric Utilities Act, Chapter E-5.1 (the EUA), Section 20(1)



major concern with the combined responsibilities of the AESO. Consequently, TCE recommended that the AESO should be directed, at the next GTA, to identify potential conflicts of interest between AESO functions and to describe AESO’s measures for preventing such conflicts. These measures could include, for example:

1. a revised code of conduct;

2. physical separation of staff;

3. separate reporting relationships for staff who should not be exchanging information; and

4. staff incentive compensation that ensures that a single potential conflicting objective such as ancillary service cost reduction, does not become preeminent over other objectives, such as system reliability, customer satisfaction and promotion of a fair, efficient and openly competitive market for electricity.

The AESO, in response to TCE’s concern, suggested that code of conduct issues requiring the attention of the AESO should be brought to the attention of the Competing Mandates Committee which was formed by the AESO in 2004 to address code of conduct issues. As stated above, the Board notes that the incentive parameters for 2005 are still not available for Board review. The Board also notes that in other utility decisions, such as 2005-019 dealing with AltaLink’s revenue requirement, the Board has denied amounts for incentive payments even though they were supported by detailed discussion of payout parameters. The Board does not consider that it can reasonably approve a revenue requirement for this item when the AESO cannot identify to stakeholders either the amount proposed for incentives or the parameters to be used in measuring performance. The Board directs the AESO to exclude from its revenue requirement and collection through the deferral account process any amounts related to employee incentive payments. The Board also notes the concerns expressed by TCE and agrees that the AESO is charged with potentially conflicting responsibilities. The Board further agrees that it is reasonable to consider different incentive parameters for the staff charged with the differing responsibilities identified by TCE. The AESO can report upon this when filing the deferral account application, if the AESO chooses to refile for approval of incentive payments at that time. While the Board will not direct the AESO to consider all the other suggestions of TCE at this time, the AESO is directed to comment and report upon them when filing its next GTA. 2.2 Disallowance of Costs In Decision 2005-015 the Board noted its prior Decision 2005-005 in which it discussed the merits of applying disallowances for deemed imprudent costs only on a “notional” rather than an “actual” basis in the context of its discussion on the use of deferral accounts. In this regard, the Board noted that its expectation was that, even if only a notional disallowance is applied, the act of simple identification of imprudent costs should, of itself, lead to self-correcting behaviour by shedding additional light on the deemed imprudence. While the Board did not order the AESO to restate its revenue requirement forecast to more precisely segment the costs disallowed in UCO 2004-038 in Decision 2005-015, the Board nonetheless considered that the issue of how to account for disallowed costs should receive



further consideration. Accordingly, the Board expected that this matter would be further pursued by parties in the balance of the AESO 2005/2006 proceeding. The Board notes that, contrary to its expectations, no parties commented on this issue. Nonetheless, the Board has considered the matter of disallowance and concludes that while notional disallowance may be appropriate as an initial motivator for the AESO, it is inadequate as a means to address ongoing imprudent cost behaviour. In this regard, the Board has taken the position that in the event that it has previously directed the AESO to take some action in response to a notional disallowance on costs that have been found by the Board to have been imprudently incurred by the AESO, and the AESO has not satisfactorily corrected its behaviour, the Board may direct an actual disallowance of all or a portion of these costs on a go forward basis. By way of example, the Board has indicated to the AESO in past decisions3 that it considers the AESO’s use of external legal counsel in substitution for the development of sufficient in-house legal resources to be an instance where the AESO may have incurred unnecessary costs. To date, the Board has gone so far as to direct the notional disallowance of some of these costs. In the event that the AESO does not take action either to voluntarily remove notionally denied costs from its revenue requirement or to convince the Board that these costs are prudent and appropriate, the Board may consider an actual disallowance of some or all of these costs. In the event of such disallowance and where the AESO has not provided the necessary justification, the AESO shall not seek to recover these costs in any fashion from its customers through regulated activities. 3 2005 PHASE I REVENUE REQUIREMENT

3.1 2005 Revenue Requirement and Deferral Account Treatment The Board notes that with the exception of the incentive parameters discussed in the prior section, no party took issue with the 2005 revenue requirement requested by the AESO. The Board notes interim rates were set for 2005 in Board Order U2004-476. As the Board does not consider the incentive amounts disallowed in the prior section to be material, the Board considers it reasonable to continue the interim rates currently in place. The 2005 revenue requirement will be finalized when the AESO files its 2005 deferral account application and the status of 2005 incentive payments is finalized. Finally, the Board also notes that the AESO has requested, in its original 2005 Application, deferral account treatment for its 2005 revenue requirement similar to previous years. The Board notes that no party has taken issue with this proposal and it is approved as requested.

3 Decisions 2004-012 and 2005-015



4 2006 PHASE I REVENUE REQUIREMENT

4.1 2006 Own Costs Process In argument, FIRM noted the evidence of the AESO4 that the amount included in the application for 2006 own costs was just a placeholder. No further application to seek approval of a more advanced forecast of these costs was planned beyond the deferral account application for 2006, which would not be made until August 2007. FIRM supported a more timely review and approval process for the AESO 2006 Own Costs by the fall of 2005, with the Board providing approval of the placeholder amount in this application subject to a future filing for review and approval in the fall of 2005. FIRM further suggested that a Board approved budget review committee process, including the availability of participant funding, would facilitate stakeholder understanding of the AESO proposals and serve to potentially minimize future litigation of the application eventually filed with the Board for approval. In its reply, IPCAA took issue with FIRM’s request for intervener funding with respect to the AESO’s proposed budget review process. IPCAA termed FIRM’s request and recommendation out of place, inappropriate and irrelevant to the proceeding. IPCAA noted the Board had no evidence before it concerning cost recovery for such matters, or concerning any discussions or understandings between the AESO and stakeholders involved in committee discussions regarding cost recovery. IPCAA maintained the Board should reject FIRM’s funding request and recommendation outright. TCE supported the AESO filing its 2006 Own Costs Forecast with the Board, but recommended to the Board that should the requested amount materially exceed the 2005 Own Costs Forecast, the AESO should be required to provide variance explanations with justifications for the increases. The Board or interveners should also have recourse to challenge the 2006 forecast under these circumstances. The Board notes that the AESO has engaged in a consultative process with its stakeholders and expects that this process will lead to more timely filings of its own costs in the future. With respect to the 2006 placeholder, the Board notes that own costs are a very small portion of the total revenue requirement. The Board does not, therefore, consider it necessary to have a special process later this year to review a final 2006 own cost proposal. The Board notes the AESO has also stated that it will provide the EUB and interveners with explanations and justifications for any variances to its 2006 own costs. The Board will accept the placeholder and notes that prudent variances from forecast will be trued up through the deferral account process. As with 2005, however, the Board directs the AESO to remove employee incentive payments until the relevant amount and acceptable performance criteria are identified. With respect to FIRM’s suggestion that intervener funding be available for the AESO’s process, the Board notes that the AESO noted in the Application5 that membership in the Standing Advisory Committee would be voluntary and unpaid. With respect to FIRM in particular, the Board notes that its membership represents hundreds of thousands of residential consumers as well as small commercial and institutional consumers. The Board considers that FIRM’s

4 Transcript, page 756 5 Section 2, page 29



membership should be interested in such matters irrespective of public funding though rates, and further, the Board does not consider these groups to be either small or without means. The Board also notes the Utility Consumer Advocate (UCA) also has a responsibility and resources to represent such customers. 4.2 Forecast Methodology In argument, the AESO stated6 that, whenever possible it had used the most recent data available for determining all 2006 forecast amounts. The AESO noted that there were no information requests regarding the Forecast Methodology and the AESO panel was not questioned on this issue during the hearing. Therefore, the AESO requested that the Forecast Methodology be approved. The Board notes that minimal comments were received on this topic and subject to the comments in the following sections, the methodology is approved. 4.2.1 Key Forecast Inputs FIRM expressed concern with the impact the changes in the 2006 pool price forecast could have on DTS customers and its detrimental effect on the Ancillary Services and Losses forecast. FIRM noted EDC Associates Ltd. (EDC), the only source used for price forecasts by the AESO, was unable to supply any supporting details due to the proprietary nature of its information. FIRM recommended the AESO utilize additional sources for future forecasts of pool price and provide comprehensive supporting data on the underlying assumptions. The AESO stated in reply that it did produce an hourly pool price or daily gas price forecast one or more years into the future, which is required in order to prepare the loss and ancillary services cost forecasts. The AESO relies on the EDC commodity price forecast which provides the following:

• Detailed quarterly forecasts which includes a 20 year commodity price forecast, the likely in-service dates of generation under construction and applications made to the AEUB for constructing new generation.

• Weekly forecast updates which include a 2 year commodity price forecast. The AESO noted the EDC commodity price forecast has been used by the AESO and predecessor organizations since at least 2002 for the following reasons:

• The EDC forecast is a credible, industry accepted standard.

• A third-party or arms length forecast is less contentious.

• Purchasing the EDC forecast is more cost–effective than producing an internal forecast. The AESO noted that in Information Response BR.AESO-030, the AESO stated that in the future it will use the most recent EDC bi-weekly forecasts regarding ancillary service forecasts.

6 Application, Section 2, page 1



The reliability of the forecasts was also addressed in Information Response BR.AESO-02 from the 2004 Phase I Revenue Requirement Application, in which the AESO provided information regarding the experience and qualifications of EDC with respect to pool price forecasts:

EDC Associates was founded in 1992 by Mr. Duane Reid-Carlson. Mr. Reid-Carlson who is also the principal of EDC holds a B.Sc. degree in Electrical Engineering from the University of Alberta. Mr. Reid-Carlson oversees a team of energy economic analysts that are responsible for providing electric energy supply, demand and price forecast information, energy procurement, generation development and regulatory analytical services.

Furthermore, during cross-examination, the Alberta Direct Connect Consumer Association (ADC) panel stated7 that some ADC members used EDC forecasts and noted that EDC is a credible and professional organization. The AESO submitted that it was not cost effective to use other sources in the determination of pool price forecasts. Furthermore, the amount billed each month for losses reflects the actual pool price and not the pool price forecast. The Board shares the concerns of FIRM with respect to the accuracy of the AESO’s forecasts. The Board must also acknowledge, however, the evidence of the AESO with respect to the competence of EDC and the difficulties in obtaining other Alberta specific forecasts. While the Board would like to see more accurate forecasts it agrees with the AESO that this may not be practical. The AESO has stated it is a non-profit organization and simply does not have the means to employ highly specialized staff in order to forecast commodity prices when another credible source is readily available. The Board is concerned that the EDC information was unable to be disclosed in such a manner as to understand its basis and concludes that an understanding of such information would be helpful in that these forecasts provide the AESO with a foundation for its tariff structure. To that end, the Board directs the AESO at the time of its next GTA to assess the business case for developing its own view on such a forecast using its knowledge of external information and its operating knowledge. The Board notes that the AESO has added considerable expertise over the past few years and that it may not require the incremental costs of merely adding more resources. Rather, the Board would look to the AESO to provide such forecasts from its own existing experts and current knowledge of the market activity in Alberta and its participation in its several peer group associations. The AESO remains free to engage resources such as EDC. However, for purposes of enhancing the understanding of all parties to the GTAs, the process will benefit from the AESO’s explanations of the basis of such forecasts, even if these explanations are conclusions and assumptions which the AESO has made. This would provide the Board and stakeholders with a solid understanding of the basis of the AESO forecasts and tariffs.

7 Tr. Pages 1383-84



4.3 TFO Wires Related Costs FIRM noted the AESO utilizes the latest forecasts or approved amounts from the Transmission Facilities Owners (TFOs) in its forecast of wires related costs and agreed with this approach. TCE stated that the AESO’s use of requested but unapproved revenue requirements without adjustment contributes to errors in AESO forecasts and increases the size of deferral accounts.8 As a result, the AESO forecasting method will typically result in a revenue requirement above that actually charged to AESO customers. This excessive revenue requirement occurs because the Board has historically approved revenue requirements at lower levels than the revenue requirement amounts applied for.9 As a result of this practice, customers must be refunded for wires-related amounts that they have been overcharged for. However, TCE noted that using previous Board-approved revenue requirements for the TFOs when determining the AESO revenue requirement is likely to understate the amount of the AESO revenue requirement that should be collected from AESO customers. Consequently, TCE recommended the Board direct the AESO to adjust its forecast revenue requirement for TFOs to a reasonable estimate between the amounts for currently approved TFO wires costs and the TFO applied for wires related revenue requirement. TCE further recommended that any adjustment be done on an aggregate basis for all TFO wires related costs to ensure that adjustments could not be attributed to an individual TFO. TCE anticipated that the AESO could use an interim rate charge if the interim charge is meant to extend over the year end. In those circumstances, the interim charge would effectively be the final charge for that year since differences between final approved amounts after a year end has passed would go to deferral accounts. The AESO noted in its argument that it addressed the issue of its forecasting accuracy in Information Response BR.AESO-028 (a-b). In particular, the AESO noted that it would be “prepared to amend its 2006 Wires Costs for interim or final approved TFO tariffs when the AESO files its revenue requirement as directed in the Board’s September 1, 2005 Decision.” In response to the position advocated by TCE, the AESO submitted that TCE was suggesting a methodology that the AESO was already engaged in. The suggested methodology is essentially what the AESO applied for in the 2006 Application. As stated in the Application10 the AESO advised that it would use final or latest interim approved amounts in determination of wires costs for its revenue requirement. Further, the AESO referred to Information Response TCE.AESO-102 (a-g), in which the AESO advised that the use of unapproved TFO revenue requirements may create a variance with respect to deferral accounts. Similarly, the use of interim approved tariffs which the AESO has used in previous GTAs may also create a variance in deferral accounts if there is a difference from the final approved tariff following a decision from the Board on the AESO’s GTA. Therefore, the AESO submitted it should not be required to make a reasonable estimate between the amounts for currently approved TFO wires costs and the TFO applied for wires related revenue requirement. 8 Exhibit 02-033,TCE.AESO-102 (a-c) 9 For example, AEUB Decision 2004-018, page 3, for EPCOR TFO reduced the 2004 revenue requirement by

$3.11 million on a request of $35.66 million (a 9% reduction), AEUB Decision 2004-016, page 2, approved $156.2 million for 2004 for ATCO Electric (TFO) on a revenue requirement request of $175 million per AEUB Decision 2003-071, page 1, (an 11% reduction) and AEUB Decision 2004-028, page 6, for AltaLink approved $150.1 million on an applied for revenue requirement of $166.8 million (a 10% reduction).




The Board notes the concern of TCE, but considers that its proposal may be administratively complex and may not add material value to the process. The Board notes the AESO’s willingness to update its forecast for any interim or final approvals granted to TFOs and considers this a more practical approach to the problem identified. The Board directs the AESO to follow its proposed practice of updating its forecast of wires related costs to reflect any interim or final approvals granted to TFOs. The Board will accept the AESO’s current forecast, subject to any updates the AESO may file. 4.4 Non-Wires Costs The AESO forecast TMR costs of $41.4 million and $53.2 million for 2005 and 2006 respectively, an increase of $11.8 million. The AESO attributed the 28.5 % forecast increase for 2006 over the 2005 forecast primarily to an anticipated decline in market heat rates and the inclusion of costs related to a pending contract for TMR service from the Rossdale generating unit. The AESO noted that TMR service is normally procured through commercial agreements negotiated between the AESO and suppliers. These agreements are typically structured to compensate the TMR provider based on the ratio of the hourly pool price in $/MWh to the cost of natural gas in $/GJ (the “market heat rate”). If the market heat rate in a particular hour is above the heat rate benchmarks specified in the TMR contracts with suppliers, no variable cost is incurred for TMR from that unit. However, when the market heat rate in a particular hour is lower than the heat rate benchmarks specified in the TMR contracts, variable costs are incurred for TMR. As such, the AESO noted that there is an inverse relationship between variable TMR payments and market heat rate In its argument submission, the AESO noted the sensitivity analysis of the forecast TMR costs assuming various pool prices and gas prices that it had provided to the Board at the Board’s request. This sensitivity analysis illustrated the manner in which actual TMR costs are influenced by commodity prices.11 The AESO also noted that it had provided a breakdown of TMR costs on a regional basis exclusively to the Board. This information was provided on a confidential basis in light of the commercially sensitive nature of the information sought. The AESO submitted that its confidential information request responses to the Board were full and complete. The AESO also noted that the AESO panel provided full and complete responses to Board questions regarding the results of the RFP process to procure TMR services for the Calgary and Rainbow Lake areas in an in camera hearing session held on April 14, 2005. The AESO submitted that the confidential information and information derived from the in camera session supports the conclusion that the AESO’s forecast of 2005 and 2006 TMR costs is both reasonable and prudent. The Board notes that significant information related to the derivation of the AESO’s 2005 and 2006 TMR cost forecast was deemed commercially sensitive and, as such, was provided on a confidential basis to the Board. As a result of the restricted availability of some information, the Board was required to take a comparatively active role in clarifying the derivation and reasonableness of the AESO’s TMR cost forecast in the Application proceeding. 11 Exhibit 030-042



The Board’s interest in TMR matters within the Application proceeding related primarily to the following main areas:

1. Understanding the extent to which key variances between the forecast and actual level of key forecast inputs such as pool price, natural gas prices, and the market heat rate may result in variances between the forecast and observed level of TMR cost;

2. Understanding the regional breakdown of forecast TMR costs; 3. Understanding the effect of applicable Transmission Regulation provisions on the

AESO’s obligations to mitigate TMR costs;and, 4. Understanding the AESO’s plans to mitigate TMR costs in light of the AESO’s

obligations under Subsection 8(3) of the Transmission Regulation. With respect to the overall level of the AESO’s TMR forecast, the Board notes that, while FIRM expressed some concern about the reasonableness of forecast input parameters, neither FIRM, nor any other party took issue with the reasonableness of the AESO’s forecast of 2005 and 2006 TMR costs. The Board likewise considers that the forecasts appear to be reasonable in light of the input parameters discussed during the Application proceeding. The Board remains concerned with the extent to which TMR costs have grown over a relatively short time.12 The Board also notes that, notwithstanding the Board’s acceptance of the AESO’s 2005 and 2006 forecasts, there remains risk that further increases in 2005 and 2006 TMR costs may be observed in the event that the AESO’s forecasts of average natural gas prices in those years is found to be understated and/or if the forecast level of the average pool prices is found to have been overstated. As a result, the Board considers there to be some urgency to ensure that TMR costs are appropriately addressed. With respect to the regional breakdown of forecast TMR costs, the Board notes that it is precluded from disclosing much of the information provided to the Board within this Decision. Notwithstanding this constraint, however, the Board has been made aware that a notable component of the 2005 and 2006 forecast relates to TMR costs incurred in the NW region of Alberta and in particular in the Rainbow Lake area. Without violating the confidentiality constraints agreed to by the Board, the Board considers that the proportion of the forecast TMR costs related to forecast Rainbow Lake area TMR is sufficiently high so as to warrant further investigation of these costs and the actions proposed by the AESO to address these costs. With respect to the Board’s questions regarding the effect of the Transmission Regulation on the AESO’s duties in respect of TMR and TMR costs, the Board considers that the AESO’s discretion to utilize TMR is primarily defined under Section 8 of the Transmission Regulation, and in particular through Subsections 8(1)(e) 8(3), and 8(4) thereof.

12 The Board notes that Table 5.1.11 found on pages 4-5 of Decision 2000-1 (excerpt filed as Exhibit 030-045

during the Application proceeding) indicates that forecast AESO TMR costs have risen more than 10 fold from the $4.0 million level of “Transmission Constrained On” compensation forecast for 2000.



Section 8(1)(e) is reproduced as follows:

8(1) In making rules under section 20 of the Act, and in exercising its duties under section 17 of the Act, the ISO must

(e) taking into consideration the characteristics and expected

availability of generating units, plan a transmission system that

(i) is sufficiently robust to allow for transmission of 100%

of anticipated in-merit electric energy referred to in section 17(c) of the Act when all transmission facilities are in service, and

(ii) is adequate to allow for transmission, on an annual basis,

of at least 95% of all anticipated in-merit electric energy referred to in section 17(c) of the Act when operating under abnormal operating conditions;

To the extent that, by definition, TMR involves the directed dispatch of generation that is not in-merit, when read by itself, the Board considers that Subsection 8(1)(e) of the Transmission Regulation would have the effect of precluding the AESO from planning a transmission system that relies on TMR. The Board notes, however, that Subsection 8(3) of the Transmission Regulation provides that limited exceptions may be granted from the requirements Subsection 8(1) (e). Subsection 8(3) reads as follows:

8(3) In planning and arranging for enhancements or upgrades to the transmission system, the ISO may make or provide for specific and limited exceptions to the matters described in subsection (1)(e), (f) and (g), or any of them, and if it does so, must

(a) file the exceptions with the Board for approval, and (b) specify the period of time the exception applies.

Subsection 8(4) is also relevant and states:

8(4) In considering the design and planning of the transmission system, the ISO may consider specific and limited exceptions to the requirements of subsection (1) and propose a non-wires solution

(a) in areas where there is limited potential for growth of load,

and the cost of the non-wires solution is materially less than the life-cycle cost of the transmission wires solution, compared over an equivalent study period, or

(b) if the non-wires solution is required to ensure reliable service

due to the shorter lead time of the non-wires solution, for a specified limited period of time.



The Board considers that, in combination, the above noted Sections of the Transmission Regulation have the effect of permitting TMR to be utilized, but only on an exception basis where the Board has determined that the exceptional circumstances for the acceptable long term use of TMR apply. The Board also recognizes, however, that circumstances may arise from time to time to make it necessary for the AESO to procure TMR on a short-term basis. As such, the Board considers that it would be both impractical and detrimental to the AESO’s duty to provide safe and reliable service to require the AESO to make an application to the Board before procuring TMR under these circumstances. Accordingly, the Board considers that the requirement to file a need application pursuant to Subsection 8(3) should generally only be required in circumstances where the anticipated cost of procuring TMR over a sustained period is at or above a reasonable “ballpark” estimate of the cost of a wires upgrade.13 Given the high level and apparent persistence14 of the TMR costs in the AESO’s revenue requirement, the Board sought to clarify the AESO’s plans to mitigate these costs, and in particular its plans in respect of the Rainbow Lake area portion thereof, during the Application proceeding. During the course of the Board’s examination, members of the AESO’s witness panel described these plans.15 The Board found the information provided by the AESO panel to be very helpful and informative. Furthermore, as a result of this testimony and the communication of the AESO’s definitive intent to address NW TMR issues in the near term, the Board is satisfied that the AESO has adopted a prudent and reasonable go forward plan to address the Board’s concerns with rising TMR costs. In light of the Board’s findings, the Board anticipates that it will not be necessary to examine the AESO’s actions and strategies in regard to TMR in the detail pursued by the Board in this proceeding in future AESO general tariff application proceedings. Rather, the Board considers that such examination will normally take place in the context of AESO need applications such as the AESO’s forthcoming NW area need application. Only in the event that a need application is not received prior to the Board’s consideration of the AESO’s next GTA will the Board again be required to examine these costs to the extent required in this proceeding. 4.5 Ancillary Services Forecast In reply, the AESO noted the comments of FIRM with respect to key forecast inputs and stated that the low pool price forecast does not have a significant impact on the Ancillary Services forecast. The only place pool price is used in the 2006 forecast is for TMR costs. TMR costs are driven by market heat rates, not pool price. The market heat rate forecast used for 2006 is slightly lower than the forward market at this time (while the forecasted 2005 market heat rate is slightly higher than the forward market at this time). The AESO submitted that the issue regarding ancillary services forecasts has been adequately addressed and therefore, should be approved by the Board. The Board accepts the AESO’s

13 The Board notes, however, that this threshold has been met in respect of NW region and Rainbow Lake area

TMR costs. 14 See Decision 2005-005, page 21 15 Transcript, Volume 5, page 1219



forecast but is mindful of its directions respecting the importance of the AESO’s forecasts expressed earlier in this Decision. 4.6 Transmission Losses TCE did not have comments with respect to the accuracy of the AESO’s forecast but did comment upon loss factor methodologies. TCE noted the AESO had indicated that when it forecasts losses, it may either use a forecast of a unit’s dispatch behavior or an estimated dispatch based on the fuel type and historic behavior of a similar facility for new generators.16 The AESO recognized the impact of maintenance as a major change in the operation of a generation plant from year to year.17 In the 2006 GTA proceeding, TCE claimed it identified the double counting of losses associated with exports.18 TCE stated all of these factors suggested a need to consider a plant by plant true-up rather than an across-the-board true-up, most likely in the context of a deferral account proceeding. TCE submitted that the losses based on current loss factors used by the AESO for 2005 or that will be developed for 2006 should not be considered final, but should be subject to a true-up process, whether under ISO rules or a deferral account proceeding, or combination thereof. For these reasons, TCE requested that the Board be clear in its decision that loss forecasts are not final tariffs and that loss factors in use by the AESO for 2005 and 2006 are subject to adjustments in corresponding deferral account proceedings. In reply, the AESO stated that, for 2005, the difference between forecast and actual losses will be dealt with through Rider C and the current deferral account methodology, and will be subject to a deferral account proceeding. For 2006, the AESO advised that it will collect or refund the difference between forecast and actual cost of losses on a prospective basis through Rider E. The AESO proposes to file an annual reconciliation with the EUB for information purposes. The AESO further stated that as transmission loss factors are to be established through the AESO rules, it is expected that the EUB would review the adjustments on a complaint basis only. The Board notes that for 2005 any variance will be dealt with through the usual deferral account process. This would appear to address TCE’s concern for the 2005 year. For 2006, the AESO has proposed a Rider E. The Board notes that TCE did not comment upon Rider E and the Board has dealt with Rider E in section, 5.10.3 of this decision. The Board notes that parties are free to file a complaint with the Board if they are not satisfied with the AESO’s proposal for the setting of loss factors. The Board accepts the AESO’s proposals respecting transmission losses. 5 RATE DESIGN

5.1 Legislative Requirements In argument, the AESO stated that it has responded in its rates to three requirements19 of the Transmission Regulation:

16 Exhibit 02-033, TCE.AESO-203(a) 17 Exhibit 02-033, TCE.AESO-203(b) 18 Exhibit 23-010, TransCanada Written Direct Evidence, page 11, lines 7-12 19 Application, Section 4, page 1



• allocation of all costs of the transmission system (except for losses and regulated

generating unit connection costs) to load customers and exporters, resulting in an overall 66% increase to the DTS rate;

• development of an export and import tariff framework to address all combinations of export and import service, with firm and opportunity bases, over merchant and non-merchant lines; and

• introduction of a calibration factor to ensure that the actual cost of losses is recovered on an annual basis.

The AESO also stated it responded in its Terms and Conditions (T&Cs)20 to two requirements of the Transmission Regulation:

(a) Introduction of a $10,000-$50,000/MW system contribution for generators refundable over ten years with satisfactory performance, in accordance with Part 4 of the Transmission Regulation.

(b) Definition of Maximum TMR Compensation as a cost determination

methodology to limit the amount that can be paid for transmission must-run service, in accordance with Section 23.

The AESO maintained that it was not necessary to include T&Cs for merchant transmission inter-connections as none existed at present. The AESO did support the continued review of such issues through stakeholder consultations. The AESO also noted that all Article 24/TMR (Transmission Must Run) issues had been deferred to a separate Board proceeding. In reply, the AESO took issue with EnCana’s assertion21 that the transmission system was historically built to meet the reliability criteria. In particular, the AESO stated that legislation itself requires the EUB to take a much broader view than simply considering reliability criteria when approving transmission developments. Specifically, subsection 2(a) of the Hydro and Electric Energy Act stated that its purpose is “…to provide for the economic, orderly and efficient development and operation, in the public interest, of hydro energy and the generation and transmission of electric energy in Alberta….” The Board agrees with the AESO. In its intervener evidence, ADC suggested that wires costs incurred to reduce line losses should be allocated to generators. ADC reiterated this in its reply. TransAlta Utilities (TAU) took issue with ADC’s proposal, suggesting that Section 30 of the Transmission Regulation was clear that all wires costs were to be paid by load and only losses by generation customers. The Board agrees with TransAlta’s interpretation and has been guided by this in the rate design sections that follow. Finally, the Board notes both TCE and IPPSA commented upon the requirement22 for the AESO to expand or enhance the transmission system so that inter-provincial inter-ties could handle

20 Application, Section 6, page 1 21 EnCana argument, page 4 22 Transmission Regulation, Section 8(1)(g)



imports/exports at or near each path’s rating. TCE also noted the requirement23 for the AESO to articulate T&Cs to accommodate merchant transmission interconnections. The Board has dealt with these matters in Sections 6 and 7 of this Decision. Subject to any directions in following sections of this Decision, the Board considers the AESO has adequately addressed the requirements of the relevant legislation. 5.2 Rate Design Principles A major point of contention amongst parties was the level of costs to be recovered by demand, energy, and fixed customer charges. The alternatives ranged from a near direct cost recovery by component (demand, energy, fixed) as put forward by the pure cost allocation results of the PSTI (PS Technologies Inc.) COS study (the ADC approach), to a recovery based significantly more on an energy charge (the AESO approach). The Board has, in past decisions, given significant weight to Bonbright et al's principles in evaluating proposed rate designs. Accordingly, a number of parties have listed certain of these principles in support of their proposed rate designs. For example, the ADC considered that recovery of costs should follow cost allocation, while the AESO submitted that gradualism, or concern for rate shock, should play a larger role in its rate design. The Board considers that these two approaches represent parts of a broad spectrum of possible rate designs. The Board notes that in Exhibit 02-023B24 the AESO discussed the consideration of Bonbright’s principles in the development of a rate design, as follows:

A comprehensive rate design review should consider the usual rate design criteria applicable to a utility. Relying on the criteria of a desirable rate structure as described in Principles of Public Utility Rates by Bonbright, Danielsen, and Kamerschen (2nd ed., 1988, pp. 385-389), rate considerations should include:

(i) Recovery of the total revenue requirement;

(ii) Provision of appropriate price signals that reflect all costs and benefits, including in

comparison with alternative sources of service;

(iii) Fairness, objectivity, and equity that avoids undue discrimination and minimizes intercustomer subsidies; and

(iv) Stability and predictability of rates and revenue.

Bonbright et al identify the first three as primary criteria, and they should therefore probably be given more weight when examining a rate design. The fourth is identified as a secondary criterion, and should therefore probably be given less weight. Beyond these general comments, the specific merits of each case must be weighed individually when approving a rate design.

In addition, at the end of the process rates must remain practical — that is, appropriately simple, convenient, understandable, acceptable, and billable.

23 Transmission Regulation, Section 15(6) 24 information response EnCana.AESO-15(c)



The Board is in agreement with the AESO that the first three criteria should be given the most weight when evaluating a proposed rate design. The Board notes that item (i) from the Bonbright principles listed above would be satisfied by the majority of the proposed rate designs, that is, all rate designs would, on a forecast basis, recover the applied for AESO revenue requirement. The lone exception was the proposal submitted by the Cities which contained a point of delivery (POD) demand charge which would not be sufficient to recover the AESO’s revenue requirement. With respect to item (ii) above, the Board considers that appropriate price signals typically will be sent when costs are being recovered in the matter in which they are caused, that is, demand related costs are recovered through a demand charge, energy related costs are recovered through an energy charge, and fixed costs are recovered through a fixed charge. The Board notes that the AESO also appears to endorse this principle, as reflected in a statement from Section 4.2 of their original application that “The AESO does recognize, however, that rate design should generally reflect cost causation, and expects that the results of the Cost Causation Study will be more fully reflected in future tariff applications”. With respect to item (iii) above, the Board considers that by adhering to the principle of cost causation, that inter-customer subsidies are kept to a minimum, if not eliminated entirely. For example, if certain costs are identified as fixed following a cost of service study, recovery of these costs through either a demand or energy charge will result in inter-customer subsidies. While the proposed AESO rate design does not include a fixed charge, the Board notes that the AESO indicated in testimony that they “…were not opposed to a customer charge”.25 With respect to item (iv) above, the Board has also historically given the concept of rate stability (commonly also referred to as rate shock or rate gradualism) significant weight. The Board notes that the AESO submitted that factors other than cost causation need to be given consideration:

Again drawing from Principles of Public Utility Rates by Bonbright et al (pp. 391), the principle of cost causation or “service at cost” means “the rates for any given class of service…should cover the costs of supplying that class. And so the rates charged to any single customer within that class should cover the costs of supplying this one customer.” To apply the cost causation principle, costs should first be classified to the greatest extent possible in accordance with the relevant cost drivers. The classified costs should then be allocated to rate classes and charged to individual customers in accordance with the cost classification. As Bonbright et al note, however, “no such simple identification of reasonable rates with rates measured by costs of service is attainable.” Reasons for deviations from a cost causation standard include excessive complexity of cost relationships, differences between incremental costs and embedded costs, and problems of joint and common costs. Cost causation principles cannot therefore be mechanically applied without consideration of other considerations affecting rate design.26

25 1T, p206-207 26 EnCana-AESO-15(e)



To conclude, with regard to the rate design principles discussed above, the Board considers that cost causation must be afforded the most weight in attempting to balance these sometimes competing principles when evaluating a proposed rate design. That is, in reviewing a proposed rate design, the Board finds that it is critical that the rate design proposed ensures that a customer that causes a cost must be prepared to pay that cost. The principle of rate shock, which can conflict with this cost causation principle, must take a secondary consideration to cost causation in arriving at an appropriate rate design. The balance of the criteria can usually be seen as complimentary to cost causation. On balance, if rates reflect causation, barring unusual regulatory events such as regulatory lag or a dramatic change in cost structure, there should be little need to be concerned about the principles of rate shock and gradualism. The Board has considered all of these factors in arriving at its preferred classification of costs and rate design, as contained in sections 5.3, 5.4 and 5.5 of this Decision. 5.3 Transmission Wires Cost Causation Study (TCCS) The AESO filed a cost of service study in response to Direction 21 contained in Decision 2001-32. The TCCS covered the wires portion of transmission costs only and a summary of the study results was produced at pages 4-6 of Section 4 of the Application. The TCCS investigated transmission wires costs and included an analysis of net book value data by transmission facility from the four major transmission facility owners in Alberta, namely, AltaLink, ATCO Electric, Enmax, and EPCOR. The study assessed, or “sub-functionalized”, transmission wires costs to bulk system, local system, and POD (including radial lines exclusively used by a single POD) functions based on three approaches: voltage level, economics, and volume-distance. The study’s final recommendation was functionalization based on the average of the three methods, these being voltage level, economics and MW-kM. The three methods are described in detail in the Application.27 The TCCS also classified costs as demand-related, usage-related, or customer-related, based on zero intercept and minimum system approaches to determine the principal drivers of costs within each function. The TCCS results were summarized in Tables 4.2.1 and 4.2.228 of the Application and are reproduced below:

Table 4.2.1 Functionalized and Classified Transmission Wires Costs, $ 000 000 Classification

Function Total Demand Usage Customer Bulk System $144.6 $117.9 $ 26.7 $ - Local System 60.2 49.7 10.5 - POD 147.8 63.7 1.0 83.1 Total $352.6 $231.2 $ 38.3 $ 83.1 Note: Totals may not add due to rounding

For rate design purposes, the functionalized and classified wires costs are generally converted to percentages of total costs, as provided in Table 4.2.2. 27 Appendix B, pages 13-32 of the Wires Cost of Service Study or TCCS 28 Section 4, P. 5 of the Application



Table 4.2.2 Functionalized and Classified Transmission Wires Costs (“Pure”), % of Total Classification

Function Total Demand Usage Customer Bulk System 41.0% 33.4% 7.6% - Local System 17.1% 14.1% 3.0% - POD 41.9% 18.1% 0.3% 23.6% Total 100.0% 65.6% 10.9% 23.6% Note: Totals may not add due to rounding

For comparison, the AESO noted the current AESO DTS rate was based on transmission wires costs classified 60% as demand-related, 40% as usage-related, and 0% as customer-related. Dr. Rosenberg, in evidence filed on behalf of the ADC, was generally supportive of the TCCS but expressed reservations regarding the minimum system analysis that PSTI used to support its recommended classification of transmission wires costs into demand and energy components. Specifically, Dr. Rosenberg stated the minimum system approach led to an overstatement of the energy portion of the wires costs. Apart from this concern, Dr. Rosenberg indicated that other aspects of the PSTI study reasonably adhered to the tenets of cost causation. Therefore, while not endorsing the minimum system component of PSTI’s analysis, Dr. Rosenberg considered it was reasonable to accept the results of the study for the purpose of designing DTS rates in this case. IPCAA submitted evidence prepared by Drazen Consulting. IPCAA noted that the TCCS had not attempted to allocate the costs among various classes of service and stated that the purpose of defining rate classes was to recognize differences in costs that should be appropriately recognized between groups of customers. Absent this consideration, IPCAA considered the usefulness of the TCCS to be limited. IPCAA suggested some insight into differences in behaviour that give rise to cost incurrence may have been useful to examine the possible need to distinguish cost responsibility among sub-groups of AESO customers. IPCAA also noted that the study claimed that maximum stress upon the system did not coincide with system peak. IPCAA disagreed with this finding on the basis that this claim was based upon an examination of very few of the bulk lines in the Province. Both IPCAA and EnCana claimed that POD costs may have been overstated in the functionalization step due to the use of Net Book Value (NBV) in the analysis. They maintained that, as POD costs were of a more recent vintage and as no major new bulk lines had been constructed for several years, the use of NBV would tend to distort the results of the study, causing POD costs to be more heavily weighted. FIRM concurred with this latter claim and suggested that replacement costs new (RCN) be used rather than NBV. EnCana also claimed that functionalization of wires costs on the basis of voltage was flawed as it was inconsistent with the AESO’s approach to planning and that some of the lower voltage lines still in use may have originally been built to serve the bulk function. EnCana suggested the findings of the study should be rejected and that the Board should instead rely on the functionalization proposed by the AESO in the Application. In addition to its comments respecting the use of RCN, FIRM also suggested that high side switches and bus work be functionalized as local costs rather than POD related costs, noting the



testimony of Mr. Reimer to that effect.29 The Board notes, however, Mr. Reimer stated that the cost information received from the utilities did not contain sufficient detail to allow for the detailed breakdown suggested by FIRM. TCE expressed concern over the amount AESO proposed to use as the Regulated Generation Unit Connection Costs (RGUCC). The Board acknowledges the above suggestions and concerns of the parties and will address them in more detail below. The Board notes, however, that the TCCS was the only cost of service study filed in this process. Furthermore, the Board notes that no party, with the exception of EnCana, has questioned that the study is directionally incorrect or suggested that it be ignored by the Board. Indeed, both IPCAA and ADC have used the study as evidence to bolster their arguments for a higher demand related component in the final rate design. The Board considers the TCCS to be an excellent first step and commends the AESO and Mr. Reimer for their initiative and effort in this regard. The Board will rely upon the results of the study in the development of its approved rate design. 5.3.1 Functionalization of Costs As noted above, the study assessed, or “sub-functionalized”, transmission wires costs to bulk system, local system, and POD (including radial lines exclusively used by a single POD) functions based on three approaches: voltage level, economics, and volume-distance. The study’s final recommendation was functionalization based on the average of the three methods. The parties raised some concerns with the functionalization of costs but, in the Board’s view, appeared to accept the study as reasonable. In the evidence of Dr. Rosenberg,30 the ADC stated the following:

PSTI considered three different approaches to determine the transmission wires functional categories: 1) voltage level, 2) economics and 3) MW-km. The three methods provide results that are somewhat similar, particularly for the voltage level and MW-km approaches. The POD function is the same in all three approaches. The variation occurs between bulk and local system. According to PSTI, all three methods have strengths and weakness. Since this type of study is relatively new, PSTI recommended that functionalization be based on the average results of the three methods. The resulting functionalization is 45.7% bulk system, 15.7% local system and 38.6% point of delivery. I support the proposed functionalization of the transmission system as reasonable.

IPCAA noted that the TCCS used depreciated historical book costs and stated the relative weighting of the cost of various functions will differ whether they are based on current costs or depreciated original cost. IPCAA stated that no major transmission has been built in Alberta in many years. This, combined with the addition of PODs as load has continued to grow, means that POD costs were likely more heavily weighted in the present analysis than would be the case if all assets were of similar vintage. Both EnCana and FIRM supported IPCAA’s claim. In its reply, the AESO stated: 29 T241, L. 2 30 Rosenberg Evidence, page 21



Examining the depreciation evidence filed in AltaLink’s 2004-2007 GTA as referenced by EnCana, one finds the following information for AltaLink’s two largest asset accounts: Substation Facilities: Transformers and Regulators

Average Service Life (Survivor Curve) 38 years Composite Remaining Life 24.2 years

Transmission Plant (Lines): Transmission Facilities

Average Service Life (Survivor Curve) 42 years Composite Remaining Life 23.0 years

The AESO submits that these two accounts demonstrate that both substation and line facilities have similar lives and are of comparable vintage, and any resulting variance of the approximately 50% of TFO costs represented by depreciation and operating and maintenance expense would not be substantive enough to lead to rejection of the Transmission Cost Causation Study as recommended by EnCana.31

The Board notes that, while the amount of dollars related to the bulk system may increase in the future, and therefore the percentage of costs allocated to bulk system costs will increase, this will not, however, decrease the absolute dollars allocated to POD costs. Moreover, it is NBV which drives the return, tax and depreciation calculations of the TFO revenue requirements. As these items comprise the bulk of the revenue requirement of the TFOs, the Board considers NBV to be an appropriate basis upon which to base the functionalization of costs. For all of the above reasons, the Board does not share the concern of IPCAA and EnCana. FIRM and EnCana submitted that the use of voltage level to differentiate between bulk and local wires may not be accurate since older, low voltage lines may have originally been constructed to serve as bulk lines but would now be classified as local lines. This, they argued, could distort the amounts allocated to each function, lowering bulk costs and raising local related wires costs. EnCana stated that this approach was not consistent with the AESO’s planning, noting that 138kv and 240kv lines were often substitute technical options for the same transmission need. The Board notes that three different approaches were used to functionalize costs and Mr. Reimer described the three approaches in detail at pages 20 to 33 of the TCCS. In the Board’s view, Mr. Reimer was very direct and candid in describing the strengths and weaknesses of the approaches. In particular, Mr. Reimer stated the following:

The three options provide different views of how transmission property can be functionalized in an objective way. Subjective functionalization was rejected because the results were not repeatable, and there was no assurance that a reasonable group of experts could come to an agreement with respect to functionalization of transmission property. The three methods provide results that are somewhat similar. The POD definition does not change and the functionalization of POD property remains stable. The variation occurs as to the distinction between Bulk System and Local System. All three methods have strengths and weaknesses. We consider that the MW-kM method is the strongest because it most closely aligns the purpose of transmission facilities to

31 AESO Reply Argument page 12.



their functional category. Since this type of study is relatively new, we recommend that the functionalization be based on the average results of the three methods.32

The Board considers that the averaging of the three different approaches provides sufficient balance to the findings of the TCCS. Finally, the Board notes that TCE expressed concern with the amount the AESO proposed to allocate to RGUCC claiming it was too high and was just a placeholder as per Decision U97065. In reply, the AESO acknowledged that although the RGUCC costs were established as a placeholder in Decision U97065, additional evidence was submitted during EAL’s (ESBI Alberta Ltd.)1999-2000 GTA proceeding, resulting in the following conclusion in Decision 2000-1 (p. 119):

Although Mr. Crowe noted the shortcomings and possible inaccuracies of his study, the Board accepts his results as confirming the reasonableness of the $43.9 million deemed by the Board to be generation connection costs for existing generators.

The AESO submitted that the EUB’s acceptance removed the “placeholder” nature of the RGUCC and provided a basis for continuing it as determined in Decision 2000-1. The Board agrees. The Board, having addressed the concerns of the parties with respect to the functionalization proposed in the TCCS, accepts the findings of the TCCS as reasonable and will rely upon them in its final approved rate design. 5.3.2 Classification of Costs The TCCS used a minimum system approach to classify bulk and local wires costs and a zero intercept approach to classify POD related costs. The TCCS also noted that a complicating factor in classifying the costs of the bulk system was the fact that the time of maximum stress on the bulk system did not coincide with peak load conditions. The TCCS proposal for the classification of costs is detailed at pages 34-45 of the TCCS. ADC was critical of the use of the minimum system approach for bulk and local wires costs. ADC claimed that such an approach was unorthodox and was generally used to classify distribution costs between demand and customer-related components. ADC noted that system investment was lumpy and the lead time for transmission projects was frequently much longer than for generation projects. ADC maintained that the fact that the transmission grid may be configured to exceed the system’s minimum requirements does not imply that the excess transmission investment was constructed to minimize energy costs. IPCAA was also critical of the TCCS use of a minimum system analysis. IPCAA claimed that there was no evidence that past practice was to increase conductor size to reduce line losses, that conductor optimization or size could not be generalized and that it was difficult to generalize about loss savings given that losses varied with the load on a line.

32 TCCS, page 33



IPCAA was also critical of the TCCS for attempting to define demand in terms of coincident load at maximum system stress (CLMS), noting that the TCCS only reviewed two bulk lines and that CLMS included significant opportunity transactions.33 IPCAA noted that Mr. Reimer himself stated:

A. MR. REIMER: No. I think generally I would expect peak stress on the Bulk System to be more coincident to the system peak load than what was found, in this case, on the north-south corridor:34

IPCAA appeared to agree with the TCCS that a portion of POD costs could be classified as customer-related and in their rate design proposal have advocated the implementation of a customer charge. EnCana supported IPCAA’s criticism of the TCCS, stating that there was no evidence that the minimum system approach had been used in any other jurisdiction. Specifically EnCana submitted that PSTI's use of the minimum system approach was inappropriate because it did not attempt to identify the causes behind transmission expansion. Instead, it only reflected the capacity-optimization decisions once a primary ‘need’ exists. In EnCana’s view, the driver of the primary ‘need’ is the central question that must be addressed in any sound cost causation study. The Board agrees that the use of a minimum system analysis may be somewhat unorthodox, as described by ADC. However, the Board notes the following passages from the TCCS:35

The nature of cost causation for transmission service is an evolving science. The cost of transmission service within the context of the vertically integrated structure was small in comparison to total cost and therefore transmission costs were not normally the focus of attention. … Performing a Cost of Service Study on transmission alone is not a common practice and therefore, there is no one common or standardized method for conducting such a study.

The Board notes that the contentious point of the minimum system analysis is that it maintains embedded costs are incurred to optimize losses. In its reply argument the AESO stated the following:36

ADC stated (ADC Argument, p. 19) that “the only contentious part of the study was the use of the minimum size method to determine that 11 percent of the costs were energy related.” IPCAA argued (IPCAA Argument, p. 8-9) that the Transmission Cost Causation Study did not provide any evidence that embedded costs were incurred to optimize losses. In fact, the Study contained the following information: Since electric transmission system costs are capital intensive, decisions made at the planning stage drive costs over the life of the transmission facilities. Therefore, understanding the transmission planning process is crucial to understanding cost causation for a transmission system. (p. 8)

33 IPCAA argument, page 13 34 Transcript Volume 1, page 223 lines 10 to 14. 35 TCCS. page 3 36 AESO reply, page 15



The nature of a transmission facility is such that the facility is sized to meet the forecast demand, and a conductor optimization study is typically performed to determine the optimum conductor size to optimize losses. (p. 36) The cost of a substation was assessed with a normal efficiency transformer, and a high efficiency transformer that may be suitable for a high load factor customer. (p. 43) These excerpts indicate that planners do study the efficient expansion of the transmission system, and that there are capital costs associated with energy efficiency in both conductors and transformers. However, Mr. Reimer described (T0834) the difficulty in recreating history to determine precisely what embedded costs would have been associated with energy efficiency. Given these challenges, a simplified approach was taken in the Transmission Cost Causation Study to assess costs associated with energy efficiency. The AESO submits that costs are incurred to optimize losses on the transmission system…

Parties also questioned the use of CLMS to moderate the demand charge otherwise called for. With respect to this matter, the Board notes that the TCCS appears to have studied only two of many bulk lines in its analysis. IPCAA has argued that one of the two lines studied, the Edmonton-Calgary line, had significant loading caused by opportunity service at the time of CLMS. Indeed, the Board observes that Mr. Reimer, as referenced above, has acknowledged that CLMS may be expected to be more coincident with system peak. As such, the discount that Mr. Reimer proposes in demand related charges may not be fully justified. The Board expects that, in future studies, the AESO will conduct a more thorough review of all those lines comprising the bulk system. This should give a more accurate indication as to the exact portion of costs that are energy related. However, the Board also considers that a reasonable portion of TFO costs are related to O&M and that a material percentage of these may be energy related. Unfortunately, the impact of this factor does not appear to have been researched in this current study and therefore the Board cannot draw a firm conclusion respecting its impacts on the demand charge. Nonetheless, based upon the percentage that O&M expenses comprise of a TFO’s revenue requirement,37 the Board considers that such an analysis would support a reasonable classification of costs as energy related. The Board expects the AESO to address these issues in future cost of service studies. The Board also notes the following from the TCCS:38

While transmission planning models consider one point in time, transmission planning criteria are based on experience and judgment to ensure reliable operations year round, and planners will optimize conductor size in order to minimize the total cost of wires and losses. The transmission planning process is often used as justification for classification of all wires costs by demand, because transmission planners consider demand under various scenarios. In the event that transmission planning criteria are violated, the transmission system is upgraded to accommodate the forecast demand. However, transmission planning criteria are based on experience and judgment, and therefore, it is too simplistic to classify transmission costs as completely demand related.

37 AltaLink 2004-2007 GTA Application 38 TCCS, page 34



Given the above, the Board is prepared to accept that some portion of embedded wires costs are energy related. The Board also notes that preparing a cost of service study for transmission on a stand alone basis is a relatively new and unique process. The Board acknowledges the difficulties faced by Mr. Reimer in preparing his analysis and in the circumstances the Board considers the TCCS to be a good first step and is willing to accept its recommendations in the Board’s approved rate design. 5.4 Ancillary Services Cost of Service Study In response to Directions 10 and 11 of Decision 2001-32, the AESO filed an Ancillary Services Cost of Service Study. The study was prepared by Mr. Randy Stubbings of Envision Consulting and was summarized at pages 11-15, Section 4 of the Application. The AESO’s proposed classification was summarized in Table 4.3.1 of the Application and is reproduced below. The AESO explained the results of the study and their proposal as follows:39

Ancillary services costs to the AESO can also be viewed as a function of payments to ancillary service providers, and can be classified for rate design purposes as demand-related or usage-related. The costs could then be recovered through tariffs as fixed or variable charges, in accordance with the classification of the ancillary service payments. Basing rate design for ancillary services solely on alignment with payments to ancillary services providers may not always accord with the cost classification set out in the AS Cost Study, as cost causation is only one of several rate design criteria. In particular, the AESO is proposing ancillary services rates that also consider rate stability, simplicity of understanding, and economy of billing. In Decision 2001-32, the EUB also noted “that the first step to self-provision [of ancillary services] is to unbundle the various system support services in the TA’s tariff” (p. 41) and provided Direction 11 to “include rate proposals for unbundling SSS and proposals for customer self-supply of SSS” (p. 59). Based on the AS Cost Study and rate design considerations, the AESO proposes to unbundle certain ancillary services. The AESO recognizes that each of the many individual ancillary services (as detailed in the AS Cost Study) could be identified separately in the rate schedule, but considers such detailed unbundling would be premature and would unnecessarily complicate billing during the time that the market for such services is developing. For example, the AS Cost Study concludes that the cost of regulating reserves should be classified in accordance with customers’ ranges of demand over a given period. Rates designed on this basis would degrade rate stability on an individual customer basis, and would also increase billing costs as extensive information system changes to the billing and metering systems would be required to support the resulting tariffs. Accordingly, the AESO has unbundled ancillary services into three separate and distinct tariff charges categorized by separate cost recovery approaches:

a) operating reserves charge, structured as a usage charge which varies as a percentage of pool price, averaged over all hours;

b) voltage control charge, structured as a flat (non-varying) usage charge; and

c) other system support services charge, structured as a demand charge.

39 Application, Section 4, pages 11-12



Table 4.3.1 Proposed Ancillary Services Charges and Classification Ancillary Service Current Classification Proposed Classification Component MW MWh % of PP MW MWh % of PP Operating Reserves Charge Operating Reserves - - 100% - - 100% Generator RAS - - 100% - - 100% Black Start - - 100% - - 100% Voltage Control Charge Transmission Must Run - - 100% - 100% - Other System Support Services Charge Under Frequency Mitigation - - 100% 100% - - Poplar Hill 100% - - 100% - - ILRAS (see note) 60% 40% - 46.6% 53.4% - Notes: MW indicates classification as demand MWh indicates classification as flat (non-varying) usage % of PP indicates classification as usage varying as percentage of pool price Changes in classification are indicated in bold in the table Classification of ILRAS changes to reflect the change in classification of wires costs The MWh component of ILRAS is recovered in the DTS rate schedule as part of the DTS Interconnection Charge, to

avoid a small $/MWh component in the OSS Services Charge ILRAS Interruptible Load Remedial Action Scheme

5.4.1 Classification of Ancillary Services The only party to submit any comments with respect to the AESO’s proposal was FIRM. FIRM maintained that TMR costs should be allocated on a basis more reflective of cost causation and recommended that the AESO rate design for the TMR component of voltage control reflect the 1:2 ratio of TMR costs for DTS-MWH on-peak and off-peak charges. FIRM acknowledged such a muted price signal would not significantly affect customer consumption behavior but claimed it would better reflect cost causation. In reply the AESO submitted that if a price signal is so muted that it will not affect customer behaviour, then there is little point in providing such a signal. If such a unique bill charge will vary by so little compared to an all-hours average charge and will seem illogical to many customers (as explained by Mr. Martin at T0657-58), then the AESO submitted there was no justification to warrant its implementation. The Board agrees with the AESO and approves the recovery of TMR costs on a flat usage basis. Consistent with the Board’s determinations with respect to classification of wires costs, the costs for ILRAS should be classified as 80% demand and 20% energy. The demand portion should be allocated on the same basis as the bulk wires. 5.5 Demand Transmission Service Rate Design

5.5.1 Unbundling The AESO has stated that it considers the level of unbundling proposed in the Application to be adequate and any further steps in this regard should be deferred until the 2007 tariff. The AESO stated that it did not consider a bill containing seven to nine distinct charges to be simple.



Both IPCAA and ADC supported unbundling. IPCAA maintained that unbundling would result in a tariff where charges are better aligned with the various cost components and cost drivers. Both IPCAA and ADC pointed out that unbundling would allow for different billing determinants. The Board does not agree with the AESO. The Board considers that unbundling, as recommended in the TCCS report, would allow for rates that are more reflective of cost causation, more visible and capable of sending more appropriate price signals to customers. With respect to the concern raised by the AESO that such a bill would be too complex for its customers, the Board considers the customers of the AESO to be few in number, sophisticated in nature, and well able to understand and respond to such a bill. The Board therefore directs the AESO, in its refiling, to unbundle the wires portion of the DTS rate into bulk, local and POD segments. The Board notes this is necessary to facilitate the cost allocation decided upon below. 5.5.2 Classification of Costs The AESO’s proposal for classification of wires costs was originally presented in the Application.40 The AESO submission proposed three adjustments to the cost results of the TCCS. First, the AESO reduced the demand weighting to reflect billing demand non-coincidence with the point of system maximum stress. Second, the AESO eliminated the customer charge amount and added it back to demand. Third, and most significantly, the AESO deducted the current STS wires revenue from demand and re-classified it as energy related. The AESO acknowledged that its proposal did not meet the goal of cost causation but stated that it planned further consultation in 2007 and other rate design considerations may affect the rate design ultimately developed in 2007.41 The AESO also maintained that phasing in the STS wires revenues into the DTS rate on an energy basis would maintain customer neutrality and would avoid undue rate shock to low load, low load factor customers. The AESO was largely supported in its proposed rate design by FIRM and EnCana. EnCana supported the unbundling proposed in the TCCS but also supported the classification of the STS wires costs as energy related. The resultant demand/energy split is approximately the same. Proponents of the AESO proposal appear to support it for three main reasons:

1. Gradualism or rate shock – The parties state that low load, low load factor customers will see huge rate increases and maintain that these should be tempered. All agree this can be accomplished by classifying the STS wires amount as energy related. This would also achieve customer neutrality to the phase out of the STS charge.

2. Transmission Regulation – Parties assert that the regulation requires classification of STS charges as energy related, as a means to ensure revenue neutrality.

3. Decision 2000-1 – Parties submit that the Board’s determination in Decision 2000-1 to classify all STS wires charges as energy was based upon cost causation.

40 Application, Section 4, pages 7-9 41 Application, Section 4, page 9



The Board has noted in the previous section on rate design principles that it considers cost causation to be the most important principle and the Board is in agreement with ADC and IPCAA that rates should reflect this principle to the greatest extent possible. With respect to gradualism or rate shock concerns, the Board notes that the AESO has stated that DTS rates will rise by 66% in total, largely due to the legislative requirement that load pay for all wires costs. Regardless of the rate design chosen, DTS customers will see significant increases in their AESO billings. The Board points out, however, that this relates to AESO billings only. In the past when the Board has considered rate shock, the Board has considered the effect an increase will have on a customer’s total bill. The Board continues to believe that this is the most appropriate manner in which to assess rate design proposals. Only this approach allows the Board to keep bill impact in true perspective. The Board notes that, in information response ADC-AESO-012(c), the AESO provided the impact upon a customer’s total bill as a result of their proposed rate design. In response to an undertaking requested by the Board42, the AESO provided the effect upon a customer’s bill when demand factors of 60, 70 and 80% were used. Exhibit 030-126 revealed that a demand factor of 80% resulted in an 8% increase in costs, when commodity charges were included. The Board does not consider this to be unreasonable. The Board did not request the AESO to factor in the effect of allocating some of the demand charge to a customer charge. The Board has prepared such a spreadsheet and it is attached as Appendix A.43 As can be seen in Appendix A, when considering the effect upon a low load factor customer of the increase in DTS rates only, the addition of a customer charge, including commodity charges, results in an increase of approximately 47%. This could be considered significant. As noted above, the Board considers that it must evaluate the effect that a change in rate design will have upon a customer’s total bill. The Board notes that, in response to an undertaking requested by the Cities, Exhibit 030-022, the AESO acknowledged that all 17 of the low load factor customers identified in response to IR IPCAA-AESO-23(a) are generators. The Board considers it appropriate to account for the drop in the STS portion of their AESO billings that these customers will receive as a result of the shift in costs to load. The Board has prepared such an analysis and it is also attached as part of Appendix A.44 The result clearly indicates that, when the drop in STS billings is factored in, these low load factor customers actually experience a decrease in total billings. In the end, therefore, when considering the total effect upon low load factor customers of an increase in DTS rates and decreases in STS rates, it is clear to the Board from the evidence that the rate shock referenced is simply not significant. It does not justify a failure to move to more cost based rates. Indeed, when the reduction of STS charges is considered, customers may actually see decreases in their total AESO billings. With respect to the requirements of the Transmission Regulation, the Board has examined Section 30 of the regulation and concludes that there is no requirement for the Board to pass through STS costs on an energy basis. Section 30 simply requires that costs be just and reasonable. Associated with this issue is the notion of revenue neutrality. The Board notes the 42 Exhibit 030-126 43 Appendix A, sheet titled “DTS only increase” 44 Appendix A, sheets titled “Rate Shock Analysis” and “Rate Shock no STS losses”



evidence Mr. Sullivan presented on behalf of the ADC. This evidence clearly indicates that the energy market may not be as efficient as postulated by the AESO. In the Board’s view there is no evidence to conclude that STS charges in total will be recouped by load, let alone that they can be recouped evenly across all hours. Finally, the Board will address the suggestion that Decision 2000-1 classified STS charges as energy related because it believed that this was in accordance with cost causation. The evidence in that proceeding indicated that EAL (ESBI Alberta Ltd.) originally proposed to recover a significant portion of the STS wires costs on a demand basis. The evidence of the Coalition in that proceeding was that the imposition of a demand charge on generators could lead to an inefficient energy market and have a detrimental effect upon the PPA (Power Purchase Arrangements) auction, which was imminent at that time. Based upon the evidence before it in that proceeding, the Board classified the STS portion of wires costs as energy. This determination was not made on the basis of cost causation but rather as an exception to the principle45. Reallocating all wires costs to load now allows the Board the opportunity to classify such costs in a manner more in keeping with cost causation. The Board concurs with ADC and IPCAA that rates should be more in keeping with cost causation. The Board above has dismissed the parties’ concerns about rate shock or gradualism and the potential complexity resulting from unbundling. The Board in the prior section on rate design principles has determined that most other rate design principles are complimentary to cost causation. The Board considers that wires costs should be classified as 20% energy to be collected evenly over all hours. There should be a full POD customer charge as determined in the TCCS. This should amount to approximately 24% of total costs as per table 24 at page 47 of the TCCS. The balance of wires costs should be collected through two demand charges – one related to the bulk system and the second relating to local system and POD related costs. The Board, as stated above, agrees with the AESO’s proposal and Mr. Reimer’s suggestion that a reduction be made to the demand related portion of the bulk wires to account for the lack of coincidence of system peak with point of maximum stress. The demand charge for local and POD costs should be collected on the basis of non-coincident peak (NCP), including the use of a ratchet, as proposed by the AESO. With respect to the demand charge for bulk wires, the Board notes that ADC and IPCAA have both proposed different alternatives. Both, however, would use some form of coincident peak to allocate this demand charge. The parties advocate this approach on the basis that the bulk system is largely constructed and sized, and costs incurred, to meet the peak load of the system. The Board agrees. ADC has proposed a 12 CP approach that would use a 12 month average of the system peaks and base a customer’s individual charge on their monthly coincidence with the 12 month average.46 IPCAA proposes to use an average of several peak hours to allocate the demand charge.47 While the Board sees a certain degree of academic merit to the IPCAA approach it considers that it may be more complex to administer. The Board considers that both approaches would provide an appropriate price signal to customers. 45 Decision 2000-1, pages 121-123 46 Rosenberg Evidence, page 31 47 IPCAA Argument, page 20



Therefore, the Board directs the AESO to use the 12 CP approach proposed by Dr. Rosenberg. The average of 12 CP should address the seasonality concerns of IPCAA. As noted by IPCAA, however, a reasonable degree of diversity exists on the bulk system and for this reason no ratchet will apply to this demand charge. As a summary of the above findings the AESO, in its refiling, is directed to amend its DTS rate design as follows:

• 20% of all wires costs will be collected on an all hours energy basis • Levy a customer-related POD charge, as suggested in the TCCS • Levy a demand charge on bulk wires utilizing a 12 CP allocator • Levy a demand charge on local and POD related costs utilizing an NCP allocator.

5.5.3 Ratchet The AESO introduced its proposal for a revised ratchet in the Application.48 The AESO proposed to reduce the current 5 year declining ratchet to a 2 year, 90% ratchet. The AESO stated that it was proposing the change in response to concerns expressed by customers. The AESO explained that its proposal for a 90% ratchet could be achieved with only a 1% drop in interconnection revenue and would therefore preserve revenue stability. The AESO maintained that, in the absence of contract-based billing, ratchets are appropriate to recover revenue from customers who may be leaving the system. The revenue is required to balance the financial impacts for the remaining customers who would otherwise bear the full cost of facilities which become under-utilized due to other customer’s actions. The ratchet provided a balance between flexibility for customers and the need to recover any stranded system costs from remaining customers. Interveners made a number of comments with respect to the AESO proposal. TCE argued the ratchet level should be reduced to 66% from the proposed 90% as this would be more in line with Disco levels and it would be fairer. EnCana argued that the 5 year notice period for reduction in service should be reduced to 2 years as well, to be consistent and fair. FIRM argued the opposite view, maintaining that the ratchet should be maintained at the current 5 year level, to be consistent with the 5 year notice period and protect customers from stranded costs. In response to intervener comments, the AESO noted that TCE’s proposed ratchet level of 66% would entail a 10% drop in interconnection revenue. In response to EnCana and FIRM, the AESO noted EnCana stated that with respect to the ratchet provisions in Article 14.2 of the proposed terms and conditions of service “…that two Customers who are similar in all respects will be assessed different penalties based on whether or not notice of termination or reduction has been provided.” The AESO explained if one customer has provided a notice of termination while the other has not, those customers were not “similar in all respects.” As explained at T0161-62, the specific provisions in Article 14.2 were designed to ensure the AESO gets as clear an indication as possible of the customer’s intention with respect to demand on the transmission system. The AESO submitted the ratchet provisions in Article 14.2 should be approved as filed.




The Board agrees with the AESO that the proposed reduction in ratchet term to two years provides a reasonable balance between customer flexibility and revenue stability. The AESO’s proposal is therefore approved, subject to the direction contained above that no ratchet will apply to bulk wires costs. 5.5.4 Standby Tariffs The Application did not contain a specific proposal for a standby rate. The AESO noted that it had commenced discussions with customers with respect to the development of such a rate and suggested that a standby rate may offer some relief to the low load factor customers most impacted by changes to the DTS rate. The AESO proposed to engage in additional customer consultation on rate design immediately after the decision on its 2006 tariff application is issued in preparation for filing its 2007 application. The Board notes that EnCana and TransAlta supported the development of rates for low load factor or standby customers, and were specifically supportive of the discussion of such a rate in consultations proposed by the AESO for its 2007 tariff. ADC and IPCAA also supported the development of such a rate as a means to ameliorate the effect of their DTS rate proposals. The Board agrees with the parties that the development of a standby rate would be appropriate and may offer some flexibility to low load factor customers. However, the Board cautions parties that such customers impose significant costs with respect to the local system and POD costs and therefore, they must remain responsible for those costs. The Board has no specific directions with respect to stand-by rates, however. 5.6 Supply Transmission Service Rate (STS) The Board notes that the AESO did not specifically comment upon the design of the STS rate in Section 4 of the Application nor did any party comment upon it in argument or reply. The Board notes that the Transmission Regulation has had the effect of shifting all wires costs to load. The only significant cost left for supply customers is line losses. This has been appropriately reflected in the design of the STS rate proposed in Section 7 of the Application. The rate is approved as filed. 5.7 Fort Nelson BC Rate The AESO explained its rate proposal respecting its proposed Fort Nelson Demand Service (FDS) Rate as follows:

The AESO has examined the Fort Nelson arrangement in light of its history and current circumstances, and has decided to not re-apply for the approval of the Fort Nelson Settlement. Instead the AESO has determined that the treatment of BC Hydro and Powerex under DTS and STS contracts respectively as set out in the Settlement is inappropriate for the following reasons:

(a) Current DTS and STS rates are intended for service to Alberta customers. BC Hydro and Powerex are not Alberta customers.

(b) The current DTS contract does not appropriately reflect the type of services provided to BC Hydro and Powerex, nor does it reflect the principles set out by



the EUB in Decision E91095 to recover the incremental cost burden to Alberta so that Albertans do not subsidize BC through serving Fort Nelson.

(c) The provision of ancillary services (especially transmission must run, or TMR, services) as well as the treatment of losses has developed well beyond the levels that existed at the time the original Fort Nelson Settlement was entered into in July 2000.

The AESO therefore proposes to terminate the DTS contract with BC Hydro and replace it with a load contract for a specific Fort Nelson Demand Transmission Service (FDS) rate, and to terminate the STS contract with Powerex and replace it with an import opportunity contract under the standard IOS rate The FDS rate is intended to recover the costs associated with the demand services provided to Fort Nelson, while the IOS rate will recover the costs associated with the import services provided.49

The AESO proposes to charge Fort Nelson a customized DTS rate and an Import Opportunity Service (IOS) rate that would include:

(i) the forecast cost to be incurred by ATCO Electric to supply the transmission line to Fort Nelson;

(ii) a transmission must run (TMR) cost that is based upon TMR dispatched from Fort Nelson and standby TMR from Alberta;

(iii) the losses attributable to the Fort Nelson generator; and (iv) the charges to recover general and administrative costs attributable to Fort Nelson.

The largest charge would be the TMR costs which were forecast to be $6 million for 2006. In argument, the AESO continued to maintain that Fort Nelson was not eligible for the postage stamp DTS rate, arguing that it did not fall under Subsection 30(3) of the Electrical Utilities Act (EUA) and that the FDS rate fairly reflected the cost of providing service to Fort Nelson. The AESO also argued that the large increase in costs to Fort Nelson did not constitute rate shock as it would only increase British Columbia Hydro and Power Authority’s (BCH) total costs by 0.25%. In reply, the AESO did not dispute that it had an obligation to serve the Fort Nelson load, but maintained it had a corresponding responsibility to recover the costs of such service. FIRM supported the AESO’s argument. In its intervener evidence, BC Hydro (BCH) strongly opposed the AESO’s proposal, stating that it was discriminatory, unfair and failed to consider value of service. BCH noted that its costs would rise by approximately 2800%, an increase constituting rate shock of a magnitude imposed upon no other DTS customer. BCH maintained that it had historically been treated as an Alberta customer and stated as such it should continue to receive non-discriminatory access to the same postage stamp DTS and STS service as any other Alberta customer, regardless of the estimated individual incremental cost. In argument, BCH stated that the AESO had an obligation to continue to serve Fort Nelson and such service should be provided under the DTS rate. BCH maintained that the AESO had presented no evidence that the EUA allowed it to discriminate against customers such as Fort Nelson due to its location. In the event that Fort Nelson was determined by the Board to not qualify as an Alberta customer eligible for the DTS rate, BCH submitted that service should be 49 Application. Section 4, page 19



provided on an incremental cost basis, which it described as inherently unstable and difficult to calculate. In particular BCH stated50:

As Mr. Stout made clear51, if the AESO wants to ignore BC Hydro’s status as a customer on the basis that the ultimate load is outside Alberta, then, logically, it must look at the total consequence of the service provided to and obtained from the territory it has determined to be foreign. In other words, if it wishes to employ an incremental analysis, it must look at the incremental effect of Fort Nelson generation, as well as Fort Nelson load. If that is done, there can be no doubt that the relative efficiency of the Fort Nelson generation introduces a substantial benefit to the Rainbow Lake area and significantly diminishes the cost of providing transmission must run (“TMR”) within that area of northwest Alberta.

The AESO’s calculation of the costs of serving Fort Nelson load significantly exaggerates the actual incremental cost of serving by inappropriately combining a calculation of some embedded historical costs with a flawed calculation of gross incremental costs of service to serve the Rainbow Lake area.

Specifically, the AESO has included in what it calls incremental costs, wires costs that are not incremental in any normal sense of that word’s use in cost studies.52 As Mr. Stout testified, these costs represent a non-averaged wires cost directly allocated to Fort Nelson but not to any other radial line customer.53 In addition, the AESO has also declared the $455,000 contribution towards fixed costs to be an incremental cost of serving Fort Nelson, and yet admits that such contribution towards fixed costs would simply be reallocated to other Alberta load in the event that Fort Nelson were no longer integrated with the AESO system.54 This contribution, like the wires costs, forms no proper part of an incremental cost study because they are sunk or embedded costs which would remain even if the Fort Nelson load were no longer present. A truly incrementally-based rate would not include these costs.

The Board rejects BCH’s argument that it should continue to receive service under the DTS rate. The Board cannot ignore the obvious – Fort Nelson is not located in Alberta. As such, the Board does not consider that the AESO is obliged to offer the postage stamp service that it is obligated to provide to Alberta customers. Equally, however, the Board considers that the rate charged to BCH for Fort Nelson service must be just and reasonable, in accordance with established regulatory principles. The Board does not consider that the proposed FDS rate conforms to these principles. The Board also believes that the rate charged for Fort Nelson service must be designed in such a manner that it will provide a fair and reasonable template that can be used in determining rates for other inter-provincial service, be it service provided by the AESO to other BC customers or by BCH to customers located in Alberta. The Board does not consider the AESO’s proposal to be either just or reasonable.

50 BCH argument, page 8 51 Transcript Volume 7 at page 1678, line 6 to page 1679, line 16; see also Transcript Volume 7 at page 1719,

line 5 to page 1722, line 22. 52 Transcript Volume 7, page 1682, lines 7-13. 53 Transcript Volume 7, page 1702, line 17 to page 1703 line 13. 54 See Exhibit 02-020 at BCH.AESO-006(a).



The Board notes that the largest single element in the proposed FDS rate is the allocation of TMR costs. The Board agrees with BCH that the AESO has not provided a sufficient basis for this charge. In particular, the Board does not consider that there is sufficient evidence that the AESO has considered the real value of Fort Nelson generation to Alberta customers. The Board also notes the proposed $455,000 charge for contribution to fixed costs. The Board does not consider this charge has been justified on the basis of a reasonable allocation of actual costs. The Board has determined that the following should form the basis for charges to BCH for Fort Nelson services. DTS service charges should include the following:

1. the postage stamp rate for bulk wires costs; 2. the greater of the postage stamp rate for local wires costs or the actual cost of the AE line

providing service to Fort Nelson; 3. the postage stamp rate for the AESO’s own costs and other industry costs; and 4. the postage stamp rates for each of operating reserve charges, voltage control (TMR) and

other system support charges. The Board does not consider it necessary to charge a POD related cost as BCH provides its own facilities. Correspondingly, BCH should not be eligible for the PSC credit in the future as it will not be charged for POD services. The STS service provided to Fort Nelson should continue to be charged at the full postage stamp rate plus a losses charge to be determined by the AESO, in the same manner as it would for an Alberta generator. Both DTS and STS services provided to Fort Nelson should continue to be subject to the usual deferral account treatment, similar to that of any other customer. The Board considers the above will result in just and reasonable charges for service to Fort Nelson. The Board also considers that this provides a reasonable template for the provision of other inter-provincial services as well. The AESO’s proposed tariff treatment of Fort Nelson is denied and the AESO is directed to continue to provide DTS and STS services to Fort Nelson on the basis set out above and the refiling should demonstrate this treatment. 5.8 Export Rates

5.8.1 Firm Export/Import Rates

In Decision 2002-099, the Transmission Administrator’s (TA) Congestion Management Decision, the Board directed the TA to “…further investigate whether a firm import/export service could be offered over the existing B.C. Tie with a level of “firmness” acceptable to prospective import/export customers”. In response to this directive, the AESO submitted that it began contacting its customers active in importing and exporting in the spring and summer of 2004. On September 23, 2004, the AESO published an Alberta Import/Export Tariff discussion paper to broaden consultation with stakeholders. The paper was presented at a stakeholder conference on October 6, 2004 followed by written comments from six stakeholders. Discussion was also held at a December 3, 2004



stakeholder workshop, with a follow-up Directions and Plans discussion paper published on December 9, 2004. The AESO submitted that the key considerations resulting from this examination of firm export and import services were:

• Firm export tariffs would add a new option for participants and may enhance investment opportunities for new supplies. However, at present there appears to be little demand for a firm export option and deferral of further detailed development until after the Wholesale Market Review appears appropriate.

• Deferring development of a firm export tariff will also allow careful examination of issues such that the introduction avoids or minimizes negative impacts on the market.

• Firm import tariffs appear inconsistent with the transmission cost allocation principles in the Transmission Regulation and would disadvantage imports compared to domestic supplies.

As a result of these considerations, the AESO proposed the following in its Application:

(a) Continued development of a firm export tariff with the objective of including such a tariff in the AESO’s 2007 General Tariff Application (expected to be filed in late 2005 or early 2006); and,

(b) No further action to be taken on establishing a firm import tariff at this time.

During the proceeding, a number of parties55 took the position that the AESO was not responding to the Board’s directives from Decision 2002-099 in a timely fashion, and requested that the Board order the AESO to implement firm import/export rates as part of its Decision in this proceeding. The parties further considered that the AESO was ignoring directives from the Transmission Regulation to implement firm import and export rates. TCE presented and testified to evidence in the proceeding concerning a form of firm export service which it submitted that the AESO could implement in a timely fashion. By way of argument, the AESO submitted that TCE’s proposal provided for a different level of firm service than was normally accepted as firm in the utility industry. The AESO further noted that TCE agreed as well under cross56 that its proposal might be considered as a lower level of firm service. The AESO further noted that TCE’s proposal for a deferral account mechanism in support of its proposed firm export service was lacking in detail, and thus TCE’s proposal should be set aside until a full stakeholder process could occur on this proposal. Finally the AESO submitted that the position taken by a number of parties in the proceeding that the AESO was not responding to the urging of industry to develop firm import and export rates had taken it by surprise. The AESO further noted that both IPSAA and ATCO Power had failed to provide comments on its Import/Export discussion paper when given the opportunity. The AESO did submit in argument that, if further stakeholder consultation did identify the urgency suggested by parties in this proceeding, it would proceed to develop a new proposal for import and export tariffs prior to or in conjunction with its 2007 application.

55 See Argument in Chief and Reply Argument of TCE, IPSSA, TAU, ATCO Power. 56 T1919



TCE also took issue with the AESO’s calculation of Available Transfer Capacity (ATC). TCE suggested that the AESO should include all of the Calgary area generation in its calculations. The AESO responded that, while the export market required hourly commitments, the Alberta market required generator response on a minute by minute basis, and suggested that the reliability of the Alberta system could be jeopardized by deeming this generation to be available. The AESO further submitted, by way of exhibit57, that export ATC was to be governed as an AESO rule, per Subsection 20(1) of the EUA, and therefore was not subject to Board ruling. FIRM submitted that WECC definitions of ATC unique to import and export services should be considered in the Alberta market calculation of ATC. FIRM further submitted that the application of a firm DTS rate to export without proper ratchet provisions and investment levels could result in preferential treatment inadvertently being part of an export tariff. FIRM supported the AESO position for further stakeholder consultation in the development of firm import and export tariffs, as well as agreeing with the AESO that its calculation of ATC not include all Calgary area generation. IPCAA submitted that all TFO customers end up paying for TMR costs related to firm export tariffs, and as such, DTS customers would not be kept whole if a firm export tariff were developed. IPCAA further submitted that TCE had not established sufficient urgency that further stakeholder consultation on firm export service should be ignored. IPCAA noted58 TCE’s acknowledgement that not all stakeholders who will be impacted by the development of firm export tariffs had been contacted, and further noted59 TCE’s admission that its firm export tariff proposals were still maturing. IPCAA further considered that the Board should direct the AESO to consult with stakeholders prior to the end of 2005 concerning any changes to the definition of ATC in Southern Alberta. The Board considers that the Transmission Regulation supercedes many of the principles it established in Decision 2002-099. As such, it is not clear to the Board that certain directives concerning import and export rates from that Decision can be still be considered to be in effect. The Board notes that even TCE acknowledged during cross60 that a number of principles from Decision 2002-099 would have to be modified because of the Transmission Regulation, including, for example, changes caused by the shifting of cost recovery from a 50/50 DTS/STS recovery to a 100% recovery from DTS customers. The Board has reviewed Subsection 8(1)(g) of the Transmission Regulation, dealing with the restoration of the inter-tie to its rated capacity. The Board considers that the AESO has an obligation pursuant to the Transmission Regulation to make rules and to take measures to expand or enhance the transmission system in order to restore the path rating of the interconnections however, the regulation does not impose a time frame nor does it dictate the method in which this must be achieved. This provision is not a required matter to be included in the tariff under the regulation. Rather, it is part of the rule making authority conferred on the AESO. The Board therefore does not consider that the AESO is in breach of this section of the regulation should it choose not to pursue the development of import and export tariffs to the extent desired by parties in this proceeding. The Board notes, with encouragement, the fact that the AESO has invited significant stakeholder consultation in this process, as shown by the evidence in this proceeding. 57 Exhibit 30(13) 58 Page 28, IPCAA Argument in Chief 59 Page 29, IPCAA Argument in Chief 60 T1983, lines 14-20.



The Board further considers that TCE’s proposal for firm import and export rates is deficient at this point in time in that the Board considers there to be a potential for cross subsidization to occur due to the lack of detail currently available concerning TCE’s proposal for a TMR deferral account mechanism. Therefore the Board will not require the AESO to include firm import or export rates as part of its 2006 tariff. The Board however, does encourage the AESO to continue the stakeholder discussions with interested parties on a go forward basis towards the potential development of firm import and export rates. With respect to the calculation of ATC, the Board is in agreement with the AESO that this calculation does not fall under the Board’s jurisdiction, but is, instead, subject to AESO rules. The Board will therefore not provide any ruling concerning the AESO’s calculation of ATC, but again urges further consultation with stakeholders. 5.8.2 Generator Remedial Action Scheme (GRAS) The AESO noted in its application that a GRAS is used to restore and maintain power system frequency at acceptable levels. The AESO noted that it was approached by a group of stakeholders interested in increasing export capability during the fourth quarter of 2004. The AESO further noted that as part of these discussions, it and the stakeholder group had evaluated operating practices that might enable additional export opportunities consistent with the requirements of the Transmission Regulation. The AESO noted that one potential action given prominent consideration in its discussions with the stakeholders interested in export capacity expansion was a proposal to re-establish a GRAS similar to the Keephills Remedial Action Scheme that was in place prior to 2000. The AESO submitted that a feasibility analysis of GRAS is currently underway and that the use of GRAS to increase export capability would be explored when this feasibility analysis was complete. ATCO Power submitted that the AESO has an obligation to pursue measures such as GRAS in order to enhance export capability. ATCO Power submitted that the AESO should not be permitted to "kink the hose" by withholding export tariffs and export capacity, thereby stranding surplus generation in Alberta. Further, ATCO Power noted that Subsection 8(1)(g) of the Transmission Regulation requires the AESO to make arrangements for the expansion or enhancement of the transmission system so that, under normal operating conditions, the transmission system interconnections with jurisdictions outside of Alberta can import and export electricity on a continuous basis, at or near the transmission facility's path rating. IPPSA also suggested that a GRAS was required in order to reflect true market conditions. IPPSA submitted that the AESO had GRAS capability at the Keephills PPA, and that GRAS equipment could be installed in a matter of months. As such, IPPSA recommended that the Board should direct the AESO to implement a GRAS as soon as it had completed its technical studies. TCE also submitted that the Keephills GRAS capability should be restored as soon as possible. In its evidence, TCE noted that the Alberta Government Transmission Development Policy paper indicated that the cost of RAS arrangements required to allow the interties to function as designed should be allocated to load.61

61 TCE Evidence (Exhibit 23-010) page 12 of 42, Citing Alberta Government Transmission Development Policy

Paper (Exhibit 30-027), page 9



FIRM noted that as GRAS is associated with exports rather than imports, the costs of GRAS should be recovered completely from firm export loads as well as export opportunity loads to the extent that such loads are responsible for GRAS costs. The Board agrees with parties that GRAS may be pursued by the AESO as part of its strategy to ensure that interconnections with jurisdictions outside Alberta can import and export electricity on a continuous basis at or near the path rating of the interconnections. The Board does not agree, however, that Subsection 8(1)(g) of the Transmission Regulation may be interpreted in a manner that should cause the Board to direct the AESO to re-implement a generator remedial action scheme. The Board considers that direction to the AESO in the Transmission Regulation to restore the capacity of the intertie does not supersede the AESO’s duty to ensure a safe, reliable system. As such, the Board considers that the AESO must be satisfied that system safety and reliability is not compromised by a decision to implement a program such as GRAS. The Board is comforted by the ongoing efforts of the AESO to ensure that GRAS may be implemented reliably before any steps are taken to implement it. In any event, the Board is reluctant within the context of a tariff application proceeding to, in effect, over-ride the AESO’s technical judgement on the measures that the AESO needs to take to fulfill its mandate to ensure the reliable operation of the transmission system. In this regard, the Board expects that the implementation of GRAS would generally be affected through the development of an operating policy and, as such, would fall under the ambit of an AESO rule pursuant to Section 20 of the EUA. Accordingly, the Board notes that concerns about the appropriateness of an AESO operating policy should generally be brought before the Board through the complaint mechanism described in Section 25 of the EUA. In light of the foregoing, therefore, the Board will not direct the AESO to implement a GRAS as part of this Decision. However, the Board does agree with TCE that the Transmission Development Policy clearly indicates that the costs of internal reinforcements and RAS arrangements necessary to allow the interties to operate at their design capacity are to be allocated to load, irrespective of whether the RAS arrangement is export or import related. Accordingly, if the AESO were to enter into a RAS arrangement during the term of the Tariff, the Board would expect that the costs of this arrangement would be allocated to DTS customers. The Board may consider other cost allocation arrangements only after the rated design capability of the existing intertie facilities has been restored. 5.8.3 Opportunity Import and Export Rates The Board notes that the AESO has proposed minor changes to its opportunity import and export rates to accommodate the provisions of the Transmission Regulation that requires DTS customers to pay for 100% of load. The Board notes that no parties commented against the AESO’s proposed modification to these two rates. The Board has reviewed the proposed modifications and considers them to be in compliance with the changes required by the Transmission Regulation as noted above and therefore approves the AESO’s proposed modifications to these rates. The Board directs the AESO to update its proposals accordingly in its refiling, using the values which result from the Board’s recommended rate design, as discussed in section 5.5 of this Decision.



5.9 Primary Service Credit and Finalization of COS Credits The AESO introduced its proposal for the Primary Service Credit (PSC) in the Application.62 Generally, the PSC is to take the place of the Customer Owned Substation (COS) Credit. Additionally, the AESO has proposed the finalization of COS Credits paid on an interim basis. The Board considers that there are three basic criteria that must be satisfied with respect to the approval of COS credits already paid on an interim basis and the applicability of the proposed PSC in the future. They are as follows:

1. The justness or rationale for paying such a credit; 2. The determination of the amount of the credit; and 3. The applicability or eligibility for the credit.

The Board understands the rationale for the payment of the credit is that the credit reflects the fact that DTS customers have paid for the full cost of transformation facilities at their site. As DTS customers, they have signed a contract with the AESO for service and are obligated to pay fixed DTS charges related to their contract capacity. Included in this fixed charge is payment to the AESO for the cost of transformation equipment that the system would usually pay for and provide to the customer. As the customer has already paid for the full cost of transformation equipment at their site, it is not necessary for the system to invest in such facilities. Consequently, if no credit were available to these customers they would be in a position of paying twice for one set of transformation assets – once when the customer installed and paid for the assets, and a second time when paying their fixed DTS charges each month. The Board does not consider it reasonable to compel a customer to pay twice for one set of assets. It follows that a credit should be available to such customers to ensure that they do not pay twice. The Board considers this to be just and reasonable. With respect to establishing the amount of the credit, the AESO has proposed and the Board agrees, that it should be related to the avoided average cost of system investment for providing the level of DTS service contracted for. The Board considers it important for parties to understand that the amount of the credit is not related to the actual cost paid by the individual customer for the assets installed or even what the system would have paid for providing service to a particular customer. The DTS rate is a postage stamp rate which seeks to collect, on an average basis, the total cost of system investment to provide service to all customers. What a customer has expended to acquire its own assets or what the system would have to spend to supply equivalent service could vary widely from customer to customer and from the system postage stamp average. Globally however, the Board would expect there to be some approximate relationship between customer cost and credits paid. The Board notes the comment of the COS Coalition at paragraph 44 of their argument and Table 1 of argument:

As can be seen from Table 1, excluding DAT Customers, there are about an equal number of COS eligible customers with a PV COS Credits / DTS Cost Est. ratio greater than one and less than one (average is 0.98). This analysis suggests that, on average, the COS rate is set appropriately. As discussed with the Chairman, the COS Coalition panel agreed that a certain amount of averaging takes place with the AESO Tariff and that, on




average, the COS (and PSC) rate should provide a general level of neutrality for other AESO customers.

The AESO provided calculations for the COS Credit and the proposed PSC credit.63 The Board continues to accept these approximate calculations as reasonable. The Board notes that the AESO’s calculations are based upon typical configurations the system would invest in to provide DTS service to a customer. This is what the DTS rate is designed to recover. FIRM proposed64 a credit of $200/MW/month. This proposal is based upon actual costs customers have paid for all their transformation requirements, including the generation related requirements of dual use customers. The Board does not consider this to be appropriate. As stated above, this is not the basis of the DTS revenues that are being credited back to the customers. The Board does note, however, that the actual average of the three sample configurations provided by the AESO is $660/MW/month, somewhat less than their proposed credit. The Board considers that this is a more appropriate amount to credit customers to maintain neutrality between self supply and system supply. The Board directs the AESO to use this amount for the calculation of future PSC Credits. The Board is willing to entertain adjustments in the future to reflect changes in costs over time. With respect to eligibility for these credits, the Board considers that any DTS customer that has supplied its own transformation equipment should be eligible. Any DTS customer that has supplied its own facilities and is paying for system provided facilities through the DTS postage stamp rate, is in the position of paying twice for one set of facilities and should be credited. The only exceptions to this general rule are DAT customers. DAT customers do not pay the standard postage stamp rate but rather a customized rate designed to provide economic neutrality to them as between bypassing the system and remaining on the system. DAT customers should still be eligible for the credits but the amount paid should be reviewed on a case by case basis to ensure economic neutrality is maintained. Subject to this caveat, the Board confirms the eligibility of DAT customers for the credits at the approved level as well. The Board also notes the issue of future eligibility for some current dual use customers was raised by the COS Coalition in their evidence. The Board notes the following passage from the AESO reply argument:

The COS Coalition stated (COSC Argument, paragraph 48), “The COS Coalition is prepared to support the AESO’s PSC proposal, with the changes suggested in the COS Coalition Direct Evidence, as an adequate response to the Board’s directions to the AESO concerning the continuation of the COS credit.” The COS Coalition also proposed (paragraph 57) that “The Board could also direct the AESO to calculate the maximum allowable investment under the AESO’s proposed 2006 Contribution Policy and determine whether this investment is greater than the AESO’s derived cost estimate for transformation assets plus any actual TFO investment.” On consideration of the COSC Argument and review of its own evidence, the AESO supports the COS Coalition proposal as providing equitable treatment of existing DTS loads at dual use sites. The AESO agrees that such treatment would meet the intent of the “reduced investment” test applied in section 4.10 of the 2006 Application (section 4, pp. 43-45), namely that “the maximum local investment for the customer load is greater than

63 Application, Section 4, page 40 64 FIRM Argument, pages 60-63



the least cost system to interconnect the load at the employed voltage level” where the least cost system includes transformation assets and local facilities owned by the TFO. The AESO therefore submits that the EUB approve the revised PSC eligibility recommendation of the COS Coalition.

The Board finds that the treatment proposed by the COS Coalition is reasonable. The AESO is directed to amend the wording of its proposed PSC Credit accordingly. Subject to this direction, and the change in the amount of the credit referenced above, the PSC credit is approved. For purposes of calculating and finalizing those COS credits paid on an interim basis to date, however, the Board is willing to approve the $700/MW/month amount, subject to the exception proposed by the AESO. 5.10 Opportunity Service Rates In Section 4 of the Application, the AESO noted that it currently has three opportunity rates available in its tariff. These are:

• DOS (Demand Opportunity Service) 7 Minutes, for service recallable within seven minutes,

• DOS 1 Hour, for service recallable within one hour; and

• DOS Term, for service recallable in advance of non-recallable (firm) service in an emergency.

The AESO noted that only four customers were using these rates and no customers used the DOS 1 hour rate. Consequently the AESO proposed to eliminate this rate. The AESO proposed to continue DOS 7 Minutes and DOS Term at current levels and to include a losses charge as directed by Subsection 22(2) of the Transmission Regulation. The AESO noted that no one opposed the continuation of these rates and submitted they should be approved as filed. In reply, the AESO noted that ADC, EnCana, and TCE recommended the DOS 1 Hour rate remain in place, and not be discontinued as proposed by the AESO. However, neither party provided evidence of any material advantage to customers of the DOS 1 Hour rate compared to the DOS 7 Minutes and DOS Term rates, nor any indication that they (or their members) intended to utilize DOS 1 Hour in the future. The AESO submitted that the simple fact that no customers take service under DOS 1 Hour, while customers do take service under DOS 7 Minutes and DOS Term, is evidence that DOS 1 Hour does not provide advantages compared to DOS 7 Minutes and DOS Term. The AESO therefore submitted that its proposal to discontinue the DOS 1 Hour rate should be approved as filed. AESO noted IPCAA suggested65 opportunity service rates should encourage use in off-peak hours only. The AESO suggested that providing opportunity service to qualified customers, whenever sufficient transmission capacity exists (whether on-peak or off-peak, as specified in the DOS rate schedules), is more appropriate to the nature of opportunity service. The AESO therefore submitted that its DOS rate schedules should be approved as filed.

65 IPCAA evidence, page 27



In argument, EnCana disagreed with the AESO, stating that because the rate was not presently being used was insufficient reason to limit the future choice of customers. EnCana explained opportunity rates provided a reasonable means to increase system usage when it would otherwise be unused. This increased the efficiency of the transmission system and lowered costs to DTS rate customers. From this perspective, it was submitted that the AESO should instead be encouraged to survey the transmission system and customer situations to enhance the number of legitimate opportunities for increased DOS revenue. These will not only encourage a more efficient use of transmission, but it will also promote increased participation, thus facilitating the development of a fair, open and efficient electricity market. ADC agreed with EnCana that the DOS 1 Hour rate should be retained. ADC argued that retention of the rate was consistent with encouraging demand responsive load and that relatively low pool prices may have reduced the incentive to pursue increased production by taking advantage of such rates. While the Board notes that there are currently no customers using the DOS 1 hour rate the Board agrees with the interveners that there may be merit in retaining the availability of the rate. The Board considers that opportunity rates should be reasonably flexible so as to maximize their revenues and consequent contribution to overall costs. The Board also does not consider there to be any material administrative burden to retaining the rates. Therefore the Board directs the AESO to retain the DOS 1 hour rate. The other opportunity rates are approved as filed. 5.11 Rate Riders

5.11.1 Rider B In the Application66, the AESO explained that the Working Capital Deficiency/Surplus Rider was necessary to recover unexpected increases in the AESO’s working capital deficiency or to refund unexpected surpluses of working capital. In reply, the AESO noted that no party had commented upon this Rider proposal and suggested it should be approved as filed. The Board agrees and it is approved as filed. 5.11.2 Rider C

In the Application,67 the AESO explained that the purpose of the Deferral Account Adjustment Rider was to recover or refund all accumulated deferral account balances. In reply, the AESO noted that no party had commented upon this Rider proposal and suggested it should be approved as filed. The Board agrees and it is approved as filed. 5.11.3 Rider E

In the Application68, the AESO explained that effective January 1, 2006, deferral account balances associated with transmission system losses will no longer be recovered or refunded through Rider C, but will be addressed instead through Rider E. Rider E would implement the calibration factor required by the Transmission Regulation, and would include the following characteristics: 66 Section 7, page 30 67 Section 7, page 31 68 Section 4, page 50 and Section 7, page 32



• Rider E would address only the calibration factor related to transmission system losses

and would apply to Rate STS as well as all opportunity rates (DOS 7 Minutes, DOS Term, EOS, and IOS).

• Rider E’s purpose would be “…to adjust loss factors to ensure that the actual cost of losses is reasonably recovered through charges and credits on an annual basis” in accordance with Subsection 21(1) of the Transmission Regulation.

• Rider E would be determined prior to the beginning of each calendar quarter, and would be set at a level that, if applied for the remainder of the calendar year, would result in the full recovery of the actual cost of transmission line losses by the end of the calendar year.

• Rider E would be applied as a calibration factor percentage based on the preceding which would be added to or subtracted from all location-specific loss factors for generators and all opportunity services.

• Rider E would apply on a prospective basis only in accordance with Subsection 21(2) of the Transmission Regulation. However, an annual reconciliation would be filed with the EUB for information purposes only.

• As Rider E will be set in advance based on a forecast year-end balance, there will likely remain some small difference between the anticipated and actual cost of transmission line losses at the end of the year. Any year-end balance will be included in the next year’s Rider E in accordance with Subsection 21(2) of the Transmission Regulation.

Rider E should primarily address variances from forecast of losses volumes. Variances from forecast of pool price should not require Rider E recovery or refund as both the cost of transmission system losses and the recovery (through a percentage of pool price) varies directly with pool price. Establishing Rider E with a purpose of achieving a zero balance at year-end should avoid any seasonal variations that could arise if the rider’s purpose was to achieve a zero balance at the end of the following quarter. In reply, the AESO noted that no party had commented upon this Rider proposal and suggested it should be approved as filed. The Board agrees and it is approved as filed. 6 TERMS AND CONDITIONS – CONTRIBUTION POLICY

6.1 Customer Contribution Policy The AESO proposed a number of major revisions to the customer contribution policy in the 2005-2006 Application. 6.1.1 High Level Policy Principles

The AESO submitted in the Application that the current contribution policy approved in Decision 2001-6 was devised with regard to four major principles, namely:

• The desire to impose an economic siting discipline on customers; • Consistency with the “postage stamp” principle; • Harmonization with the contribution policies of distribution facility owners (Discos);

and • Consistent application of the policy to all load customers.



The AESO submitted that the refinements to the contribution policy proposed in the Application were necessary to achieve these principles and to reduce the need for discretionary classification of project costs. The Board will evaluate the AESO’s proposed changes to the contribution policy in light of these policy principles in the sections that follow. In addition, the Board will also consider other factors in assessing the appropriateness of the AESO’s proposal that have arisen since Decision 2001-6 was released. In particular, the Board will be mindful of the impact that the Transmission Regulation may have on these principles. Provision of Economic Signal(s) The Board notes that Decision 2002-082, in respect of ATCO Electric’s (AE’s) 2002 Investment and Contribution Policy, extensively investigated the principles underlying electric utility contribution/investment policies. In turn, that Decision quoted Decision 2000-1 as follows in order to set out certain basic principles for its disposition of the AE contribution policy:

The Board considers that customer contributions are suitable in circumstances where service to a customer may impose costs on other customers for which they should not be responsible. An appropriate contribution policy therefore provides a suitable balance to an unlimited obligation to serve by imposing economic discipline on siting decisions. It transfers the economic burden of connection of new customers from the utility and its existing customers to the new customer. In other words, it exerts some of the discipline of the utility’s economics on the economic decision-making of the customer. The Board considers that customer contributions should relate only to the local connection costs of the system expansion. The deep system costs of expansion are properly the responsibility of all customers, form part of the utility’s revenue requirement and should be recovered from all customers through rates.

The Board’s views on the underlying purpose of a contribution policy have not changed since Decision 2002-082 was issued. As such, it remains important to the Board that the AESO’s contribution policy should continue to exert an economic discipline on siting decisions by sending price signals reflective of the AESO’s economics to an interconnecting customer. The Board also notes the following finding reflected in Decision 2002-082 (originally derived from Decision 2001-38):

The Board considers that these same observations apply at the distribution level in the case of AE’s investment policy. Achieving a suitable balance to an unlimited obligation to service does not necessarily mean that investment levels should be set as high as possible without placing undue upward pressure on rates. For example, if a technological breakthrough significantly reduced the cost of connecting new customers, it may be appropriate to reduce the level of investment to maintain intergenerational equity. In such circumstances, all generations of customers would benefit from investment toward the same functionality of service, and all customers would benefit from the eventual downward pressure on rates. Conversely, if the Board were persuaded that it was appropriate to adopt a new standard of construction (for example, underground instead of overhead construction), the Board might approve a significant increase in the level of investment, which would eventually result in upward pressure on rates for all customers.



The Board considers that the appropriate maximum level of investment could be affected by factors such as technological advancements and changes in standards of construction. Absent such factors, the Board would generally expect that maintaining a suitable balance to an unlimited obligation to serve would result in investment levels increasing with inflationary pressures, offset by productivity and technological improvements. This would result in different generations of customers benefiting from investment toward the same functionality of service, and would also result in approximately the same economic discipline on different generations of customers.

The Board notes that, while the above noted passage was taken from a decision issued by the Board in respect of ATCO Electric’s contribution investment policy, the principles described therein also apply to the AESO. Accordingly, the Board considers that three aspects of the above noted passage are relevant in considering the disposition of the AESO’s proposed contribution policy. These aspects are:

• Establishing a maximum investment allowance; • Establishing standards for functionality and service characteristics; and • Recognizing the changing nature of the standards for functionality and service.

The Board notes that the above referenced passage does not support a proposition that investment allowances should be set at the maximum amount of incremental revenues generated by the interconnection of a new customer. Rather, the Board has identified its concern that such a proposal may place undue upward pressure on rates. The Board continues to be concerned that setting investment allowances at a level significantly above the expected cost of an interconnection would be inflationary. In particular, the Board is concerned that an excessive investment allowance could provide incentives for customers to pursue higher standards of connection facilities than required, largely on the basis that the cost of the higher standard facilities would not exceed the permitted investment allowance. Accordingly, the Board considers that the incremental revenue generated by an interconnection should only be used as an upper bound but should not be the primary driver of the investment formula. The Board will provide further elaboration on these matters in its discussion of the AESO’s proposed Maximum Investment formula, found in Section 6.1.4 of this Decision. The Board also notes that the passage above from Decision 2002-082 focuses on consideration of the functionality and service characteristics provided by the interconnection facilities rather than on the financial aspects as the principal driver of the contribution policy. Given this focus, investment allowances should be set with regard to the anticipated cost of establishing an interconnection to the AIES (Alberta Interconnected Electrical System) reflecting acceptable standards of functionality/service established by the AESO. The above referenced passage from Decision 2002-082 also recognizes that the standards of functionality and service characteristics may change over time. The Board discusses this issue further in Section 6.1.3.1 of the Decision respecting the AESO’s proposed definition of “AESO Standard Service”. Consistency with Postage Stamp Principle The AESO suggested in the Application that certain aspects of its proposed contribution policy would bring the policy in closer alignment with the “postage stamp principle” outlined in Section 30(3) of the EUA which reads as follows:



s. 30 (3) The rates set out in the tariff

(a) shall not be different for owners of electric distribution systems, customers who are industrial systems or a person who has made an arrangement under section 101(2) as a result of the location of those systems or persons on the transmission system, and

(b) are not unjust or unreasonable simply because they comply

with clause (a). The Board notes that the wording of Subsection 30(3) substantially preserves the postage stamp rates provision from Section 27 of the version of the EUA in effect prior to June 2003, which was worded as follows:

s. 27(2) The rates set out in the tariff

(a) must reflect the prudent costs that are reasonably attributable to each class of system access service provided by the Transmission Administrator, and

(b) must not be different for owners of electric distribution

systems as a result of the location of those systems on the transmission system.

(3) Rates are not unjust or unreasonable simply because they are

prepared taking into account subsection (2)(b). The Board notes that previous Board Decisions in respect of the AESO’s predecessor, EAL,including Decision 2000-1 and Decision 2001-6 examined the manner in which the postage stamp principle should coexist with the use of contribution policies to provide appropriate economic siting signals. In particular, the Board determined in Decision 2001-6 that because the contribution policy proposed by EAL did not have the effect of making the location of an electric distribution system on the transmission system or the geographic location of a POD within Alberta a consideration in how the contribution policy was applied, the contribution policy of EAL complied with the postage stamp requirements of Subsection 27(2)(b). Accordingly, the Board considers that the contribution policy of the AESO’s existing tariff may also be judged to align with the postage stamp principle as described in Subsection 30(3). It did not need to be altered to be brought into compliance. Harmonization of the AESO Contribution Policy with Contribution Policies of Discos The AESO advised that it is seeking to harmonize its contribution policy with those of the other regulated distribution companies in Alberta. The AESO submitted that the form of the maximum local investment function proposed in the Application would provide a better harmonization with the similarly-structured load-based investment policies of most distribution facility owners (Discos). By using an average unit investment allowance that varies with contract term, the maximum local investment allows customers to lower the customer contribution required by contracting for a longer DTS contract term.



The AESO indicated that it hoped its redesign of the maximum investment formula would ensure that approximately 80% of customer interconnection projects would be fully covered by the selected maximum investment limit while 20% of projects would only be partially covered. The AESO noted this “80/20 criteria” was initially adopted in order to preserve intergenerational equity relative to the customer contributions required during the vertically integrated regime that existed prior to the unbundling of the Alberta electricity system that occurred in 2001. The AESO noted that the “80/20 criteria” was accepted by the Board in Decision 2001-6.69 The Board notes that the rationale for seeking to harmonize the contribution policies of the AESO with the Discos was evaluated by the Board in Decision 2001-6. As noted in Decision 2001-6, the harmonization issues under consideration in that proceeding primarily related to the following aspects of the contribution policy:

• Ensuring the appropriate harmonization between the contribution policies of the distribution utilities and the AESO’s predecessor;

• Ensuring that the contribution policy did not disturb proper planning; and • Understanding how the customer contribution policy affects a customer’s decision to

choose to become a “direct” transmission-connected customer versus a distribution-connected or isolated generation customer.

The Board considers that while progress has been made in relation to the last of the harmonization goals noted above, additional improvements could be made. In particular, and as further discussed in Section 6.3.2 of this Decision, the Board considers that the primary focus on Disco/AESO harmonization efforts should be directed towards harmonizing the definitions of “standard facilities” and “optional facilities”. Application of Supply Contribution Principles to Load Contribution Policy The Board notes that the load customer contribution policy proposed in the Application parallels several aspects of the contribution policy for new interconnecting generators as outlined in the Transmission Regulation. The major components of the generator contribution policy are described in Sections 16 and 17 of the Transmission Regulation. Through information requests, the Board sought to clarify the extent to which consistency is required between aspects of the Transmission Regulation’s generator contribution policy and the load contribution policy proposed by the AESO for the Application. The Board notes that, in one of its responses70, the AESO indicated that Subsection 16(4) of the Transmission Regulation had played some part in the formulation of the load policy, namely, the determination of whether a cost arising from an interconnection should be designated as a “system” or a “customer” cost. The AESO noted that whereas Subsections 16(1), 16(2), and 16(3) all refer specifically to the interconnection by the “owner of a generating unit” to the transmission system, Subsection 16(4) of the Transmission Regulation uses the terminology “another person”. The AESO thus considered that the use of “another person” rather than “owner of a generating unit” was intended to imply general application of Subsection 16(4) to both generators and loads.

69 Decision 2001-6, page 70 70 BR-AESO-017



The AESO further noted that, in general, facilities constructed for the same purpose should be classified the same regardless of whether the interconnection is for a generator or a load customer. In the AESO’s view, to do otherwise would be problematic for dual-use interconnections (serving both a generator and a load customer). The AESO did not consider that any other aspects of the Transmission Regulation had influenced its proposed contribution policy for load customers.71 The Board has considered the provisions in Section 16 of the Transmission Regulation and agrees with the AESO that the reference to “another person” rather than “the owner of a generating unit” in Subsection 16(4) of the Transmission Regulation may be interpreted as a reflection of the Government’s intent to apply this provision to any type of customer that wishes to make use of previously constructed interconnection facilities and is not intended to be restricted to generators alone. However, as noted by the AESO, the more specific references to “a generating unit” in the other subsections of Sections 16 and 17 of the Transmission Regulation have the effect of making these requirements mandatory only in respect of interconnecting generating units. Therefore, while the Board is not precluded from adopting the AESO’s proposal to devise a load customer contribution policy that largely parallels the design principles for generator contributions outlined in the Transmission Regulation, the Transmission Regulation does not require the AESO to devise a parallel load customer contribution policy. Whether it is in the public interest to do so is a separate issue that must be determined by the Board. The Board considers that the fundamental difference between the load customer contribution in the AESO’s current tariff and the generator contribution policy relates to the manner in which “system-related” and “customer-related” costs are determined. The existing contribution policy is essentially top-down in nature in the sense that the baseline for the identification of system-related and customer-related costs arises from an evaluation of the facilities currently available or contemplated for addition over the next five years in relation to the AESO’s long term system plan. Under this approach, any additional facilities and costs arising from a new customer’s interconnection are identified as customer-related costs and are charged to the existing customer. In contrast, the generator contribution policy described in the Transmission Regulation may be considered more of a bottom-up approach, in the sense that the generator’s local interconnection facility costs are determined first and deemed to be the customer-related costs associated with the interconnection. Any further residual incremental system enhancement or upgrade costs not fitting the definition of a local interconnection facility cost are deemed to be system-related, and thus excluded from the contribution policy. As further described in the Board’s discussion of the designation of system and customer costs in Section 6.1.2 of this Decision, the Board does not, in general, consider that the generator contribution policy principles outlined in the Transmission Regulation should necessarily be used as the model for establishing the load customer contribution policy unless doing so is supportable under generally accepted principles of rate design. 6.1.2 Designation of System-Related Costs The Board notes that the first step in the application of any contribution/investment policy is to classify costs as either system-related or customer-related. 71 BR-AESO-017



The mechanism to classify costs as system-related or customer-related was set out in Article 9.2 of the existing AESO Tariff’s Terms and Conditions. Article 9.2 reflects the framework established by the Board in Decision 2001-6. Under Article 9.2, the determination of whether a proposed interconnection project would be classified as system-related or customer-related depended on whether the proposed project was radial to the existing transmission system. If a proposed interconnection was radial, new interconnection facility costs were generally designated as customer costs. Alternatively, if all or a portion of a new interconnection project completed a looped configuration in conjunction either with existing transmission system facilities or in conjunction with system upgrades expected to be built within the next 5 years, the looped portion of a new interconnection project was deemed to be a system-related cost. Article 9.2 also allowed for the customer to pay for the cost of advancing any portions to be looped within the subsequent 5 year period. Article 9.3 of the proposed T&Cs in the Application establishes the proposed methodology to designate system and customer-related costs. Although the AESO proposes to preserve the looped vs radial criteria it had established in Article 9.2 of the existing T&Cs, the looped vs radial designation will no longer be the primary determinant of whether a cost was to be designated as system or customer-related. In its place, the AESO has proposed the additional Article 9.3(a), which concentrates on defining the specific types of facilities within a new radial interconnection project that the AESO considers to be customer-related. In conjunction with its proposed focus on typical local interconnection facilities as the basis for identifying customer-related costs, the AESO has also proposed to designate any enhancements to the existing transmission system that may arise as a result of a new customer interconnection to be, by definition, system-related for the purposes of the contribution policy. The AESO contends that its revised criteria for designating system-related and customer-related costs are necessary because the existing process for designating costs may tend to be unpredictable for customers. In particular, the AESO noted that because the AESO exercises some discretion in the case of enhancements, such as protection upgrades, it is possible under the existing T&Cs to designate such costs as either system or customer costs, depending on the AESO’s determination as to who benefits from the interconnection upgrade.72 The AESO provided a conceptual illustration of three basic approaches to the classification of system and customer costs in Figure 6.1.1 of the Application.73 The AESO noted that, while each scenario always classifies local connection costs as customer-related and classifies bulk system costs as system-related, the classification of system enhancements varied between the three alternatives. Of the three alternatives described by Figure 6.1.1, the AESO chose “Alternative 1” (all system enhancements designated as system costs) on the basis that the chosen alternative would provide a high level of predictability and would provide consistency in the treatment of load and generator interconnection projects. The AESO’s proposal to treat system enhancements as system costs for the purposes of the contribution policy was supported by ATCO Electric. Conversely, FIRM opposed the automatic designation of enhancements as system costs.

72 Application, Section 6, page 2 73 Application Section 6, p. 3 of 42



While desirable, the Board does not consider the goal of trying to achieve greater consistency between the generator and load customer contribution policies to be the most important public interest consideration. Accordingly, the Board is not persuaded that consistency with the generator contribution policy should, in and of itself, lead the Board to endorse the AESO’s proposed Alternative 1 in which all costs not specifically identifiable as a local interconnection cost should be deemed as system cost for contribution policy purposes. The Board has difficulty accepting the proposition that decision making as to whether a system enhancement should be designated as a system or a customer cost should be problematic for the AESO. The Board notes that the radial vs looped framework currently in place in the T&Cs was proposed in part because it provided enhanced objectivity and predictability from a customer perspective.74 The Board also notes that the AESO has an explicit obligation under Subsection 4(2) of the Transmission Regulation to identify all transmission facility projects which the AESO proposes to initiate through a needs application within 5 years from the release of each update of its long term transmission system plan. Additionally, in respect of each project so identified, the AESO is required to provide the anticipated implementation schedule for the project. The Board considers that since detailed information must now be provided as required in Subsection 4(2), the AESO should be able to objectively assess whether a cost arising from a new interconnection warrants system or customer cost treatment. With respect to the request of AE that the Board should provide clear directions respecting the classification of system and customer costs, the Board considers that the AESO should approach any situation in which there may be “shades of grey” in this designation exercise, with the position that a debatable interconnection project cost should be presumed initially to be customer-related unless clearly demonstrated otherwise. The Board does not wish to take away the AESO’s discretion under Article 9.11 of its proposed T&Cs to deem costs normally designated as customer costs to be system-related costs in appropriate circumstances. The Board, however, considers that a general stance that system enhancement costs are customer costs unless demonstrated otherwise is consistent with the expectation that the AESO adopt a more proactive stance in respect of its overall system planning and transmission system upgrade responsibilities, as detailed in the Transmission Regulation. 6.1.3 “Standard” and “Optional” Interconnection Facilities

6.1.3.1 AESO Standard Service Definition The T&Cs submitted with the Application include a proposed definition of the facilities that the AESO considers to be the standard facilities that it expects to provide for a new interconnection project. The definition of AESO Standard Facilities from Article 1 of the proposed T&Cs is as follows:

“AESO Standard Facilities” mean the least-cost interconnection facilities which meet good transmission practice including applicable reliability, protection, and operating criteria and standards, and generally consist of a single radial transmission circuit and a single transformer to supply an individual Point of Connection.

74 Decision 2001-6, p. 3 and p. 62



The AESO noted in its Argument that the inclusion of a definition of standard facilities in the Tariff was intended to provide clarity and transparency to a long-standing practice.75 A number of parties addressed the definition of standard facilities in argument, including ATCO Electric, TCE, the Cities of Red Deer and Lethbridge and the FIRM Group. TCE was particularly active respecting this issue, and proposed to define standard service as follows (TCE wording italicized to illustrate their proposed changes):

“AESO Standard Facilities” mean the least-cost interconnection facilities which meet good transmission practice including applicable reliability, protection, and operating criteria and standards, and generally consist of two lines of transmission circuit and two transformers to supply an individual POD for peak loads at or above 15 MVA and to generally consist of a single radial transmission circuit and a single transformer to supply an individual POD for peak loads below 15 MVA.

For reasons further described below, the Board has determined that the definition of “AESO Standard Facilities" as set out in the T&Cs of the Application should be approved as filed by the AESO. The Board has addressed the views of the other parties below. Reliability Obligations Required by Legislation The Board notes that the Transmission Regulation has imposed additional obligations on the AESO to ensure that its reliability standards meet or exceed generally accepted North American reliability standards. The AESO’s obligations in respect of reliability standards are set out in Part 2 of the Transmission Regulation, reproduced in part below:

8(1) In making rules under section 20 of the Act, and in exercising its duties under section 17 of the Act, the ISO must

(a) plan a transmission system that satisfies reliability standards,

unless the ISO decides that to do so would not provide for a safe, reliable or efficient transmission system;

(b) ensure that transmission facilities adhere to reliability

standards;

(c) monitor and ensure overall reliability of the interconnected electric system;

(d) comply with directives of the Board; …

(2) A decision by the ISO under subsection (1)(a) that a reliability

standard would not be safe, reliable or efficient must be filed by the ISO with the Board for approval.

75 AESO Argument, p. 47 of 58



The phrase “reliability standards” as referenced in Section 8 of the Transmission Regulation is defined in Subsection 1(1)(e) of the regulation as follows:

1(1)(e) “reliability standards” means the reliability standards agreements, criteria and directives of the Western Electric Coordinating Council and the North American Reliability Council, or their successor organizations, and reliability standards, agreements, criteria or directives of any similar entity recognized by the ISO;

The above referenced passages of the Transmission Regulation mandate the AESO to adhere to reliability standards that meet or exceed standards adopted by the North American Reliability Council (NERC) and the Western Electric Coordinating Council (WECC). While the Transmission Regulation provides some discretion to the AESO to deviate from specific elements of either the NERC or WECC standards, the AESO faces a reverse onus requirement to prove that compliance with a particular aspect of the NERC and WECC standards would not be safe, reliable or efficient in the Alberta context. The AESO submitted that it adopted both the NERC and WECC Reliability Criteria as the basis for its own Reliability Criteria document.76 The Board notes that no evidence was provided during the Application proceeding to suggest that the AESO Reliability Criteria did not reflect the NERC and WECC Reliability Criteria to the extent required by the Transmission Regulation. As the AESO has not made any application pursuant to Subsection 8(2) of the Transmission Regulation seeking relief from the reliability standards, the Board considers that the obligation on the AESO to maintain these standards remains fully intact. The Board notes that a comprehensive update to the AESO reliability standards was prepared by the AESO (AESO Reliability Criteria) and was circulated for stakeholder comment. The AESO’s Reliability Criteria document was filed in this proceeding by the AESO in response to an information request.77 In addition, a matrix document containing stakeholder comments on the AESO’s Reliability Criteria and the AESO’s responses to these comments was also filed in the Application proceeding.78 The Board finds that the Point of Delivery (POD) Criteria described in Section 4.5 of the AESO Reliability Criteria document reflects the WECC’s determination within its Reliability Criteria that interconnection facilities based on a single radial circuit and single transformer are acceptable in relation to WECC’s standards. Further, it is also notable that the Section 4.5 POD Criteria expressly indicate that there is a risk of firm and opportunity load having to be shed in the event of an outage of the radial interconnection elements. Accordingly, the Board considers that AESO customers contemplating the interconnection of a new load will be aware of the potential for electric service disruption if they choose to rely solely on the facilities described by the POD Criteria. The Board notes that the AESO indicated in its matrix that distribution customers and industrials would be treated the same.79 However, the Board notes that it might be argued that, if a multi-customer POD waiver were to be granted to distribution utilities with the result that distribution utilities could obtain system cost treatment for most or all of the costs of a second

76 Exhibit 02-025-001, p. 1 77 Exhibit 02-025-001, EPCOR-AESO-001 response. 78 Exhibit 02-021-001, CITIES-AESO-010, Attachment A 79 Exhibit 02-021-00 (see AESO “Comment 56”, pp. 23-24)



transformer/second line while an industrial customer could not, this would constitute undue discrimination. The Board considers this concern to be valid. As such, this concern contributed to the Board’s decision to disallow the AESO’s multiple customer POD contribution waiver, as further discussed in Section 6.1.5 of the Decision. Economic Rationale for AESO Standard Facilities Definition The Board notes that certain parties suggested that POD service standards should be higher than a single line/single transformer standard and therefore advocated the adoption of a higher standard on the basis that the AESO has a duty to ensure that an equal quality of service is provided to all customers. The Board notes that it was readily acknowledged by the AESO in the course of the proceeding that the adoption of one-line/one-transformer as the normal standard would not provide a minimally acceptable level of service for some customers. That is, the AESO has made it clear that it accepts that some customers would never consider reliance on an interconnection based solely on AESO Standard Facilities to be acceptable. As noted by the Cities, this implies that a substantial contribution would be required just to achieve a minimum acceptable level of service. The Board does not find that the AESO has an obligation to equalize service levels to the extent advocated by some parties. The Board notes Decision 2001-6 where it held that there is no analogue to the postage stamp rates principle that would mandate the AESO to provide postage stamp service.80 The Board also notes that the notion of designating costs as system or customer-related on the basis of whether a looped or a radial interconnection was built was adopted by the Board in Decision 2001-6 in spite of the fact that certain parties had argued in that proceeding that it would be unfair for customers served by a less reliable radial interconnection to have to pay a contribution while customers who received more reliable looped service paid no contribution.81 The Board considers that the evaluation of a set of reliability criteria, including the POD service level criteria, is influenced by economic considerations. That is, the AESO must consider the extent to which the costs of providing higher standards of facilities justify the increase in benefits to users in the form of increased reliability. In addition, the Board also considers that the manner in which the benefits of increased reliability are distributed amongst the AESO’s customers should also be a significant consideration in how aspects of the reliability criteria, including the AESO Standard Service definition/POD Criteria, are devised. In this regard, the Board notes that the AESO’s decision to adopt within its reliability criteria the WECC practice of excluding radial customer interconnections from the general scope of the AESO Reliability Criteria. This reflects the fact that an outage on a radial interconnection “downstream” of the bulk system will affect the radially connected customer, but should have limited impact, if any, on other AESO customers not served by the radial interconnection. As a consequence, the Board considers that the benefit of increased electric service reliability arising from higher standard and/or redundant interconnection facilities accrues primarily to the radially interconnected customer rather than to AESO customers at large.

80 Decision 2001-6, p.74 81 Decision 2001-6, page 74



Additionally, the Board notes that the need for absolute reliability amongst AESO customers is unlikely to be uniform, since different customers will experience different types and severity of consequences from electric service disruptions. The Board notes that alternative arrangements (such as backup power supplies), other than interconnection facilities may be made to deal with potential service disruptions. As such, the Board considers it to be economically efficient that the contribution policy should provide appropriate economic siting signals which pass along the costs arising from the installation of facilities beyond standard facilities to the specific AESO customer requesting the interconnection. The Board considers that the principal concern that the AESO’s existing customers might have with a minimum standard service definition relates to the possibility that the cost of optional facilities might actually dissuade a customer from making an investment and interconnecting with the system. If this were to occur, existing customers would not enjoy the benefit of being able to transfer a portion of the burden of the AESO’s embedded system costs to a new customer. However, based on evidence available in this proceeding, this is not a substantial concern of the Board at this time. In particular, the Board notes that, while TCE presented analysis in its argument designed to the show the high economic costs that would arise from a prolonged disruption in service82, a corollary of TCE’s analysis is that customers will place a high value on reliability assurance at the time they are considering their initial investment as well. As a result, absent information to the contrary, the Board expects that customers facing substantial optional interconnection facility costs should generally be presumed to be willing to make a decision to invest in providing the minimum level of reliability that their operations require. Analysis of Interconnection Facilities at Existing AESO PODs - Rate Shock Regarding TCE’s submission that the AESO and its predecessors have generally provided a second transformer at system rather than customer expense, the Board does not agree. In arriving at this determination, the Board takes particular note of the AESO’s rebuttal evidence which suggests that a significant number of the second transformers may have been installed because the AESO and/or its predecessors determined that the cost of an interconnection using a configuration with two smaller capacity transformers was more efficient or cost effective than an interconnection devised using a single large capacity transformer. In any event, the Board finds that even if TCE’s interpretation of the statistics was to be accepted, it is clear from the statistics provided during the proceeding that a significant number of PODs greater than 15 MVA are presently served by a single transformer. As such, the Board is concerned that the adoption of TCE’s additions to the proposed AESO Standard Facilities definition could establish a de facto minimum standard for a second transformer in instances where such facilities have not historically been deemed to be warranted.83

82 At p. 44 of its Argument, TCE estimated a that the value of expected energy not served arising from a 7 day

disruption of a 90% load factor 30 MW industrial load would be approximately $54.4 million. 83 The Board is in general agreement with the AESO’s observation at p. 47 of its Argument that a greater

emphasis should be placed on the aspect of the AESO Standard Facilities definition focusing on the “least-cost interconnection facilities which meet good transmission practice including applicable reliability, protection, and operating criteria” and comparatively less on the one-line/one-transformer aspect of the definition. Conversely, however, the Board does not agree with the suggestion of AE the one-line/one-transformer standard is inherently contradictory with good transmission practice and should thus be removed from the decision. That is, notwithstanding that the good transmission practice should govern decision making in specific situations, the Board considers that the one-line / one-transformer standard provides a useful reference point to AESO customers and may appropriately be included in the AESO Standard Facilities definition.



The Board further notes that, to the extent that potential AESO customers are able to assess the costs and benefits associated with higher or lower levels of reliability prior to committing to an investment, such customers will not be harmed and do not experience rate shock in the manner suggested by TCE.84 As such the Board does not agree with TCE’s view that the adoption of the AESO’s proposed Standard Facilities definition constitutes rate shock for new customers. Alignment with Discos Contribution Policies The Board notes that two documents filed during the proceeding received some prominence in some parties’ discussions of the AESO Standard Service These documents are the “Distribution Point-of-Delivery Interconnection Process Guideline – Typical Supply Arrangements”85 (Typical Supply Arrangements Document) and the “Distribution Point-of Delivery Interconnection Process Guideline – Standard of Service”86 (Standard Service Document). The Board understands that these documents were prepared in conjunction with the new Interconnection Redesign Process initiative described in Section 6.3 of the Application. The Board notes that TCE has pointed to the Typical Supply Arrangements Document as being supportive of its contention that, at a breakpoint of approximately 15 MVA, customer interconnections tend to require interconnection facilities beyond a single line/single transformer configuration. TCE also pointed to the Standard Service Document as supporting its view that the determination of standard interconnection facilities should be based on a maximum restoration time standard. The Cities similarly appear to suggest that aspects of the Interconnection Redesign Process documents may be interpreted as defining minimum standards. The Board does not share this view. The Board understands that an over-riding goal of the Interconnection Redesign Process initiative is to streamline and standardize the interconnection process with an eye towards shortening timelines, including the time required to obtain Board approval(s). In this respect, the Board considers that the identification of common aspects of interconnection projects including typical service and facility arrangements should be helpful in reducing the turn-around time for processing interconnection applications. The Board notes, however, that when it is called upon to assess the overall need for an interconnection project pursuant to Section 34 of the EUA, the Board’s determination of need is typically straightforward because the technical specifications have been worked out by the end-use customer and the AESO in advance, based primarily on the customer’s requirement for a defined level of reliability. Accordingly, the Board notes that when it approves the need for a customer interconnection project, the Board does not consider that such an approval should imply, in any respect, that the Board agrees that the facilities built for an interconnection project should be regarded as standard facilities for the purposes of applying the contribution policies of either the AESO or the applicable Disco. In this regard, the Board notes that a disclaimer warning parties not to infer interpretations of contribution policies is included in the introductory sections of both of the Interconnection Redesign Process documents filed in the Application proceeding.87 The Board considers that this disclaimer is important and needs to be heeded in the present case.

84 Exhibit 23-016 (Response to BR-TCE-1) 85 Exhibit 30-006, “Distribution Point-of Delivery Interconnection Process Guideline – Typical Supply

Arrangements” 86 Exhibit 02-033-004, TCE.AESO-238(a) Attachment entitled “Distribution Point-of Delivery Interconnection

Process Guideline – Standard of Service” 87 Exhibit 30-006, page 1 and Exhibit 02-033-004, page 1



Notwithstanding the above, the Board agrees with the comment of the Cities that it may be somewhat unrealistic to expect that these documents could not have some influence on the determination of standard service. It is of concern to the Board that the above referenced documents could be interpreted such that, for Discos, facilities above a single line and transformer, could be considered standard for loads above a certain level. This could provide incentives for customers to generally favour interconnection to a distribution system over interconnection to the AESO system. The Board considers that it would to be an economically inefficient and undesirable result if the type of interconnection (i.e. distribution vs. transmission) sought by a customer was driven more by a Disco’s more attractive contribution policy than on the basis of which type of interconnection was the most technically sound and cost efficient. Accordingly, the Board considers that it is important for the standard service definitions of the AESO and Discos to be aligned to the extent possible. For this to occur, the Board considers that an evaluation and debate must take place regarding the extent, if at all, that a minimum service norm as discussed in the Interconnection Redesign Process should be set at a higher level than a Disco’s standard facilities definition for a Disco’s contribution purposes. The Board considers the above described exercise to be an essential aspect of the harmonization of Disco and AESO contribution policies that should occur as soon as practicable. The Board will provide additional directions in regard to AESO/Disco harmonization process in Section 6.3.2 of this Decision. 6.1.4 Maximum Investment Formula The AESO noted that in Decision 2001-6, the Board had supported a criterion for the design of the maximum investment formula (presently referred to as the “roll-in ceiling” in the existing tariff) such that approximately 80% of interconnection projects would not require a customer contribution. The AESO noted that it was posited by the AESO’s predecessor during the course of the proceeding leading to Decision 2001-6 that setting a roll-in ceiling in this manner would have the effect of minimizing intergenerational inequities. In the Application, the AESO noted that the use of the roll-in ceiling had not met the target of 80% of projects not requiring a contribution with 20% of projects requiring some contribution be paid. Instead, it was noted that, in practice, the roll-in ceiling has resulted in customers being required to pay a contribution only in respect of about 10% of interconnection projects. The Application also noted that while the roll-in ceiling reflected some consideration of the forecast amount of transmission rate revenues to be paid by a customer following the customer’s interconnection, the major driver of the size of the roll-in ceiling for a specific project related to the length of the DTS contract signed by the customer (the “commitment term amount”). In an effort to try to meet the 80/20 target more consistently, the AESO has proposed a new maximum investment function in the Application. The proposed maximum investment function does not include a Commitment Term component. Instead, the AESO has proposed a simpler formula under which a customer would be granted an investment allowance of $27,000 per MW of contracted DTS load, per year of DTS contract term. A graphical representation of the roll-in ceiling and the maximum investment function proposed in the Application are shown in Figure 6.1.2.88 88 Application, Section 6, page 10



As discussed above in Section 6.1.1 the Board considers it is of primary importance that the contribution policy should send appropriate economic siting signals to new customers. The Board considers the design of the maximum investment function to be central to the goal of sending appropriate economic signals through the contribution policy. While the Board notes that the AESO has attempted to achieve a balance between economic signals and administrative simplicity, the Board considers that the maximum investment function proposed by the AESO is overly simple. As a result, it does not achieve an appropriate balance between simplicity and appropriate economic signals. The primary concern of the Board with respect to the AESO’s proposed investment function is that it emphasizes revenues; that is, the AESO has considered the revenue stream it will receive from a prospective connection, rather than costs as a driver of the design. The Board agrees with the AESO that the current roll-in ceiling formula places a disproportionately high emphasis on the commitment term amount of the formula when compared to forecasted revenues. However, it is inappropriate to presume that a desire to downplay the influence of the commitment term component of the current roll-in ceiling formula results in a general preference for revenue based investment formulas over cost based formulas. The Board considers that the underlying rationale for the consideration of revenues in the context of a contribution investment policy relates to the manner in which a new customer interconnection may benefit existing customers through a broader sharing of embedded system costs. In this context, the incremental transmission revenue generated by connecting the new customer is also the maximum level of the “willingness to pay” of existing customers. Furthermore, since the Board considers that a new customer may normally be presumed to be seeking an interconnection in order to obtain the benefits of electrical service rather than an investment allowance per se, the Board considers that the new customer should be provided the incentive to commit an investment as long as the costs of any required interconnection facilities are offset. Thus, there is the potential risk of creating a substantial difference between the respective willingness to pay of the new customers and that of existing customers. The difficulty in creating a utility investment policy is to determine how to design a maximum investment allowance function that will fall at a reasonable level within this range. Based on evidence brought forward in this proceeding, the Board has determined that cost, not revenue, is the appropriate starting point for establishing the investment policy. As such, rather than being a driver of the investment policy, the Board considers that the primary role that transmission tariff revenues should play is to establish the upper limit of the investment allowance. That is, if the transmission revenues expected to be generated by a new DTS customer over the customer’s contract term are estimated to be less than the expected cost of a standard facility interconnection, the amount of maximum investment function should be limited to no more than the amount of the estimated incremental transmission revenue. While the Board notes that the AESO has indicated that it has adopted a revenue based approach for the AESO’s maximum investment proposed in the Application, the Board considers that the AESO’s proposal is, in reality, based on the observed and/or derived costs for a set of interconnection projects of varying sizes.89 In contrast, the Board notes that the revenue based aspect of the AESO investment proposal related to the AESO’s decision to force the derived

89 Application, Section 6, Pages 8-9



investment line through a zero intercept. The Board understands that this constraint was imposed in an attempt to reflect the fact that the AESO’s proposed rate design did not include a customer charge.90 However, the Board considers that the AESO’s adoption of the zero intercept constraint acted in combination with the AESO’s adoption of a linear form for the investment function to create a function that is excessively steep. As a result, the Board considers that the AESO’s proposed maximum investment function tends to provide an insufficient allowance for small interconnection projects and an excessive allowance in respect of comparatively larger projects. In addition to these concerns, it is also not clear to the Board that a linear investment function will properly reflect the reduced rate at which interconnection project costs increase as peak load rises. In this regard, the Board was strongly persuaded by the testimony of the IPCAA panel91 that significant scale economies occur as the size of interconnection projects increases. As a result, the Board considers that such scale economies should be reflected in the functional form of the maximum investment curve. The Board also takes note of evidence introduced by TCE which concretely illustrated the existence of significant scale economies in respect of both transformation equipment and transmission lines.92 In light of the Board’s findings with respect to scale economies, the Board considers that it is appropriate for the AESO to assess the merits of a non-linear rather than a linear form for the maximum investment function along the lines of the “0.6 power rule”93 discussed by the Chairman and IPCAA. The Board noted, with interest, IPCAA’s proposed approach whereby a threshold above the proposed allowable investment is incorporated into the maximum investment allowance. The Board notes that it is in the interest of existing AESO customers that the interconnection of new customers be encouraged so long as the interconnection costs to be funded by existing customers are less than the incremental transmission tariff revenues expected to be generated. Accordingly, the Board considers that it is appropriate that the maximum investment function to be applied in the longer term should include some additional “tolerance” above the amount that would be provided under an investment function strictly designed to reflect average costs. However, the Board is not prepared at this time to adopt IPCAA’s recommendation that the investment function should be increased by 25%. Instead, the Board considers that an appropriate level for this “average-cost plus” threshold should be the subject of future study of the extent to which interconnection project costs of a comparable capacity may be expected to exceed the average for that size of project. Notwithstanding the Board’s suggestion to review the merits of a non-linear maximum investment function and provide its findings at the next GRA, the Board notes that the notion of a non-linear function was discussed only at a conceptual level during the Application proceeding. As such, the Board considers that a linear maximum investment function must continue to be utilized in the short term. Accordingly, the Board hereby directs the AESO to amend Article 9.4 90 The AESO indicates at Tr. Vol. 3, pages 875-876, that the choice of a zero intercept reflected the AESO’s

proposed rate design in which DTS rates did not have a customer charge component. 91 Transcript Vol. 6, pp. 1587-1589 92 Exhibit 23-019-001 (FIRM-TCE-3 Schedule A) and Exhibit 23-019-002 (FIRM-TCE-3 Schedule B) 93 The chairman discussed the subject matter of potential scale economies in respect of interconnection projects

with the IPCAA panel at TR. Vol. 6, pp. 1587-1589. In the course of that exchange, the chairman discussed with the IPCAA panel the notion that engineers typically apply a rule-of-thumb which postulates that typical engineering projects should rise by only about 60% for any 100% increase in the size of the project. While it is not the intention of the Board to prescribe a specific non-linear functional form for the maximum investment function to the AESO, the Board considers that this “point-six power rule” may provide a useful starting point for the AESO’s investigations.



of the Terms and Conditions proposed for the Application such that a minimum investment allowance reflects:

• A minimum investment allowance of $2.5 million; and • An additional investment of $100,000 per MW of project capacity94

The AESO is further directed to provide a copy of the proposed adjustments to Article 9.4 with the refiling Application pursuant to this Decision. In respect of the longer term beyond 2006, the Board directs the AESO to conduct further study so that it may devise a more comprehensive investment function proposal which avoids the Board’s concerns with the AESO’s 2006 Application and reflects the design principles described by the Board in this Decision. The Board considers that this task will involve several distinct steps, as reflected in the following list of Board directions: 1. The Board hereby directs the AESO to conduct a study for the purpose of devising a

simplified maximum investment function. Such study to be completed in time for review no later than the 2008 GTA proceeding. The study should incorporate a sufficient number and diversity of data points to enable the study to consider the current costs of several different interconnection project sizes. Interconnection project costs for the purposes of the investment function study should only reflect the costs of standard facilities as described in the AESO Standard Facilities definition approved by the Board in this decision.

2. On the basis of the results of the study described in the preceding direction, the AESO shall

recommend an investment function that represents the average cost per MW of capacity. The Board expects that the resulting interconnection cost function derived will exhibit significant economies of scale and, as a result, may be non-linear in nature. For the purposes of the remaining steps of the Board’s maximum investment function directions, the average cost function derived in accordance with this step will be referred to as the “Raw Interconnection Project Cost Function”.

3. In accordance with the notion of a tolerance as discussed in the argument of IPCAA, the

Board directs the AESO to analyze the results of the above study for the purposes of determining an appropriate multiplier such that approximately 80% of the projects included have a cost greater than implied by the Raw Interconnection Project Cost Function fall within the selected tolerance multiplier.

The Board directs the AESO to present the results of the above analysis for review no later than the time of filing its 2008 GTA, along with its proposal for an appropriate maximum investment formula. 6.1.5 Contribution Waivers for Expansion at Multiple Customer PODs In this Application, the AESO proposes to waive customer contributions in respect of transmission projects at AESO PODs where multiple users are served by a distribution utility. The elements of the AESO’s Multi-POD waiver are described in Article 9.5 of the AESO’s proposed T&Cs. Specifically, Article 9.5 provides that, effective January 1, 2006, the AESO 94 This direction is based on the IPCAA analysis described at page 34 of IPCAA’s argument submission.



would waive all or part of the customer contribution that would otherwise be assessed against a distribution utility for transmission facility expansions at a multiple-user POD on condition that the distribution utility:

• Provides sufficient documentation to demonstrate that the customer contribution arises from a transmission project required by multiple end-use sites served by the distribution utility;

• Executes a twenty year System Access Service Agreement in respect of the multiple–user POD; and

• Agrees to flow through a pro rated share of the customer contribution that would otherwise apply in respect of a transmission expansion at a multi-user POD to identifiable customers of the distribution utility with loads greater than 2 MW.

The proposed Article 9.5 also specifies that the proposed contribution waiver would not be available in respect of any transmission facilities above and beyond the AESO Standard Facilities deemed to be required to provide acceptable service to the distribution utility. The AESO submitted that the availability of a contribution waiver in respect of distribution utility PODs serving multiple customers was necessary because:

(1) regulated utilities have an obligation to serve regardless of any limits imposed by the AESO’s contribution policy; and

(2) distribution utilities have little if any influence over the amount, location, or timing of the

load growth that they are obligated to serve. ATCO Electric95, the Cities of Lethbridge/Red Deer and FIRM supported the AESO’s multiple customer POD waiver proposal. EnCana, IPCAA and TCE opposed the proposal, primarily on grounds that it would create discrimination between the AESO’s industrial and distribution utilities. Alpac indicated that while it did not have a view on the multiple-customer POD waiver proposal at the present time, it considered that other aspects of the AESO’s proposed contribution policy should be determined by the Board before further consideration is given to the multiple customer POD waiver. The Board agrees with the AESO’s observation that there are fundamental differences between distribution utilities and industrial customers. In particular, the Board agrees that whereas a regulated distribution utility has a statutory obligation to provide adequate service in response to load growth that it cannot dissuade or otherwise control, there is no analogous requirement on an industrial customer to ensure that it receives electric service at some predefined minimum level of service and reliability. The Board further notes that, unlike the AESO’s industrial customers, the AESO’s distribution utility customers have the ability to collect revenues reflective of the prudent costs of carrying out their statutory obligations through the regulated distribution utility’s tariff. As such, in the event that a transmission facility investment required by a regulated distribution utility is not fully covered under the AESO’s contribution policy, the distribution utility should generally be able to expect that the costs of a customer contribution paid to the AESO may be recovered by flowing the cost of the customer contribution through the

95 In addition to supporting the multiple customer POD contribution waiver, AE also indicated that the availability

of such a waiver should be back dated to January 1, 2005 rather than only being available as at January 1, 2006.



regulated distribution utility’s revenue requirement. By contrast, industrial customers do not enjoy a comparable guarantee that they will be able to pass along any customer contribution costs through the costs of the products they may produce. Notwithstanding these noted differences, the Board is not persuaded that it is necessary or appropriate to grant a waiver from customer contributions otherwise payable by the distribution utility to the AESO. In particular, given that a distribution utility should generally be able to recover customer contributions arising from AESO facility projects through the distribution utility’s own tariff, the assessment of a contribution waiver is reduced to a question of whether the contribution costs should be spread more narrowly through a specific distribution utility’s tariff or shared more broadly under a waiver scenario that would see these costs being absorbed within the AESO’s revenue requirement. In this regard, the Board notes that it was previously determined in Decision 2001-6 that the AESO’s predecessor would not violate the principle of postage stamp rates by adopting a contribution policy that could require some distribution utilities to pay somewhat higher contributions than other distribution utilities.96 The Board further notes that while narrative in the Application appeared to suggest that the AESO’s existing contribution policy might be regarded as violating certain aspects of postage stamp principle, the AESO confirmed in an information request response97 that statements on p. 88 of the Application linking the existing contribution policy to a possible postage stamp principle violation had previously been disposed of in Decision 2001-6. The Board considers that it is both consistent with past practice and consistent with the desire to send efficient pricing signals through the contribution policy that customer contribution costs incurred by a distribution utility should be recovered through the distribution utility’s own tariff. Accordingly, the Board hereby denies the AESO’s proposed Article 9.5 of the Application’s proposed T&Cs in its entirety. 6.1.6 Other Contribution Policy Issues

6.1.6.1 Application of Contribution Policy to Dual-Use Sites

In the Application, the AESO noted that its existing contribution policy determines the extent to which the load or supply customer contribution policies apply to a dual use customer using a formula based on the ratio of the DTS and STS contract capacity to the aggregate contract capacity at the customer’s site. Under this formula, the amount payable under the load contribution policy is determined in accordance with the following formula:

[DTS ÷ (DTS + STS)] × customer-related costs Similarly, the amount payable as a generator in respect of local interconnection costs is determined as:

[STS ÷ (DTS + STS)] × cost of the local interconnection 96 Decision 2001-6, page 55 97 BR-AESO-019. (Note: The AESO’s response to BR-AESO-019 goes onto indicate that the passage found at

p. 88 of the Application implying a possible postage stamp violation should be considered to be withdrawn from its evidence.)



The AESO noted that the dual-use ratio was intended to provide a reasonable sharing of customer-related costs between load and supply in consideration of the fact that a significant portion of the load customer’s interconnection costs may be rolled into rates through the operation of the roll-in ceiling while the generator costs are paid fully by the generator as a customer contribution. The AESO noted that, in particular, the dual-use ratio was beneficial in limiting the amount of contribution provided on the basis of the commitment term component of the roll-in ceiling which, since it is not revenue based, would provide a contribution to generators without a corresponding revenue stream. The AESO indicated, however, that because its proposed maximum investment policy had eliminated the commitment term amount from the roll-in ceiling formula, it was no longer necessary to address potential mismatches between investment and revenue through the dual-use formula. Accordingly, the AESO proposed to eliminate the dual-use formula in favour of the application of a “load first” principle. Under this method, the AESO proposed to determine the dual use customer’s interconnection contribution by first determining what the contribution would be if the customer were treated as a load customer. Accordingly, if the application of the load customer contribution provided full coverage for the cost of a standard facility interconnection, the load first principle would mean that no contribution would be required. In the event that the application of the maximum investment function for load did not cover the full cost of providing a standard facility interconnection, the customer contribution would be the residual cost after subtracting the maximum investment allowance from the cost of the standard facility interconnection, as illustrated from the following formula reproduced from the Application:

customer contribution = total customer-related costs for load and generator

less local investment for load The AESO’s proposed “load first” formula was supported by IPCAA and by TCE but was opposed by FIRM. The Board notes that the AESO’s proposition that a “load first” principle should apply in determining the contribution for dual-use customers is strongly premised on the elimination of the commitment term amount from the maximum investment formula. This would be replaced by an investment formula driven entirely by the number of MWs of DTS contract capacity and contract terms that the customer signs up for. However, the Board notes that while the maximum investment function adopted by the Board in Section 6.1.4 of the Decision above no longer includes a significant commitment term component, the formula prescribed by the Board still provides a minimum contribution of at least $2.5 million. Accordingly, while the Board considers that there is a better match under the new load contribution policy between interconnect costs and DTS revenues, the adoption of the AESO’s proposed “load first” formula would still provide a substantial contribution to generators who sign up for minimal DTS capacity. In light of this finding, the Board considers that it is still necessary to maintain the dual-use formula to ensure that AESO customers that are primarily generators are not able to gain an effective exemption from the clear policy intent of the Government’s Transmission Policy and the Transmission Regulation whereby generators are to pay for their local interconnection costs. Accordingly, the Board hereby directs the AESO, in its refiling, to re-instate the dual-use



formula as described in Article 9.3 of T&Cs of the currently approved tariff. The Board considers that alterations to the wording of the dual-use clause should only be done for the purposes of maintaining consistent numbering and references to other parts of the AESO’s T&Cs. 6.1.6.2 Staged Load The AESO proposed98 to apply the customer contribution policy in a manner that would accommodate material increases or decreases in a customer’s load, provided the customer signed a DTS contract with a term that extended a minimum of five years after the start date of the last staged contract capacity. Under this proposal, the maximum investment allowance accounting for staged changes in load, would be made available to the customer at the start of the project. However, it would be adjusted to reflect the staged nature of the load by taking the present value of the investment in the incremental load for the period of the contract term after the staged increase or decrease in the contracted capacity was to take place. The AESO’s staged load proposal was supported by FIRM. However, FIRM also submitted that if the staged load did not materialize as planned for the purposes of determining the available investment allowance, the customer receiving staged treatment should be obligated to repay any excess facility investment allowance that may have been based on the assumed staging of the contracted load. The Board notes that no parties opposed the proposal to permit the staging of load levels for the purposes of determining maximum investment allowances. The Board likewise supports and approves this proposal. However, the Board notes that the proposal to permit load staging in the determination of available investment is not specifically described in the AESO’s proposed Article 9.4 or elsewhere in the AESO’s Article 9 contribution policy T&Cs. As such, the Board shares the concern of FIRM respecting the obligation of a customer to provide a refund if the staging assumptions used initially do not materialize.99 Accordingly, the Board hereby directs the AESO to propose a specific additional provision of Article 9 which more specifically describes the consideration of staged loads for both investment allowance and refund determination purposes with its refiling Application. 6.1.6.3 Distribution vs Transmission Interconnections The Board notes that Article 9.1 of the existing tariff’s T&Cs requires the AESO to assess the appropriate way of providing service to a customer requesting a new point of connection or expansion of an existing point of connection. Article 9.1 further provides that, if the AESO determines that the most economic option for providing that service to a customer is a distribution-level extension or isolated generation or, if the customer’s request primarily represents a shift of supply or demand from an existing point of connection, then the customer will pay the full cost of the project. The Board notes that the parts of the proposed Article 9.1 describing the AESO’s obligation to assess the appropriate type of interconnection that should be provided to a customer are largely unchanged from the comparable part of the existing Article 9.1. The Board concludes, however, that some adjustment of Article 9.1 is necessary to bring it into alignment with the “optional 98 Application, Section 6, pages 11-12 99 Despite this concern, the Board notes, however that the AESO has the right to require a refund in this situation

pursuant to the AESO’s proposed Article 9.7.



service” concept discussed in Section 6.1.3 above. Of specific concern to the Board is this passage from the proposed version of Article 9.1:

If the AESO determines that the most economic option for providing service to a Customer is a facility other than a transmission facility (such as a distribution-level extension or isolated generation), or that the Customer’s request primarily represents a shift of supply or demand from an existing POC, then the Customer will pay the full cost of the transmission upgrade or extension (“the project”). [Emphasis added].

The Board is concerned that, as currently proposed, the referenced portion of Article 9.1 does not align with the concepts of AESO Standard Service and Optional Service as described elsewhere in this Decision. In particular, the above referenced passage indicates that no investment allowance will be permitted on any portion of the costs of a transmission interconnection project when the AESO has determined that a distribution project is more economic. However, the Board considers that it is appropriate that an investment allowance should be permitted in respect of that portion of a project’s costs up to the cost of the foregone lower cost distribution or isolated generation service option. The Board agrees, however, that a full customer contribution should be required in respect of the difference in cost between a lower cost distribution option and the selected transmission option. Accordingly, the Board directs the AESO to amend Article 9.1 to reflect the Board’s above noted findings as part of its refiling. 6.1.6.4 Discount Rates Article 9.12 of the proposed T&Cs updated the formula used to determine the discount rate that may be used for various purposes within the contribution policy. The Board notes that no parties opposed the AESO’s proposed changes. The Board also supports the proposed changes. Accordingly, the Board hereby approves Article 9.12 as filed. 6.1.6.5 Common Facilities Article 9.8 of the Application’s T&Cs proposed to change the way the AESO deals with situations arising when one or more additional customers make use of local interconnection facilities originally built for and funded by an existing AESO customer. Unlike the existing tariff’s Article 9.8, which describes the allocation of interconnection facility costs amongst existing customers and any newly interconnecting customers using the same facilities, the proposed Article 9.8 simply provides that in any situation in which a new customer makes use of an existing customer’s local interconnection facilities, the cost of such facilities will simply be deemed to be a “Common Facility” as defined under Article 9.8 and the costs will then be designated as system-related to be borne by all AESO customers. The AESO indicates in the Application that its proposed treatment of common facilities for the purposes of Article 9.8 was devised to comply with Subsection 16(4) of the Transmission Regulation. The AESO stated that it had interpreted the Government’s choice of the words “all users” within Subsection 16(4) to denote a specific policy intent as set out in the following response to Board IR 026:

… “all users” as “all users of the transmission system” simply because there is no qualification of usage in section 16(4). For example, if limitation has been intended,



section 16(4)(a) could have stated “all users of those facilities: or used other qualifying words.100

In argument, FIRM took issue with certain aspects of the AESO’s interpretation of Subsection 16(4) and in particular with the broad nature of the words “all users” in Subsection 16(4). In FIRM’s submission, the reference to “all users” should be interpreted as “all users of those facilities”. FIRM noted that this interpretation would be consistent with the principle of cost causation where costs should be borne by those causing the costs and with the Board’s long standing practice of applying a revenue test for shared facility costs. FIRM further submitted that, if the intent of the drafters of the legislation had been to overturn well established regulatory practice, the Transmission Regulation would have included specific language, such as “all users of the transmission system”, to effect such a change. In the absence of such language, FIRM submitted that the meaning of “all users” within Subsection 16(4) should be interpreted in a manner consistent with established Board practice and cost causation principles. FIRM noted that while its comments were primarily devised in relation to the circumstances of load customer interconnections, FIRM considered that a similar interpretation of Subsection 16(4) (references to “all users” should be interpreted as “all users of those facilities”) should also be applied when one or more new customers are added to the local interconnection facilities of an STS customer. FIRM further submitted that, if the revenue test in relation to shared facilities were eliminated through the adoption of the AESO’s proposed Article 9.8, a door to potential abuse in the future could be opened. FIRM submitted, for example, that a large customer needing new facilities involving a significant customer contribution may attempt to avoid a contribution by having another customer, perhaps an affiliate, request a second connection somewhere along the new facility line for load smaller than the original facility. In this situation, FIRM suggested that the AESO’s proposal would have the effect of funding the interconnection facilities of both of the customers in the example at the expense of all users of the system. In reply to FIRM, the AESO submitted that additional background pertinent to the interpretation of Subsection 16(4) is provided by the Government’s policy paper Transmission Development: The Right Path for Alberta101 which states:

Local “system” upgrades typically include items such as changes to stations A and B (i.e. circuit breaker change-outs, protection upgrades), reconductoring of Line A-B, or other modifications to the local system to accommodate the generator. These costs will be considered “system” costs and will not be recovered specifically from a particular generator but will be treated like all other system costs.

Having regard to this passage, the AESO submitted that its proposed re-designation of customer costs as system costs as described in Article 9.8 aligns with both the Transmission Regulation and with government policy, and should therefore be approved as filed. While the Board acknowledges the public policy concerns raised, the Board must approach this issue first as a matter of statutory interpretation. If the language used by the legislation is clear, then the Board must give effect to it. To construe any legislation, including its governing legislation, the Board applies ordinary principles of statutory interpretation. The Board will

100 While not specifically indicated in FIRM’s argument, the Board understands that the referenced passage is part

of BR-AESO-026 (Exhibit 02-016). 101 Exhibit 030-027



endeavour to give statutory language its plain and ordinary meaning having regard to its context. The Board will also interpret provisions in different enactments with similar subject matter so as to avoid conflict between them. Accordingly, the Board has first approached the question of the extent to which interconnection costs are to be shared among multiple customers by considering the language used in the beginning of Subsection 16(4) which reads as follows:

16(4) If another person makes use of the facilities for which a local interconnection cost

has been paid, (emphasis added)

As is clearly shown in the above provision, the use of the modifiers “another” before “person” and “the” before “facilities” narrows the consideration of interconnection costs to a particular customer in respect of a particular interconnection as opposed to all customers and all interconnections in general. This introductory provision must then be read as part of each of the subsections that follow. Thus the whole section read together would be as follows:

If another person makes use of the facilities for which a local interconnection cost has been paid, the cost of the use of those facilities by that other person or persons must be allocated to all users in accordance with the ISO tariff; and the original local interconnection cost, or a portion of it, must be refunded to the person who paid it in accordance with the ISO tariff.

When read as a whole, the provision supports the interpretation that the words “all users” is a reference to the cost of the use by those specific users of the interconnection facilities that are now being used by one or more persons. The Board has concluded, based on the language of Subsection 16(4) of the Transmission Regulation, that the costs of local interconnections which are used by more than one customer are to be shared amongst the other customers using that interconnection. The Board is of the view that this interpretation is consistent with the policy objectives of this scheme. The Board considers that, even if it were possible to support the AESO’s proposed broad interpretation of the effect of Subsection 16(4) as valid, the Board would have very significant concerns about the potential abuse by customers seeking to minimize their contribution costs that could result in the application of Article 9.8, as proposed. In that event, the Board would have required the AESO to devise a number of safeguards to ensure that the potential abuses identified by FIRM would not occur. With respect to the submission of the AESO that its interpretation of Subsection 16(4) of the Regulation is supported by the Government’s Transmission Policy paper, the Board notes that the passage referenced by the AESO in its reply argument occurs within the context of a discussion of Generator System Contribution. However, the Board notes that the referenced section of the policy paper does not address the question of whether secondary users of previously constructed local facilities should trigger a re-designation of a customer cost to a system cost. In any event, the Board notes that the passage from the Transmission Policy referenced by the AESO merely describes the generic dividing line for system and customer costs for the purposes of the generator contribution policy. In light of the above noted findings, the Board considers that Article 9.8 must be amended. Accordingly, the Board directs that, in its refiling, the AESO provide a revised version of



Article 9.8 based on the wording of the existing Tariff’s Article 9.8. The proposed revision should exclude current sub-Articles (a)(i) and (ii) as they are no longer relevant, given the investment formula approved by the Board. In addition to the above, the Board notes that the AESO proposed to drop Article 9.8 (c) from the existing Tariff’s T&Cs on the basis of the AESO’s assessment that the administrative burden associated with contribution refunds was not expected to be sufficiently onerous to require the continuation of the $50,000 threshold. The Board notes that no parties commented on the AESO’s proposal to eliminate the $50,000 threshold. The Board likewise has no objections. However, the Board also notes that AESO’s proposal to eliminate the $50,000 minimum refund threshold may have been premised on the Board’s adoption of Article 9.8 as applied-for by the AESO. The Board notes that the AESO’s proposed Article 9.8 provided for a straightforward transfer between existing customers (i.e. “the system”) and the customer originally paying a contribution in respect of local interconnection facilities. However, with the Board’s variance of the proposed AESO wording of Article 9.8, the Board considers that the administrative costs associated with arranging for the transfers of money between old and new customers served by an existing local connection may be more complex and onerous than initially contemplated by the AESO. In light of the above, the Board considers that the AESO should have the option of reinstating a minimum contribution threshold if, in the AESO’s opinion, the administrative burden requires this. Accordingly, the Board hereby directs the AESO in its refiling to advise the Board as to whether the minimum contribution refund threshold as provided in the existing AESO Tariff’s Article 9.8 (c) should be reinstated and, if so, to amend its T&Cs accordingly. 6.1.6.6 Conditions for Customer Contribution Adjustments Article 9.6 of the proposed T&Cs provides directions to the AESO for dealing with situations when changed circumstances result in changes in the estimated cost of an interconnection project cost as compared to the initial cost estimate provided to a customer. The Board notes that no parties raised concerns with Article 9.6. The Board has also reviewed Article 9.6 and considers that it should be approved as filed. 6.1.6.7 Pre-Paid Operations and Maintenance Charge

Article 9.13 of the proposed T&Cs provides for a prepaid operations and maintenance (O&M) charge calculated as 12% of the customer-related costs of an interconnection to be applied to all new STS customers. For all other AESO customers, including DTS customers, Article 9.13 also provides for a prepaid O&M charge to be levied. The charge is to be calculated as 12% of the cost of any interconnection facilities deemed to be in excess of the AESO Standard Facilities for the interconnection project. The AESO considered that its proposal to apply a prepaid O&M charge to newly connecting STS customers is consistent with Subsection 16(1)(a) of the Transmission Regulation which requires newly connecting generators to pay all local interconnection costs for connecting to the transmission system. The AESO considered that as customer interconnections incur on-going



O&M costs beyond their initial capital costs, it would be appropriate to include a prepaid O&M charge to ensure that load customers do not pay costs related to generator interconnections. Alpac was opposed to the adoption of the AESO’s proposed prepaid O&M charge to generators because, in its view, doing so would not be consistent with the Transmission Regulation and because it would create discrimination between existing and new generators. Alpac submitted that Subsection 30(a) of the Transmission Regulation must be interpreted such that all wires related costs are allocated to load customers. Additionally, it submitted that Subsections 30(b) and 16(1) of the Transmission Regulation would not support making generation unit owners responsible for on-going operations and maintenance costs. Alpac noted that Subsection 30(b) permitted three types of costs to be charged to owners of generating units:

1. interconnection costs, 2. a financial contribution towards system upgrades, and 3. location based losses charges.

Alpac submitted that the use of the specific wording in Subsection 16(1)(a) that “local interconnection costs” are “payable by an owner of a generating unit for connecting to the transmission system” does not support an interpretation making generating units financially responsible for the operation and ongoing maintenance of portions of the transmission system. Alpac also noted that the AESO had confirmed that while prepaid O&M charges were applied to generators under the vertically integrated regime existing in Alberta prior to 1996, this practice was not continued from 1996 on under the tariffs of the AESO’s predecessors (GRIDCO and EAL). Accordingly, Alpac submitted that re-instituting a prepaid O&M charge to generators after a decade’s absence would be unfair and would provide an unwarranted first-mover advantage for the generation unit owners who have developed projects since 1996. While FIRM was supportive of a prepaid O&M charge, FIRM submitted that evidence presented during the Application proceeding did not support 12% as the appropriate level for the surcharge. In the absence of supporting evidence, FIRM submitted that the prepaid O&M surcharge should be set with regard to the ratios of “other expenses charges” to capital charges for the duplication avoidance tariff riders contained in the AESO’s current tariff. FIRM submitted that on the basis of its analysis, the prepaid O&M surcharge should increase from the AESO’s proposed level of 12% to 15.2% until such time as a more detailed review has been completed by the AESO. The Board has established four considerations in its disposition of the AESO’s proposed prepaid O&M charge, namely:

• Whether the implementation of a prepaid O&M charge would be beneficial to the orderly evolution of the transmission system.

• Whether the application of a prepaid maintenance charge is consistent with provisions of the Transmission Regulation.

• To the extent that it is consistent with the Transmission Regulation, how should the amount of the charge applied to specific customers be determined.

• If a prepaid O&M charge is adopted, what it the appropriate amount of a prepaid O&M charge in the immediate term and/or in respect of future years.

The Board has considered each of these elements separately as they apply to STS customers and DTS customers.



STS Customers With respect to the first question, the Board considers that the notion of a prepaid O&M charge is consistent with the goal of providing an appropriate economic signal to new customers considering an interconnection to the AIES. Accordingly, the Board considers that a prepaid O&M charge should be pursued to the extent that doing so is in compliance with legislation. With respect to the second consideration, however, the Board considers the application of the AESO’s proposed prepaid O&M charge to STS customers to be problematic. The Board agrees with Alpac that Section 30 of the Transmission Regulation describes the types of costs that may be charged to generators. That section limits the recovery of costs from generators to:

• Local interconnection costs as set out in Section 16; and • Financial contributions for transmission system losses (as further described in Section 22)

and system upgrades (as further described in Section 17).

With regard to the foregoing list, the Board considers that the only manner in which the Board could conclude that a prepaid O&M cost could be applied to a generator is if the proposed charge could be treated as being part of the “local interconnection cost to connect its generating unit to the transmission system”. Applying ordinary provisions of statutory interpretation, the language in this provision clearly restricts the responsibility for generators to assume the costs necessary to connect to the transmission system. The language does not contemplate any ongoing costs beyond the initial connection costs. This is borne out by the inclusion of the phrase “costs to connect”. Had the drafters of the legislation intended the owners of generating units to be responsible for ongoing costs to maintain the connection, they would have said so. Given this interpretation, the Board concludes that the AESO cannot convert an ongoing cost, such as operations and maintenance for the interconnection, to a capital cost by requiring the cost to be paid in advance. For this reason, the Board considers that the proposed Article 9.3(a) cannot be approved. Having determined that a prepaid O&M charge cannot be supported by the Transmission Regulation, there is no need to address the remaining considerations respecting STS customers. Accordingly, the Board hereby directs that, in its refiling of the Application, the AESO shall redraft Article 9.3 so as to exclude in its entirety the Article 9.3(a) portion of the Article. DTS Customers As noted above, with respect to the Board’s finding respecting the first issue, the Board considers that the prepaid O&M charge may be beneficial from the standpoint of economic efficiency and from the standpoint of the desire to send appropriate economic siting and facility development signals through the contribution policy. On the second issue, the Board considers that there is no restriction arising from either Subsection 30(a) or elsewhere in the Transmission Regulation that would preclude the use of the charge as it is applied to DTS customers With respect to the third question regarding the structure of the charge, the Board considers that specific improvements need to be implemented in conjunction with the AESO’s refiling. The Board is particularly concerned that, in applying the proposed DTS customer pre-paid O&M



charge only to the deemed “optional facility costs” of a new interconnection, the AESO appears to be implicitly assuming that the combined amount of the pre-paid O&M costs associated with the “non-optional” local interconnection facilities and the cost of the non-optional facilities themselves will fall below the level permitted under the maximum investment allowance. However, the Board considers that this should not be presumed, particularly in light of the adjustments to the maximum investment function ordered by the Board in Section 6.1.4 above. While the Board considers that the prepaid O&M charge may be improved with further research, the Board considers that the adoption of a 12% surcharge as proposed by the AESO is a good starting point for the purposes of the 2006 Tariff. Accordingly, the Board directs the AESO in its refiling Application to apply the 12% prepaid O&M surcharge such that:

• The surcharge will be determined separately for the optional and non-optional facilities; • The portion of a DTS interconnection project’s prepaid O&M surcharge based on cost of

the optional facilities will be fully charged out to the interconnecting DTS customer, consistent with the Board’s disposition of other optional facility costs; and,

• The portion of the prepaid O&M surcharge related to non-optional facilities is added to other non-optional facility costs and evaluated against the maximum investment function to determine the amount of customer contribution that may be required in respect of the standard facility portion, if any.

While the Board believes that the adoption of a 12% prepaid O&M surcharge is directionally appropriate and should be applied for the purposes of the 2006 tariff, the Board is not convinced that sufficient evidence has been gathered to determine that 12% figure appropriately tracks costs. Accordingly, the Board directs the AESO to conduct further analysis of the appropriate amount of the prepaid O&M surcharge and to reflect their findings in the design of the surcharge included no later than with the AESO’s 2008 General Tariff Application 6.2 Generator System Contribution Subsection 17(2) of the Transmission Regulation requires the AESO to collect, in its tariff, a system contribution charge of $10,000/MW from the owners of new generators for system upgrades to existing transmission facilities required as a result of a generator’s entry on to the AIES grid. This subsection further directs the AESO to collect a system contribution charge of no more than $40,000/MW from the owners of new generators who locate in areas of the transmission system where generation exceeds load, with the amount to be based on the location of the new generating unit relative to the load. Subsection 17(4) of the Transmission Regulation directs the AESO to include in its tariff, a provision for the refund to the owner of a generating unit who paid system contribution charges pursuant to Section 17. The refund must be received over a period of 10 years from the date it was paid unless the operation of the generating unit failed to meet satisfactory performance standards as set forth in rules to be developed by the AESO pursuant to Subsection 17(5). In its application, the AESO proposed to refund generator system contributions by way of 9 equal payments spread out over the 10 year period. The AESO explained that its suggested proposal was created to allow for the event that an owner of a generator might experience



circumstances beyond its control during one year of the 10 year period, thus not satisfying the AESO’s rules for satisfactory operation for that year. The AESO reasoned that the owner of the generator should still have an opportunity to collect the full amount of the system contribution it made, despite having 1 substandard year during the 10 year period. The AESO noted the system contribution must be paid before construction and must be refunded within ten years of payment subject to satisfactory performance. Since satisfactory performance can only begin after construction is complete, and since construction of both the generating unit and interconnection facilities takes time, Article 9.10 of its Terms and Conditions provided for the refund of the system contribution in fewer than nine equal annual amounts, based on the number of years after the commercial operation date of the generator and the ninth year after payment. However, to ensure that the interconnection proceeded, if the commercial operation date was later than five years after payment of the system contribution, one-fifth of the contribution would be forfeited for each additional year the commercial operation date was delayed beyond five years. If the commercial operation date did not occur within ten years after the system contribution was paid, the whole contribution would be forfeited. The AESO also proposed that no interest would be paid on the contributions. Rather, they would be treated as no-cost capital with any interest earned used to reduce overall AESO interest expense.102 The AESO noted103 that it would be developing the rules for performance measurement outside the ambit of this proceeding, given its understanding that Board approval of these rules is not required under Subsection 17(5). TAU argued that allowing the AESO to implement rules concerning a generator’s minimum operation standards might unduly influence the energy market and would be contrary to the intent of the Transmission Regulation. TAU considered that the AESO’s role should be to facilitate an open and competitive energy market but not to influence the manner in which the energy market operates. FIRM’s position in the proceeding was that the AESO should structure the timing of the refund of the system contributions over the 10 year period in a manner which would motivate the owners of generators to meet the AESO’s performance standards for operation over the entire period, especially during the initial portion of the refund period, when the impact on the AESO’s revenue requirement caused by the inclusion of these new generators would be the highest. To achieve this goal, FIRM considered that the system contribution refund amounts should increase year by year over the 10 year refund period such that the lowest percentage of the refund would be provided in the first year and the highest percentage would be available in the last year. FIRM considered that this approach appropriately reflected the front end nature of the expenditures on system transmission facilities built for the benefit of the owners of generators. FIRM indicated that its approach could be combined with the AESO’s recommendation to withhold 1/5 of the system contribution refund for each year after the 5th year in which a generator was still not interconnected. With respect to TAU’s concern that the imposition of rules concerning minimum generator output by the AESO may unduly influence the market, the Board notes that Subsection 17(5) of the Transmission Regulation clearly states that the AESO “must make rules to be used to assess the satisfactory performance of a generating unit by generating unit type”. The Board notes that

102 Application, Section 6, page 26 103 Application, Section 6, page 27



the AESO has held, and has stated its intention to hold in the future, additional workshops around the development of these rules, and further that the AESO has acknowledged that it will utilize the input it has received in this proceeding in the development of these rules. While the Board does not wish to discourage the AESO’s stated intention to consult with stakeholders in the development of these performance rules, the Board expects that the AESO, in developing its rules, will adhere to reasonable commercial principles in their creation regardless of the input received during the consultation process. The Board notes that the AESO has jurisdiction over the development of the rules. However, the Board retains jurisdiction over the evaluation of such rules in the event of a complaint further to Section 25 of the EUA. As these rules have not been developed, the Board will not comment further on the concerns expressed by TAU and expects TAU to take this matter up with the AESO as part of the AESO’s consultation process. With respect to FIRM’s proposition that the system contribution refunds increase in amount over the 10 year period, the Board considers this option has considerable merit. The Board is concerned that AESO customers should not face undue risks that system investments that may have been significantly predicated on the facilitation of an open and competitive generation marketplace should become stranded at the cost of DTS customers as a result of a generator owner’s failure to fulfill its commitments. The Board considers that the back-end loading of refunds reflects the fact that the AESO is required to place considerable reliance on the forecasts of generator owners in devising its long term transmission plans. As such, the Board considers it fair, in light of the generator owner’s ability to obtain a full or partial refund of the system contribution costs that it paid, to place some onus on generator owners to ensure that capacity built on their behalf is appropriately available and satisfactorily utilized. The Board notes that load customers bear the risk of additional capital and interest costs in the event that a generator owner does not meet the commercial operation date for delivery of energy to the transmission assets that the owner requires from the AESO and for which date the AESO implemented its transmission system upgrade plans. Having considered all of the above, the Board hereby directs the AESO to provide an amended Article 9.10 of the Terms and Conditions in its refiling application in accordance with the following parameters:

1. Payment of all of the charges pursuant to Subsection 17(2) shall be made prior to the date of construction. The Board recognizes that Subsection 17(3)(e) only requires the owner of a generator to pay the charges owing under Subsection 17 (2)(b) before commencement of construction of the local interconnection facility. However, the Board considers that prepayment of all costs, either customer contribution or system contribution, should be paid prior to the start of the commencement of activities related to the construction of any new transmission facilities necessary to provide the requested service. This will benefit the public interest by providing the maximum level of security from the outset. This will also encourage new generators to achieve commercial operation at the earliest time in order to realize their refunds, and will also be in the interests of all Albertans as they seek to realize the benefits of such generation as soon as it can reach commercial operation.



2. Any refund paid to a generating owner pursuant to Subsection 17 (4) shall be paid out no later than 10 years following the date of original payment but shall not be due and owing until after the commercial operation date for the generating unit has been achieved provided that the commercial operation date is before the expiration of the 10 years. This will, of necessity compress the refund period to a remaining period of less than 10 years in most, if not all, circumstances. For purposes of clarity, commercial operation date means the date agreed to by the AESO and the generator owner when the plant requires the transmission assets requested for delivery of energy to the AIES.

For example, assume that a charge is paid to the AESO by the generator owner on January 1, 2006 pursuant to Subsection 17 (2). In accordance with Subsection 17 (4)(a) of the Transmission Regulation, and assuming satisfactory performance, the generator owner would be entitled to receive a full refund of its payment by no later than December 31, 2015. However, if the commercial operation date is January 1, 2008, the AESO will only have 8 rather than 10 years to pay out the refund.

3. In the event that a generator owner does not commence the delivery of energy at the

levels agreed with the AESO at the time that the generator contributions were provided to the AESO by the commercial operation date for any reason whatsoever, then for each year or portion thereof that the date is delayed, the refund for that year or portion thereof will be forfeited.

Again, in consideration of the example above, in the event that the commercial operating date is not January 1, 2008 as originally provided to the AESO but is January 1, 2009, then the AESO shall deem that entire period to be one in which the generator owner failed to meet satisfactory performance standards and as such, the AESO will be entitled to retain that portion of the refund that otherwise would have been payable that year. The overall schedule over which the refund is to be paid will not change.

4. Once commercial operation of the generating unit has commenced, in the event that a

generator owner fails to meet satisfactory performance standards, any refund will be forfeited for that period.

5. The refund amount shall be structured in a backend loaded manner over the refund period

such that 25% of the total refund shall be paid out in equal payments per year over the first half of the refund period and 75% shall be paid out in equal payments per year over the last half of the remaining period.

Using the example outlined above, in the event that a generator owner becomes eligible for a refund as of January 1, 2008 (the commercial operation date) and again assuming that the payment period ends December 31, 2015, then, for the years 2008 to 2011, 25% of the total eligible refund is available to be refunded in 4 equal payments while for the years 2012 to 2015, 75% of the total eligible refund is available to be refunded in 4 equal payments.

6. The AESO shall apply any forfeited refund amounts to a deferral account and any

balances in that account shall be considered a revenue offset to its revenue requirement in a subsequent GTA.



7. No interest shall be payable by the AESO to a generator owner on any refund amounts. 6.3 Contribution Policy Next Steps

6.3.1 Contribution Policy Implementation Timing The Board notes that the Application proposed that the Tariff should come into effect on January 1, 2006 which is consistent with the legislative timing required by Subsection 31(3) of the Transmission Regulation. 6.3.2 Disco/AESO Contribution Policy Harmonization The Board notes that a concern about the need to advance the harmonization of the contribution policies of the AESO and distribution utilities has been discussed in several parts of this decision. In light of this concern, the Board considers that it would be beneficial for the AESO to assume a leadership role towards achieving greater harmonization and coordination. Accordingly, the Board hereby directs the AESO, in conjunction with the distribution utilities and such other stakeholders the AESO would consider to have an interest, to develop a proposal for harmonization of these contribution policies and to present the results at its next GTA. Although the Board considers that the ultimate terms of reference for the harmonization initiative should be established by the AESO and participating stakeholders, the Board considers that it would be beneficial for the harmonization process to, at minimum, address the following issues:

• The development of a common definition of standard POD facilities as between Disco’s and AESO (TFO) connected customers.

• Consideration of whether it is appropriate to establish defined “cutoffs” such as a maximum MVA capacity for the consideration of the interconnection of a new customer to a Disco and/or a minimum threshold for the consideration of the interconnection of a new customer to a TFO system.

• Consideration as to whether it is feasible or appropriate to adopt a common form for a cost based maximum investment function (i.e. a standard formula that would provide a greater cost allowance for the purposes the Disco’s and AESO’s respective investment policies with increases in the capacity of the interconnection

In conjunction with the above, the Board hereby also directs the AESO to provide a progress report on its contribution policy harmonization efforts in conjunction with its 2007 Tariff Application. 6.4 TransCanada Standard Interconnection Facilities Complaint On September 20, 2004, TCE filed a complaint with the Board pursuant to Section 25(1)(b) of the EUA in respect of the manner in which the AESO’s current contribution policy was applied in respect of interconnection facilities built for a TCE gas storage facility near Edson, Alberta (the Edson facility). In follow up correspondence to the Board dated February 17, 2004, TCE further advised that it would be prepared to have its complaint matter addressed in the context of the 2005/2006 tariff proceeding. Pursuant to Section 25 of the EUA, the Board, on receipt of a complaint under this provision, may, by giving written notice to the party making the complaint, investigate a complaint, decline



to investigate the complaint, hold a hearing or terminate an investigation or hearing provided the grounds for termination as set forth in Subsections 25(4) (a) through (d) of the Act are satisfied. In order for the Board to make a determination respecting this complaint, the Board must, pursuant to Subsection 25 (6) of the Act, determine the justness and reasonableness of the AESO fee complained of. In order to do so, the Board must make a determination of the justness and reasonableness of the current tariff policy and the application of that policy to the Edson facility. As the subject matter of this hearing was with respect to the proposed tariff policy, the Board does not consider it advisable to address this complaint within this Application proceeding but will consider the complaint in a separate proceeding. 7 TERMS AND CONDITIONS – OTHER

7.1 System Access Applications The AESO proposed104 to amend Article 5 (previously 7) of the T&Cs to accord with the AESO’s revised interconnection process. The AESO explained the new process has been established through stakeholder collaboration that included representatives from the AESO, the EUB, ENMAX, EPCOR, FortisAlberta, ATCO, AltaLink, VisionQuest, Canadian Natural Resources Limited, and EnCana. The AESO stated implementation of the transmission interconnection process is continuing to be developed among those parties. The AESO stated the new single-stage process would allow for a more active presence by the transmission facilities owner (TFO) and a more direct working relationship between service providers and customers, which is intended to streamline system access applications. Although the AESO will retain oversight of all transmission interconnections, it will no longer perform each of the day-to-day tasks related to such projects. For example, payment of customer contributions will normally be made directly by the customer to the TFO, although determination and administration of customer contributions will remain with the AESO. As part of the new interconnection process, Article 5 includes the following three revisions to the level and applicability of system application fees. The existing fee structure was established through the AESO’s 2002 Negotiated Settlement and was intended to create a manageable interconnection queue by introducing fees large enough to discourage customers who did not seriously intend to proceed with interconnection. The AESO proposed to revise three aspects of the system application fee.

a. System application fees are proposed to be simplified and reduced. The current two-stage application fee has been revised to a single charge in accordance with the new single-stage interconnection process. Table 6.3.1 provides a comparison of proposed and current fees.




Table 6.3.1 Proposed and Current Application Fees Proposed Application Fees

Project Size Fee < 15 MW $10,000 > 15 MW and ≤ 25 MW $20,000 > 25 MW $50,000

Current Application Fees Project Size Stage 1 Fee Stage 2 Fee < 10 MW $5,000 $5,000 > 10 MW and ≤ 15 MW $8,000 $8,000 > 15 MW and ≤ 25 MW $15,000 $15,000 > 25 MW $40,000 $50,000

b. System application fees will be refundable upon energization of the customer’s

facilities. Implementing a refundable fee continues to discourage non-serious applications, but will allow the cost of transmission system planning to be more appropriately recognized in the AESO’s standard tariff.

c. System application fees will be eliminated for transmission projects arising from

distribution load growth caused by multiple users. The elimination of such fees recognizes that:

• distribution load growth can be better managed through the planning, rather than

the transmission interconnection, process; and • application fees are unnecessary to discourage non-serious customers when the

expansion is due to load growth on a distribution network. The Board notes that this matter did not generate any comment in argument or reply. The Board has considered the AESO’s comments and proposals and believes them to be reasonable. The AESO proposals are approved. 7.2 Right of “Set-Off”

In argument, ATCO Electric (AE) expressed concern with the proposal contained in Article 6.3(b) of the T&Cs which currently provided a “set-off” not only with respect to amounts owing to or by the customer, but also its affiliates. AE was of the view that this provision attempted to ignore and override the fundamentals of basic corporate law, which recognized that separate corporate entities were not legally responsible for the actions of an affiliate. AE submitted that it was entirely inappropriate for the AESO to attempt to override corporate law through the Board approved T&Cs. AE submitted the Board did not even have the authority to override corporate law and stated the provision should be deleted. In reply, TCE agreed with AE that this proposal was beyond the legal authority of the AESO. TCE stated that generally, distinct corporate entities are not legally responsible for the actions of their affiliates.105 Moreover, corporate entities are generally not able to bind their affiliates.106 Finally, the AESO has no legal authority to bind a customer’s affiliate based on a contract with

105 Aluminum Co. of Canada v. Toronto (City), [1944] 3 D.L.R. 609 (S.C.C.) 106 Blacklaws v. 470433 Alberta Ltd. (2000), 84 Alta. L.R. (Alta. C.A)



that customer.107 TCE therefore submitted that Article 6.3(b) of the T&Cs should not be approved or at a minimum the words “or its Affiliates” should be deleted. The Board notes that the AESO, in its Argument, advised that it agreed with AE that the provisions in its proposed Article 6.3 (b) of its T&Cs may not be enforceable as presented in the Application and that it wished to delete the reference to “Affiliates” in that article.108 The Board accepts the AESO’s proposal and directs the AESO to amend this provision accordingly in its refiling. 7.3 TFO Investment in Optional Facilities Constructed for Distribution Facility

Owners (Discos) In argument, AltaLink maintained there was a problem with the AESO’s T&Cs regarding the construction of non-standard facilities for a Disco. In particular AltaLink offered the following six comments:

First, under the customer contribution policy set out in the AESO terms and conditions of service, it is the Disco and not the TFO that incurs the capital investment to in relation to non-standard facilities that are ultimately constructed owned and operated on the TFO’s system and at the TFO’s risk.

Second, the Disco recovers the capital necessarily raised to make the capital contribution that flows through to the TFO, by either expensing the amount through its deferral account or potentially adding the amount to rate base and earning a return.

Third, the Disco’s expensing of an amount related to a long-lived capital asset of this nature is inconsistent with the utility principle of maintaining intergenerational equity. While it is perhaps understandable that this issue was ignored in the past when amounts in respect of Disco requested non-standard facilities were small, the issue cannot be ignored during a growth period when the amounts in respect of such requests are likely to be significant.

Fourth, given the different capital structures and cost of capital for Discos compared to that for TFOs, in circumstances where the TFO and Disco are separate stand-alone entities, the cost of capital reflected in the revenue requirement of the Disco in respect of the capital contribution, will be higher than would have been the case had the investment been made directly by the TFO and included in the TFOs rate base, in the absence of a capital contribution. It is incongruous for a regulated Disco to be earning a return on assets, which are part of the transmission system.

Fifth, on the record in this proceeding, the amount in question is significant and could in 2005 reach approximately ten million dollars.

Sixth, the maintenance of fairness, in the sense of appropriately balancing the interests of the customers and investors in stand-alone TFO utilities, and ensuring just and reasonable rates, requires that the current practice be addressed by appropriate amendments to the AESO’s terms and conditions of service.109

To rectify the problem, AltaLink suggested that, instead of the Disco flowing through the customer contribution in respect of non-standard interconnection costs to the TFO, the TFO should make the direct investment in Disco requested non-standard facilities and include the

107 The Law of Contract in Canada, (4th ed) by G.H.L. Fridman. Toronto: Carswell, 1999, page 198 108 AESO Argument, page 41 109 AltaLink Argument, pages 5-6



amount of such investment in its capital deferral account for the corresponding year. The TFO would separately identify the owning cost (return, taxes and depreciation) associated with the non standard facilities requested by the Disco (information that is separately tracked in any event) in the TFO’s billing under its tariff with the AESO. The AESO could then stream the annual cost, separately identified in this manner, to the Disco whose request gave rise to the cost in the first place. AltaLink submitted that the AESO indicated that at a high level, it would not have a particular problem with the approach outlined above.110 The AESO also acknowledged that there may be need for certain exceptions arising from the different ownership structures of the distribution companies and transmission companies.111 In reply, AltaLink noted that Fortis suggested Disco’s were in a similar position to TFO’s with respect to customer contributions received by them from customers in respect of distribution facilities. AltaLink claimed what Fortis failed to appreciate or acknowledge is that there is an important difference in circumstances and inequity that arises in the case of Disco requested non-standard facilities installed on the transmission system. In this latter case, the Disco raises the capital necessary to make the capital contribution and the amount raised is either expensed by the Disco or added to the Disco’s rate base. As AltaLink described in its argument, neither result is just or reasonable. While the investment in Disco requested non-standard facilities installed on the TFO systems may not have been significant in the past, the evidence is that the investment in 2005 alone could reach approximately ten million dollars.112 In its reply, Fortis stated that the AltaLink proposal would effectively amount to an ‘AESO optional facilities rate rider’, whereby facilities that are optional (in the sense of being beyond a defined standard set of facilities) and which would normally attract a customer contribution under the AESO investment policy, do not attract such a contribution requirement. Instead, Fortis maintained, AltaLink, as the TFO would make the investment in such facilities, which would then be separately tracked and calculated for TFO revenue requirement purposes, then separately billed to the AESO by the TFO then separately billed by the AESO to Fortis as the Disco, and then presumably separately billed by Fortis as some sort of rider to the customers whose needs or request gave rise to the non-standard facilities. Fortis stated all of this was only to avoid the normal treatment as a contribution in aid of construction to transmission facilities to be received by AltaLink in the normal course and treated by AltaLink in the normal course. This was, Fortis maintained, a significant amount of regulatory inefficiency proposed simply to affect an increase in AltaLink rate base amounts over what would pertain in the normal course. Fortis also maintained that being a purely AltaLink-centric proposal, it would engender differing rate treatments in the TFO and Disco tariffs around the Province where AltaLink was not involved. AltaLink suggested that it was dealing with “an anomaly”, when in fact it is proposing to create an anomaly. Fortis stated Discos and TFOs have for many years received contributions to distribution facilities and transmission facilities respectively, and have treated these amounts as no cost capital underlying rate base, while bearing the ownership and operating responsibility and risk in respect of such facilities.

110 Transcript Volume 1, page 190, line 4 through page 195, line 2 111 Transcript Volume 4, page 1059, lines 17 through 25 112 Transcript Volume 1, page 181, line 8 through page 182, line 13



Fortis also disputed AltaLink’s assertion that the AESO did not object to AltaLink’s proposal, noting the following comments of Mr. Millar:113

The entire structure of contributions in aid of construction is really set up, first and foremost, to ensure overall proper cost accountability among the customers. And from the AESO's perspective, a distribution company is another customer, and we would expect the same tariff provisions to apply and, in fact, are required by this Board to treat a distribution point of delivery the same as an industrial point of delivery for investment and contribution purposes.

So we see that as being the primary issue. Distribution companies generally have fairly large held contributions in aid of construction that are reducing their net rate base. The fact that they may be obliged to pay a contribution that increases the rate base I don't think is necessarily a conceptual problem we have.

The contribution then may go on to reduce the transmission facility owner's net rate base. They obviously still own the asset, and it's sitting in the transmission facility owner's fixed capital records, but the calculation of net base rate would be reduced.

And if that is causing some perceived loss to the transmission facility owner, I think there are other ways of addressing that issue, and that should be an issue the transmission facility owner should bring before the Board in their own rate application.

I don't think it would be appropriate to adjust the contribution policy to achieve, I'll say, a bad outcome on the signal it's sending customers for the sake of addressing the issue in the transmission facility owner's, in their books, and that it issue -- if to the extent it is an issue -- can properly and probably be better addressed head on than by trying to ensure that contributions aren't paid in the first place.

The Board has considered the comments of AltaLink and finds that the AltaLink proposal would create unnecessary changes to current practice and administrative complexity, largely to effect an increase in TFO rate base. The AltaLink proposal is denied. 7.4 Merchant Transmission Interconnections This issue was first raised by TCE in its intervener evidence. TCE noted that Section 15(6) of the Transmission Regulation stated:

The ISO must include in the ISO tariff, rates and terms and conditions that include costs for use of the interconnected electric system, appropriate for the class of service provided to persons who use the facilities referred to in this section for import or export of electricity to or from Alberta.

TCE maintained the Application does not provide the rates and T&Cs contemplated by Section 15(6). These rates and terms and conditions were needed by transmission developers, including merchant transmission developers, to determine the cost of service for use of an interconnection with the AIES.114 TCE recommended the following principles in respect of transmission facilities seeking to export or import electricity:

113 Transcript Volume 1, pages 184-186 114 TCE.AESO-229(c)



1. An interconnection tariff will only be based on the use of that portion of the AIES that is reasonably attributed to the merchant transmission line (i.e. on a point to point basis).

2. An interconnection tariff respecting the use of the AIES will be based on the AIES

transmission lines actually used to provide the service. Such a tariff will not be based on theoretical transmission lines that could be built to provide a direct connection to the merchant transmission line from the generators supplying energy over the lines.

3. Costs of the transmission facilities involved in providing service to the merchant

transmission line, including facility specific losses, will be shared with other users of the same facilities based on a pro rata sharing of those lines using peak loads for each user.

4. Costs recovered from merchant transmission developers will be based on the actual cost

of service of the transmission facilities being shared by other AIES Customers using the same transmission facilities.

5. All costs of a transmission line built solely to interconnect a generator with the merchant

transmission line, and that provides no benefit to the AIES, would be charged to the merchant transmission developer.

In argument, the AESO stated that, other than that provided by TCE, there was limited evidence or discussion on merchant transmission issues or principles. The issue of tariffs for merchant transactions was closely linked to tariffs for exports and imports over existing interconnections. The AESO stated a broad consultation with stakeholders on the combined issues had not occurred. The AESO supported the continued examination of merchant transmission interconnection issues, such as those raised by TCE, through consultation. The AESO further requested that the Board refrain from taking a view on principles at this time. The AESO believed that principles, tariffs, and terms and conditions could be provided as part of the AESO 2007 GTA. In reply, TCE maintained that the AESO had not complied with Subsection 31(1) of the Transmission Regulation which required the tariff to include all matters required by the regulation and included those provisions contemplated in Subsection 15(6). TCE submitted that, if the Board agreed with TCE’s interpretation of these sections in the Transmission Regulation, then the Board should not accept the proposal that the principles, tariffs, and terms and conditions be delayed until the AESO 2007 GTA. The more compliant approach would be to adopt or modify TCE’s recommended principles115 and then direct the AESO to prepare a set of tariffs, terms and conditions that reflect those principles as soon as reasonably practical. The Board has considered the provisions referenced and, while it agrees with TCE that the AESO proposed tariff must contain provisions that include costs for use of the interconnected electric system for import or export, the Board finds that this provision does not require the development of tariff rate terms and conditions for merchant use. As the proposed tariff includes provisions for the use of the AEIS for import and export services, the Board considers the provision in Subsection 15(6) to be satisfied. The Board appreciates the

115 Exhibit 23-010, TransCanada Written Direct Evidence, page 29, line 20 to page 30, line 11



concern of TCE but notes the evidence of the AESO that TCE is the only party to comment to any extent on this matter and that broad consultation with stakeholders had not occurred yet. The Board is prepared to grant the request of the AESO that no further action be taken on principles as a result of this proceeding. However, the Board directs the AESO to consult with stakeholders in the interim and address merchant interconnection principles in the 2007 GTA. 7.5 Contract Term, Reductions, and Termination In the Application116, the AESO explained that Article 14 had been expanded to include the provision that, in reducing contract capacity, the customer will be required to sign a revised System Access Service Agreement and may be required to pay a customer contribution. The potential for an additional contribution recognizes that the proposed local investment is based on a specific contract capacity over a contract term. The maximum local investment would therefore be reduced, in proportion to a reduction in contract capacity, to a level potentially below the customer-related costs and therefore require a customer contribution. A reduction or termination notice period of 5 years was proposed as part of the revised article. Article 14.3 has been added to provide to customers who request early contract termination the option of making a lump sum payment to the AESO, as an alternative to ongoing monthly billing. Alpac noted that the AESO had provided three reasons for requiring a 5 year notice:117

1. Transmission planning (the primary reason);118 2. Contribution policy provisions; and, 3. Tariff design and system cost recovery.

Alpac took issue with all three reasons cited by the AESO in support of their proposal. Alpac acknowledged the AESO’s responsibilities under the Transmission Regulation to forecast load but questioned what effect a reduction in load of 10 MW would have when AESO was forecasting 250MW of load growth per year over the next ten years.119 During cross-examination Alpac asked the AESO to consider the addition or loss of a 10 MW POD, which is about the average size in Alberta.120 The AESO advised changes would need to be “…tens of megawatts before there's material impact in an area.”121 Alpac noted that the five year notice provision may be justified under the current contribution policy where TFO investment in customer-related costs is partially made under the “roll-in ceiling”.122 The premise is that an amount of investment, up to $6 million, can be made without a corresponding level of revenue certainty. Under the proposed “revenue based” contribution policy, DTS revenue, via the DTS Contract Capacity, will always be proportional to the amount of TFO investment in customer-related facilities. Under the AESO’s proposed 2006 contribution

116 Section 6, page 39 117 T. 105/5-19 118 T. 105/11-14 119 T. 142/17 – 143/11 120 Exhibit 02-029-003 A - Attachment IPCAA-AESO-025 A (Attachment to IPCAA-AESO-025(a)(b)) (Feb 25,

05), Median POD Contract Capacity size is 11.5 MW 121 T. 115/15-19 & T. 144/15-23 122 Exhibit 030-004



policy, the need for a five year notice provision to protect customer-related investment was no longer required. Alpac submitted that the proposed Article 9.7 provisions, in conjunction with Alpac’s proposed two year notice period in 2006, would provide an appropriate level of revenue recovery for any customer-related TFO investment. Last, Alpac noted that with regard to the AESO’s stated need to recover system costs, that investment or contribution policies were designed for the investment in, and recovery of, customer-related costs. Alpac maintained that a significant disconnect exists between the AESO’s T&C and the T&C of three of the four Board regulated distribution companies. If an ATCO, EPCOR or ENMAX distribution customer elects to exit after the initial term of their investment related contract, Alpac pointed out that they can do so with 30 days notice. Conversely, a transmission connected customer, of similar size and vintage under the AESO’s T&C, would be subject to a five year notice provision. Alpac submitted that the AESO’s five year notice provision has imposed an unwarranted and unnecessary condition on historical investment policies and investment policy related contracts and recommended that a two year notice provision for 2006 is appropriate. Further, Alpac submitted that the need for AESO notice periods should be reviewed in greater detail in the next AESO GTA. With regard to Alpac’s specific circumstances, Alpac noted that the AESO has the ability to waive its 5 year notice123 and suggested that Alpac’s transfer from the distribution system to the transmission system would be an appropriate use of the AESO’s ability to issue a five year notice waiver. With respect to transmission system-related costs, Alpac submitted that there will be no stranded costs. Alpac’s load is simply shifting from a FortisAlberta POD to an Alpac POD. All system-related transmission assets will still be required to provide service to Alpac. More importantly, the AESO’s revenue will not be reduced – transmission DTS revenue will come from Alpac directly instead of from FortisAlberta. Additionally, a transmission connection may allow Alpac to construct additional self-generation capacity and increase the quantum of electric energy exported to the transmission grid. TCE agreed with Alpac's general comments regarding 14.2(b) and recommended that the AESO be directed to modify Article 14.2 of its T&Cs to allow a customer to reduce its contract demand at no incremental cost to the extent that: (i) the customer is prepared to sign a longer term contract and the revenues under contract are financially equivalent on a net present value basis to the previous higher volume/shorter term configuration; or (ii) no investment was originally made for the additional capacity used by the customer when determining the amount of contract demand being reduced. FIRM expressed concern the AESO has not made any assessment of whether the present notice period is adequate, particularly for larger loads. In FIRM’s view, the notice period is one of the tools used by the AESO to manage investment recovery risk associated with facility additions to serve customers. Accordingly, FIRM submitted the AESO should be directed to make an

123 Alpac Argument, page 13 and Decision 2001-34, page 176



assessment and report on the risk factors to be considered in establishing the notice period, including the relationship between load size and notice period. This assessment and report should be provided as part of the next GTA filing. FIRM also noted Article 14.3 was silent as to whether payment in lieu of notice applies in the event of termination without notice, though the AESO stated that the intent of the provision is to establish that the payment in lieu of notice would apply in the event of termination without notice. For better clarity and certainty, FIRM recommended that the requirement for payment in lieu of notice in the event of termination without notice be specifically included in the language of Article 14.3 of the T&Cs. With regard to the changes proposed by Alpac, FIRM opposed these suggested changes to the notice provisions. FIRM noted the AESO acknowledged the larger the load reduction, the larger the impact on system-related facilities and that no studies have been conducted to assess the relationship between load size and impact on notice period.124 Therefore, FIRM submitted there was no basis for reducing the notice requirement of all customers to an average of 2 years at this time without a full understanding of the factors potentially warranting a shorter notice period in some cases and a longer notice period in others. FIRM also maintained reducing the notice period without evidence the contribution policies would take care of all POD and local facilities costs caused by, and associated with, an exiting or load reducing customer would result in added risk of stranded costs for remaining customers of the AESO. FIRM submitted the AESO’s proposal to base any charges on the higher of metered demand or contract demand is a necessary deterrent to ensure the customer does not, in fact, increase load during the notice period. Accordingly, FIRM submitted the AESO’s proposal to base charges on the higher of metered demand or contract demand is appropriate. With regard to reductions or terminations in STS capacity, FIRM contended that there are financial consequences to DTS customers as a result of an STS customer exiting or reducing capacity. Accordingly, FIRM submitted the consequences for not providing adequate notice could be one of the conditions for contribution refunds to generators during the first 10 years of service. In addition, STS customers should be required to provide the required notice under provisions of the Customer System Access Service Agreement between the supply customer and the AESO. Finally, with regard to Alpac’s request for a waiver for Fortis for any load reduction at the Plamondon 353S substation, FIRM submitted there was no evidence in these proceedings to assess the costs, benefits and impact of the waiver request. Accordingly, any approval of waiver must be preceded by due process. Accordingly, the waiver request should not be approved as part of these proceedings. The AESO continued to support the need for a 5 year notice period. In Information Response ENCANA.AESO-090 (a), the AESO explained the distinction between demand ratchet periods and contract notice periods:

124 T266; L2



The DTS ratchet is a short term cost recovery tool, which recovers costs from customers that use transmission facilities in excess of their contracted capacity. The five year notice period on the other hand allows the AESO to effectively plan the transmission system. To conduct effective system planning, the AESO requires a clear understanding of how the system is being used. The highest Metered Demand during the five year notice period provides a more accurate view of the customers use and impact on the system in that area.

The AESO stated that the five-year notice for contract reductions and terminations is reasonable as it reflects the system planning horizon required for transmission facilities. The notice period is a component of the overall rate design which ensures transmission costs are recovered appropriately from customers. The Board generally agrees with the AESO regarding this issue. The Board considers that sufficient economic discipline must be placed upon customers to indicate their plans for continued use of the system. Without this discipline, the Board agrees with the AESO that it may not be able to effectively plan the system and plan it to operate efficiently. The Board sees a distinct difference between the 2 year ratchet in the DTS rate and this 5 year notice period. With the ratchet in the DTS rate, the AESO is attempting to recover what are probably the fairly modest costs of a customer exceeding their contract demand. There is some certainty, however, that this customer will continue to utilize the system and the AESO can plan accordingly. When a customer leaves the system, however, the AESO may be in the position of having made investments not only in the local system and the customer’s POD, but the bulk system as well. It would not be fair that the other customers remaining on the system should bear potential stranded costs. The Board also considers that if a party wishes to arrange a one time payout in lieu of the 5 year notice that such payout should include consideration of bulk system costs. The Board notes that in Section 5.5.1 it has unbundled the DTS rate and ruled that the ratchet should not apply to bulk system costs. As noted above, however, there is some certainty that a customer continuing to use the system as a going concern will make a contribution to the fixed costs of the bulk system. This is not the case when a customer chooses to leave the system. For purposes of calculating a one time payout, therefore, the AESO is directed in its refiling to propose a payout formula which includes consideration of bulk system costs. The Board notes that Alpac has also requested some relief from a potential flow through of AESO penalty charges to Fortis should Alpac become a direct connect customer of the AESO. The Board notes that the AESO has the discretion to waive such notice penalty charges. In this particular case, should Alpac be willing to sign a DTS contract for a term and volume equal to or greater than the contract Fortis currently has in place, the Board considers it would be reasonable for the AESO to waive penalty charges to Fortis. As Fortis is not the applicant and the Board cannot offer any direction to Fortis, the Board nonetheless considers that it would be reasonable for Fortis to flow through such a waiver to Alpac. Should any stranded costs arise, whether they accrue to the AESO or Fortis, the Board considers they should be flowed through to Alpac. 7.6 Letters of Credit Security in Respect of Construction Projects In argument, Fortis commented upon the cost to its customers of supplying letters of credit with respect to construction projects, pursuant to Article 6 of the proposed T&Cs. In Exhibit 30-035,



Fortis confirmed that Fortis customers currently face amounts in the range of hundreds of thousands of dollars per year in respect of the costs of letters of credit required of Fortis for transmission facilities construction purposes. Fortis claimed there was a public interest question to be answered. That is, given the practical realities of transmission facilities construction projects for Fortis, is the cost to Fortis customers in the range of hundreds of thousands of dollars a year in respect of construction-related letters of credit from Fortis in the broader public interest? Fortis stated the AESO confirmed that if the Board concluded that it was not, the AESO was amenable to a direction from the Board confirming that the neither the AESO, nor AltaLink on the AESO’s behalf, should require financial security such as letters of credit from Fortis in respect of construction projects. In Fortis’ submission, the practical realities on the record of this proceeding which support the Board issuing such a direction were the following:

• Cancellation of construction projects for distribution companies once such projects are sufficiently advanced as to have received Board approval under the HEE Act are so rare that the AESO panel could not recall any.

• Cancellation of construction projects that have not moved forward to the Board approval stage would involve a situation where relatively few costs would have been incurred in any event.

• In either case, in the unlikely event of project cancellation, the AESO will have obtained the contractual agreement of Fortis to be responsible for project cancellation costs.

• Fortis, as an entity whose own operations, financings and rates are regulated by this Board, may be expected to live up to a contractual obligation that has been approved by the Board as part of its regulation of the AESO tariff.

Fortis submitted that the significant costs faced by its customers in respect of the provision of letters of credit in respect of potential project cancellation costs of transmission facilities do not, on balance, advance the public interest. The costs faced by Fortis customers are real, material and ongoing, while the risk of project cancellation, and as well as ensuing default by and non-collection of, any project cancellation costs from Fortis, was approaching zero. Accordingly, Fortis submitted the Board should direct that neither the AESO, nor AltaLink acting on its behalf, should require from Fortis financial security in respect of construction projects, such as letters of credit. The Board notes the AESO did not comment upon Fortis’ concerns in its reply. The Board has reflected upon the Fortis argument and considers it to have merit. The Board does not consider it necessary or reasonable for Fortis, or its customers, to bear the costs of supplying letters of credit for construction projects at this time, given the practical realities outlined by Fortis above. 7.7 Consistency, Business Practice Documents and Other T&C Issues In argument, EnCana requested that the Board direct the AESO to ensure its T&Cs accurately reflect the Board-approved 2005/06 rate design so that inconsistencies are prevented or resolved. For example, Article 9.3 of the T&Cs contains a different definition of "System Enhancements"



than the Application.125 In addition, EnCana notes that it would be preferable to have more detail included in the T&Cs. For example, it would be useful to know which Business Practice Documents (BPD's) need to be read in conjunction with the T&Cs. EnCana noted that the AESO has proposed a number of amendments to the T&Cs which, if approved by the EUB, provide the AESO with the ability to act in its "sole discretion" or "sole opinion" in regards to specific matters.126 EnCana stated the AESO seemed to suggest that such language is required in order to provide clarity and consistency in the application of the Tariff. EnCana failed to follow such reasoning, as providing the AESO with sole discretion to act does nothing to assist customers with interpretation of the T&Cs. EnCana submitted that the inclusion of such language is both excessive and unnecessary, and ought to be removed. EnCana also noted the AESO described “business practice” documents as “…formal documents which are discussed in a public forum, reviewed and vetted and finally presented to the stakeholder community”.127 The AESO intended to rely on BPDs for its day-to-day operations yet its practice in respect of creating and disclosing BPDs was irregular and unclear. In EnCana-AESO-70(f), the AESO included a public slide presentation (Transmission Access Management in Congested Areas) and a nine-page, detailed operating document (Business Practices DOS) as BPDs that guide the AESO staff in their application of its tariff. EnCana, however, was concerned that these BPDs were not fully discussed between the AESO and the stakeholder community. EnCana maintained the Board and stakeholders should be wary of the AESO’s practice of using BPDs as a replacement for T&Cs. While EnCana recognized that, in some instances, it is appropriate for the AESO to maintain some operational flexibility or discretion in the form of BPDs, it was also important to ensure that there is sufficient scrutiny of the AESO’s practices in order to ensure customers and stakeholders are not harmed. EnCana respectfully requested that the Board establish general process guidelines for the development of BPDs. EnCana submitted the AESO should be encouraged to draft and review proposed changes with industry stakeholders before T&Cs are introduced or modified. This will provide stakeholders with an opportunity to address areas of concern with the AESO before T&Cs are actually implemented. At page 21 of their argument, EnCana proposed a process for the development of BPDs. EnCana also suggested business practice guidelines and business practice documents could apply to those areas where the AESO has requested flexibility to modify documents, other pro forma applications and areas of mixed technical and rate design matters. EnCana also submitted a partial list of such documents at page 21 of its argument. In argument128, FIRM noted that in Article 1.1 the AESO appears to propose that “force majeure” include orders or decisions of the EUB. FIRM noted a similar issue arose in the ATCO Electric (AE) Phase II proceeding and the Board stated the following:

The Board considers that the Board’s determination of an application is not a force majeure event. A utility, cannot circumvent the Board’s role in determining revenue

125 EnCana-AESO-49(d), Exhibit 02-015 126 FIRM-AESO-235 (a) -(c), Exhibit 02-015 127 EnCana-AESO-70(e), Exhibit 02-015 128 FIRM Argument, pages 112-114



requirements or other findings by invoking the force majeure terms and conditions of their contract not to provide safe and reliable service.

FIRM recommended the AESO be directed to specifically exclude the Board from the definition of force majeure in Article 1.1 and incorporate language similar to that ordered in the AML (AltaLink) and AE proceedings. FIRM noted that there were a number of instances in the proposed T&Cs where the AESO had not used the words “acting reasonably” to limit the use of its sole discretion. FIRM submitted requiring the AESO to “act reasonably” in exercising its discretion and opinions is fair, responsible and, of course, reasonable. Accordingly, FIRM submitted the following clause should be added to the T&Cs:

Where a party is granted any discretion pursuant to these T&C's (whether with respect to granting its consent or withholding its consent to a particular matter or otherwise), such party will, in every instance, exercise its discretion acting reasonably.

Finally, FIRM noted that in proposed Article 9.7(e) of the T&Cs, dealing with adjustments to customer contributions, the AESO had reserved the right to adjust a contribution when it deemed there to be a material difference between the actual and estimated costs of a project. FIRM submitted the Board should direct the AESO to provide some quantification around the word “material” as used in Article 9(e) of the T&Cs. Customers should be entitled to know that below a certain dollar amount, the Customer Contribution will not be adjusted. It would also assist customers to know the specific criteria the AESO must follow when exercising its discretion to adjust the Customer Contribution in determining a “material difference” between actual and estimated project costs. In reply, FIRM noted the comments of EnCana and stated that in Decision 2005-025, respecting Atco Electric's (AE) Phase II, the Board noted AE’s Customer Guide was a reference manual provided to customers and not filed with the Board for approval.129 The Board also stated the Customer Guide could more clearly communicate the intent of AE since it is “provided as an aid to customers in their dealings with AE”.130 Since the Customer Guide (like the BPD) is not approved by the Board, the “status of the Customer Guide” must be “clear in the event of a dispute between AE and a customer”.131 In its direction, for the utility, the Board required132 AE to reword s. 4.1(a) of the T&Cs to ensure it indicated the purpose of the Customer Guide and the fact is non-binding. FIRM submitted wording similar to that ordered in the AE proceeding should be used for the AESO BPD. In FIRM’s submission, this would assist all parties and help address the concerns raised by EnCana. In reply, the AESO stated, as outlined in Information Response ENCANA.AESO-070 (a-i), that the AESO has several forms of documentation that are developed and utilized in the normal course of business. That information response also refers to a high level process outlining when and where stakeholders are involved and when documents are communicated. The AESO submitted the process detail as outlined in the information response is adequate and does not require further consideration from the Board.

129 Decision 2005-025, page 48 130 Decision 2005-025, page 48 131 Decision 2005-025, page 49 132 Decision 2005-025, page 49



The AESO noted that EnCana also stated that more detail is required in the terms and conditions to ensure clear and consistent application of the tariff. The AESO submitted the current terms and conditions provided a good balance of detail and clarity and should be approved as filed at this time. The AESO also noted FIRM suggested that a number of Articles in the terms and conditions should be modified to include the term “acting reasonably”. The AESO submitted this was not necessary, as the AESO’s duty to act fairly and responsibly is set forth in section 16 of the EUA, and therefore applies to all aspects of the terms and conditions. With regard to FIRM’s suggestion that the word “material” in Article 9.7 be quantified, the AESO submitted that the review of contribution calculations and the financial implications varies by project making it difficult to establish a specific materiality threshold. As well, the AESO would need to complete an adjustment review and calculation to determine if a specific materiality threshold was exceeded, which would result in additional administration cost even in those circumstances when an adjustment was not warranted. The AESO therefore recommended that judgments of materiality continue to be appropriate to determine when contribution recalculations are required. With respect to EnCana’s suggestion that the AESO engage in more consultation around changes to the T&Cs, the Board does not think such direction is necessary. The Board notes that the AESO consults with its stakeholders on a regular basis and considers this to be sufficient. The Board notes EnCana’s comments upon the use of the term “sole discretion” and “sole opinion” while FIRM comments upon the need to “act reasonably”. The Board considers that the AESO has a need to retain a certain degree of flexibility in its day to day dealings with its customers however, as the AESO has noted, this ability is not unfettered. The Board agrees with FIRM’s suggestion that a clause be added to the T&Cs as set forth above and directs the AESO to amend its T&Cs accordingly. The Board also considers, however, that when a customer enters into a contract with the AESO, the customer should have some certainty around what their rights and responsibilities are. Customers commit themselves to payment of significant amounts of money through monthly demand billings. The Board considers it reasonable that a customer should be able to determine their rights and responsibilities from the T&Cs and any relevant pro-forma documents attached thereto. Therefore, the Board directs the AESO in its refiling to review its T&Cs to ensure that customers’ rights and responsibilities are clearly spelled out and the appropriate pro-forma contracts are attached. The Board also directs the AESO to clarify in its BPDs, as suggested by FIRM, that customers’ rights and responsibilities are spelled out in the T&Cs. With respect to FIRM’s request that Article 9.7(e) be amended to give more clarity, the Board agrees with the AESO that some degree of flexibility is required regarding the recalculation of contributions and hence will not direct any change at this time. Finally, the Board notes FIRM’s suggestion that Article 1.1, regarding “force majeure”, be amended such that Board orders and decisions do not qualify as force majeure items. The Board agrees with FIRM, for the reasons stated in the AML and ATCO Phase II decisions, and therefore directs the AESO to amend the T&Cs accordingly.



8 OTHER MATTERS

8.1 Disposition of Outstanding Board Directions The AESO provided progress updates with respect to outstanding Board directions in sections 4, 6, and 9 of the Application. The Board directions discussed in Section 4 of the Application related primarily to cost of service studies ordered in Decision 2001-32, the potential use of out-of-merit dispatch to support exports and directions related to the provision of credits for customer owned transmission facilities. The Board directions discussed in Section 6 related to proposed changes to T&Cs in relation to the AESO’s contribution policy and liability management practices. All other outstanding Board directions are discussed in Section 9 of the Application. The AESO provided a chronological list of the outstanding Board directions in matrix format in Section 9.10 of the Application. In light of the large number of responses to outstanding matters provided in the Application, the AESO requested that the Board confirm, specifically or by exception, its acceptance of the AESO’s responses to the outstanding Board directions. The Board sought additional clarification about the specific disposition sought by the AESO in relation to each of outstanding directions listed in the Section 9.10 matrix. The AESO provided a comprehensive response to the Board’s request in its response to information request BR-AESO-47. Although a subject heading for Outstanding Board Directions was identified in the argument outline provided to parties by the Board at the close of the oral portion of the hearing, only a small subset of the outstanding directions list was addressed by parties in argument as follows:

• A number of parties, including ATCO Power, the FIRM Group, IPPSA, and TCE, referenced the Board direction in Decision 2002-099 to investigate the possibility of providing of a form of firm import/export service over the Alberta/BC intertie;

• The Cities of Lethbridge and Red Deer and TCE referenced directions from Decision 2001-6 requiring the AESO’s predecessor to establish reliability objectives for the transmission system in conjunction with TFOs and other customers; and,

• TAU sought to have the AESO take further steps to advance the establishment of a reactive power market, pursuant to Appendix 4 of the AESO’s July 4, 2003 Negotiated Settlement Agreement.

The Board notes that the directions related to firm export/import service and reliability objectives have already been addressed in Sections 5.7.1 and 6.1.3 respectively in this Decision. With respect to TAU’s desire to advance a reactive power market, the Board considers that this matter relates primarily to issues of market design and system reliability. As such the Board considers that this issue should more properly be pursued by TAU as an AESO rule matter pursuant to Section 20 of the EUA rather than in the context of the AESO’s tariff. Accordingly, the Board does not consider that it is necessary to provide additional direction to the AESO relative to the 2003 negotiated settlement matter undertaking identified by TAU. The Board considers that it is unnecessary to require the AESO to continue to provide progress reports on the large majority of the outstanding Board directions not referenced in the preceding paragraph. For instance, the Board notes that several status updates provided in the AESO’s



response to BR-AESO-47 relate to required actions that the AESO has already carried out. Of even greater concern to the Board, however, is that many of the outstanding Board directions listed by the AESO were originally prescribed in Board decisions that did not contemplate the significant changes in industry structure that have occurred in the intervening years, thereby rendering some outstanding Board directions largely irrelevant. Given this, the Board considers, at this time, that the AESO should generally start with a “clean slate”. In light of this clean slate approach, the Board has reviewed all of the outstanding Board directions referenced in the AESO’s BR-AESO-47 for ongoing relevance. As a result of this review, the Board hereby rules that the AESO’s should only have ongoing obligations with respect to the following directions: Decision Direction Required Action 2003 NS Item (1) Para- 21

All future AESO GTA filings will include for all revenue requirement line category amounts (including but not limited AESO Costs) and revenue offset categories, a description of:

• the current level of actual costs incurred in the two prior years (if applicable, the AESO’s forecast estimate of costs to be incurred in the remainder of the immediate prior year at the time of the filing of the GTA)

• forecast estimate of costs be incurred in the test year

• an explanation of any variance between the test year forecast amounts and the projected final amounts the two prior years.

Requirement continued as ongoing obligation. Direction wording updated to reflect changes in applicable terminology occurring since the issuance of the original Board direction.

2001-21-1 The Board directs the AESO to provide the following information at the next GTA, and all future GTAs unless otherwise directed by the Board:

• A management discussion section that addresses its diligence in controlling each of the major cost categories,

• A line by line breakout in the cost summary for the following items for two previous years of actuals, forecast for the year in which the application was submitted, and the forecast for the year being applied for:

• Adequate justification for capital budget items including the economics of projects which formed the basis of need

• Adequate explanations for variances between forecast and actual costs and revenues.

Reporting requirement generally continued as ongoing obligation, with some wording in the direction wording updated to reflect changes in applicable terminology that have occurred since the issuance of the original Board direction as well as the removal of reporting requirements not relevant to the AESO as a non-profit entity.

2001-21-12 Accordingly, the Board directs the AESO at its next GTA to include insurance cover note(s) annually, as long as this will not jeopardize the competitive procurement of insurance policies by the AESO.

Requirement continued as ongoing obligation. Wording of direction updated to reflect changes in applicable terminology occurring since the issuance of the original Board direction.

2001-17-6 The Board directs the AESO to report the amount of any amounts received from a

Reporting requirement continued as ongoing obligation. Wording of direction updated to reflect



generation facility owner (GFO) pursuant to an LBC SO Entitlement offer and to consider such amounts as a offset to the forecast revenue requirement of future general tariff applications in respect of years in which the AESO may be receiving such revenue from a GFO.

changes in applicable terminology occurring since the issuance of the original Board direction.

2001-15-2

The Board directs the AESO to file with the Board, at the conclusion of each fiscal year, the total number of times conscripted ancillary services were procured as well as the total cost incurred. The number and length of occurrences by payment option and the total cost by payment option should be included. At the time of filing a GTA, the AESO should provide a forecast of conscripted ancillary services costs as part of its forecast of overall ancillary services costs.

Reporting requirement continued as ongoing obligation. Direction wording updated to reflect changes in applicable terminology occurring since the issuance of the original Board direction.

2001-13-7 In order to understand the performance of GFOs and the AESO, the Board directs AESO in all future GTAs for the term of the LBC SO contracts to report on any occurrences where the GFO exceeded the maximum time to commercial operation requirement.

Reporting requirement continued as ongoing obligation. Direction wording updated to reflect changes in applicable terminology occurring since the issuance of the original Board direction.

Although not specifically referenced in the above noted outstanding Board directions exceptions list, the Board considers that certain of the outstanding Board directions described in the AESO’s response to BR-AESO-47 require further discussion as follows:

1. Firstly, the Board notes that BR-AESO-47 provides a status update on Board direction 2002-103-8 which required the AESO’s predecessor to develop a Proxy Unit Capacity Payment and a Proxy Unit Operating Cost Payment option for inclusion within the (then) Article 24 of the Tariff Terms and Conditions. The Board notes that the manner in which the AESO has fulfilled the requirements of this direction has been raised as a matter for dispute within the Application 1357161 proceeding, which is still before the Board. Further to the Board’s advice to parties in Board correspondence dated December 16, 2004, the Board considers that ongoing requirements pursuant to any outstanding directives arising from Decision 2002-103, including direction 2002-103-8, should be dealt with in the context of the Application 1357161 (Article 24) proceeding.

2. Secondly, the Board notes that while a progress report was included in the AESO’s

response to BR-AESO-47, direction 2003-071-35 created an obligation for ATCO Electric rather than an obligation for the AESO. The Board notes that the information provided by the AESO in relation to this direction indicated the amount by which the AESO’s interest expense would increase if the payment schedule for ATCO Electric TFO wires charges were to be advanced as contemplated in the direction. However, the information provided by the AESO does address the extent to which ATCO Electric’s costs and hence the amount of ATCO Electric’s wires charge to the AESO would decrease and thus does not address the fundamental question of whether a change in the TFO wires charge payment schedule would result in a net increase or decrease in the costs flowed through to the AESO’s customers and end-use customers. Accordingly, the Board considers that direction 2003-071-35 remains an obligation for ATCO Electric



which should be assessed in light of forecast interest cost increase projected by the AESO.133

9 REFILING OF APPLICATION

The Board directs the AESO to re-file its Application on or before October 1, 2005. The Board also directs the AESO, in its refiling, to provide a summary that sets out a detailed reconciliation of the revenue requirements requested in its Application to the revenue requirements approved by the Board in this Decision. Parties wishing to provide comment on the AESO’s refiling should do so by October 15, 2005. 10 ORDER

For and subject to the reasons set out in this Decision, IT IS HEREBY ORDERED THAT: (1) The AESO shall refile its 2005 and 2006 General Tariff Application to reflect the

findings, conclusions and directions in this Decision by October 1, 2005. Dated in Calgary, Alberta on August 28, 2005. ALBERTA ENERGY AND UTILITIES BOARD (original signed by) R. G. Lock, P.Eng. Presiding Member (original signed by) J. I. Douglas, FCA Member (original signed by) M. W. Edwards Acting Member

133 The Board notes that while ATCO Electric directed the Board to turn its attention to this issue in

correspondence addressed to the Board dated December 17, 2004 (Exhibit 07-001), ATCO Electric did not pursue this issue further in either its argument or reply.



APPENDIX A – RATE DESIGN SPREADSHEET

Appendix A.xls

(consists of 10 pages)

2005/2006 General Tariff ApplicationAlberta Electric System Operator

Appendix A

Rate Design

Pure Cost Allocation from Cost Causation Study

Function Demand Usage Customer TotalBulk System 117.9 26.7 0 144.6Local System 49.7 10.5 0 60.2POD 63.7 1 83.1 147.8Total 231.3 38.2 83.1 352.6

AESO suggested reduction to Bulk Demand Allocation, and Board Retention of Pure Customer Cost Allocation

Function Demand Usage Customer Total Demand Usage Customer TotalBulk System * 86.7 57.9 0 144.6 24.6% 16.4% 0.0% 41.0%Local System 49.7 10.5 0 60.2 14.1% 3.0% 0.0% 17.1%POD 63.7 1 83.1 147.8 18.1% 0.3% 23.6% 41.9%Total 200.1 69.4 83.1 352.6 56.7% 19.7% 23.6% 100.0%

* AESO recommended that 73.5% of Pure Cost Allocation Bulk System Demand Cost be used (Section 4, page 6 of application)see Table 4.2.3, and lines 35-41, the AESO generally endorses this level of usage cost allocation, absent the transfer of STS costs to Load customers

Classification

Classification Allocation

EUB Decision 2005-096 (August 28, 2005)


Appendix A

Alberta Electric System Operator Section B — Rate Calculations2006 General Tariff Application Schedule Boar

January 31, 20052006 Rate Calculations

Demand Transmission Service Costs Classified to Demand, Usage, and Fixed

A B C D E F G

DTS Classification to Rate ComponentAmount Demand Flat Usage Varying Usage Fixed

LineNo. Description

[5.1 Col C]$ 000 000

Allocator%

Amount$ 000 000

Allocator%

Amount$ 000 000

Allocator%

Amount$ 000 000

Allocator%

Amount$ 000 000

1 Wires 405.5$ 56.7% 230.0$ 19.7% 79.9$ -$ 23.6% 95.6$

2 Ancillary Services3 Operating Reserves 85.3$ - -$ - -$ 100.0% 85.3$ - -$ 4 Other Ancillary Services5 Generator Remedial Action Schemes 0.4 - - - - 100.0% 0.4 - - 6 Black Start 2.3 - - - - 100.0% 2.3 - - 7 Transmission Must Run (TMR) 53.2 - - 100.0% 53.2 - - - - 8 Under Frequency Mitigation 6.9 100.0% 6.9 - - - - - - 9 Poplar Hill 1.9 100.0% 1.9 - - - - - -

10 ILRAS 0.5 56.7% 0.3 19.7% 0.1 - 23.6% 0.1 11 Total Ancillary Services 150.6$ 6.0% 9.1$ 35.4% 53.3$ 58.5% 88.0$ 0.1% 0.1$

12 Losses - - - - - - - - -

13 Other Industry 7.8$ 56.7% 4.4$ 19.7% 1.5$ -$ 23.6% 1.8$

14 General and Administrative 30.1$ 56.7% 17.1$ 19.7% 5.9$ -$ 23.6% 7.1$

15 Total Revenue Requirement 593.9$ 43.9% 260.6$ 23.7% 140.6$ 14.8% 88.0$ 17.6% 104.6$ 16 DTS Tariff Revenue Offsets (30.5) 56.7% (17.3) 19.7% (6.0) -$ 23.6% (7.2)$ 17 Net DTS Revenue Requirement 563.4$ 43.2% 243.3$ 23.9% 134.6$ 15.6% 88.0$ 17.3% 97.4$



Appendix A

Alberta Electric System Operator2006 General Tariff Application

2006 Rate CalculationsDemand Transmission Service Rate Calculation

A B C D E F G H I J K L

Demand Component Flat Usage Component Varying Usage Component Fixed

LineNo. Description

Sch 5.3 Reference

Amount[5.3 Col C]$ 000 000

Determinant[5.7 Col A]

MW-months

Rate[A ÷ B]$/MW

Amount[5.3 Col E]$ 000 000


GWh

Rate[D ÷ E]$/MWh

Amount[5.3 Col G]$ 000 000


GWh

% of PP[G ÷ H×PP]

(Note 1)

Amount[5.3 Col G]$ 000 000

Determinant

[5.7 Col A]POD - months

Rate[J ÷ K]$/POD

1 DTS Interconnection Charge2 Wires Line 1 230.0$ 79.9$ - 95.6 3 Other Industry Line 13 4.4 1.5 - 1.8 4 General and Administrative Line 14 17.1 5.9 - 7.1 5 ILRAS Line 10 - 0.1 - 0.1 6 DTS Tariff Revenue Offsets Line 16 (17.3) (6.0) - (7.2) 7 DTS Interconnection Charge 234.2$ 114,716.8 2,041.89$ 81.4$ 54,292.7 1.50$ 97.4 5,808.0 16,775

8 DTS Operating Reserve Charge9 Operating Reserves Line 3 - - 85.3$ -$

10 Generator Remedial Action Schemes Line 5 - - 0.4 - 11 Black Start Line 6 - - 2.3 - 12 DTS Operating Reserve Charge - - - - 88.0$ 54,292.7 3.87% -$

13 Voltage Control (TMR) Charge Line 7 - - - 53.2$ 54,292.7 0.98$ -$ - - -$ - -

14 DTS Other System Support Services Charge15 Under Frequency Mitigation Line 8 6.9$ - - - 16 Poplar Hill Line 9 1.9 - - - 17 ILRAS Line 10 0.3 - - - 18 DTS OSS Services Charge 9.1$ 114,716.8 79.02$ - - - - - - - - -

19 Total DTS Tariff 243.3$ 114,716.8 2,120.91$ 134.6$ 54,292.7 2.48$ 88.0$ 54,292.7 3.87% 97.4$ 16,775

Note: The 2006 forecast pool price is $41.93/MWh



Appendix A

Alberta Electric System Operator Section B — Rate Calculations2006 General Tariff Application Schedule Boar

January 31, 20052006 Rate Calculations

2006 Billing Determinants

A B C D

Line DTS Customers STS CustomersNo. Description Determinant Unit Determinant Unit

1 DTS Billing Capacity 114,716.8 MW-months —

2 Metered Energy (All Hours) 54,292.7 GWh 58,606.1 GWh

3 Pool Price $41.93 /MWh $41.93 /MWh

4 RGU Maximum Continuous Rating (MCR) — 77,941.2 MW-months

5 POD Months 5,808.0 POD Months

Note: Pool Price is the average hourly pool price weighted by DTS usage volumes



Appendix A

Rate Shock Analysis with Line LossesExisting AESO Rates at June 13, 2005 (Interim rates approved January 1, 2005)DTS

Interconnection 1365.66 /MW/Month1.96 /MW.h

Operating Reserve 2.95% * Pool Price * energy per hour (assume $41.93/MW.h pool price)Other System Support 22.40 /MW/Month

STS

Interconnection 2.62 /MW.h 365 /MW RGUCC

Losses Loss factor * Pool Price * energy per hour (assume $41.93/MW.h pool price and 5.06% losses)Operating Reserve 2.77% * Pool Price * energy per hour (assume $41.93/MW.h pool price)

Board Proposed Rate Design

DTS


16,775 /POD/MonthOperating Reserve 3.87% * Pool Price * energy per hour (assume $41.93/MW.h pool price)

0.98 /MW.hOther System Support 79.02 /MW/Month

AESO STS Rate Design

STS

Interconnection 323 /MWLosses Loss factor * Pool Price * energy per hour (assume $41.93/MW.h pool price and 5.06% losses)

Scenario 1. Dual Use Customer. 5 MW Load. 10% LF. 90 MW Generation, 40% Generation LF



Appendix A

Billing Determinants

Demand Energy CustomerMW MW.h (POD)

DTS 5 365 1STS 90 26,280 1

Bill ComparisonTotal

Existing DTS 6,940 1,167 0 8,107Existing STS 32,850 155,134 0 187,984Total 39,790 156,301 0 196,091Board Proposed DTS 10,605 1,497 16,775 28,877AESO Proposed STS 29,070 55,757 0 84,827Total 39,675 57,255 16,775 113,704



Appendix A

Rate Shock Analysis with No Line LossesExisting AESO Rates at June 13, 2005 (Interim rates approved January 1, 2005)DTS


Operating Reserve 2.95% * Pool Price * energy per hour (assume $41.93/MW.h pool price)Other System Support 22.40 /MW/Month

STS

Interconnection 2.62 /MW.h365 /MW RGUCC

Losses Loss factor * Pool Price * energy per hour (assume $41.93/MW.h pool price and 5.06% losses)Operating Reserve 2.77% * Pool Price * energy per hour (assume $41.93/MW.h pool price)

Board Proposed Rate Design

DTS


16,775 /POD/MonthOperating Reserve 3.87% * Pool Price * energy per hour (assume $41.93/MW.h pool price)

0.98 /MW.hOther System Support 79.02 /MW/Month

AESO STS Rate Design

STS

Interconnection 323 /MWLosses Loss factor * Pool Price * energy per hour (assume $41.93/MW.h pool price and 5.06% losses)

Scenario 1. Dual Use Customer. 5 MW Load. 10% LF. 90 MW Generation, 40% Generation LF



Appendix A

Billing Determinants

Demand Energy CustomerMW MW.h (POD)

DTS 5 365 1STS 90 26,280 1

Bill ComparisonTotal

Existing DTS 6,940 1,167 0 8,107Existing STS 32,850 99,377 0 132,227Total 39,790 100,544 0 140,334Board Proposed DTS 10,605 1,497 16,775 28,877AESO Proposed STS 29,070 0 0 29,070Total 39,675 1,497 16,775 57,947



Appendix A

Alberta Electric System Operator Exhibit ______030-026_________AESO 2005-2006 General Tariff Application (1363012) April 15, 2005

Undertaking by Mr. Martin to Ms. WallComparison of Bills for Proposed Rates Based on 80% Demand Classification

1999 Interim Tariff (Effective January 1, 1999) 2006 Rates Based on 80% Demand Classification Amended to Include Customer Charge (based upon rate factors of previous page)

Description Unit Amount Description Unit Amount

Grid Interconnection Service Demand Transmission ServiceCapacity $/MW $1,879 Interconnection Capaci $/MW $2,879.07

Interconnection Energy $/MWh $1.52Grid Standard Service Operating Reserve % × PP 3.87%On-Peak T$/MW × TF $3,049 Voltage Control $/MWh $0.98Transmission Losses and Constraint Charges Other System Support $/MW $80.13On-Peak E $/MWh $1.34On-Peak E % × PP 5.08%Off-Peak E $/MWh $0.91Off Peak E % × PP 3.40%

On-Peak P $/MWh $54.86 Pool Price $/MWh $41.93Off-Peak P $/MWh $33.50

Charges ChargesCapacity $/MW $1,879 Interconnection Capaci $/MW $2,879.07On-Peak T$/MW × TF $3,049 Interconnection Energy $/MWh $1.52On-Peak E $/MWh $1.34 Operating Reserve $/MWh $1.62On-Peak E $/MWh $2.79 Voltage Control $/MWh $0.98Off-Peak E $/MWh $0.91 Other System Support $/MW $80.13Off Peak E $/MWh $1.14

Aggregate Charges Aggregate ChargesCapacity $/MW $1,879 Capacity $/MW $2,959.20On-Peak T$/MW × TF $3,049 Energy $/MWh $4.12On-Peak E $/MWh $4.13Off-Peak E $/MWh $2.05

Billing Quantities 10% LF 90% LF Billing Quantities 10% LF 90% LF 10% LF 90% LF



Appendix ALoad MW 5 5 Load MW 5 5 5 5On-Peak T % 20% 100% Load Factor % 10% 90% 10% 90%Load Facto % 10% 90% Energy MWh 360 3,240 360 3,240Energy MWh 360 3,240On-Peak F % 79% 44%On-Peak E MWh 286 1,430Off-Peak E MWh 74 1,810

Aggregate Bill Aggregate Bill Customer 16775 16775Demand $ $9,395 $9,395 Demand $ $14,796 $14,796 Demand 10605 10605On-Peak T $ $3,049 $15,245 Energy $ $1,485 $13,364 Energy 1485 13364On-Peak E $ $1,180 $5,901 Total $ $16,281 $28,160 28865 40744Off-Peak E $ $152 $3,709Total $ $13,776 $34,250 Increase (Decrease) % 18% (18%)

Total Bill Including Commodity Total Bill Including CommodityCommodity $ $18,169 $139,085 Commodity $ $18,169 $139,085 18169 139085Total Bill $ $31,945 $173,335 Total Bill $ $34,450 $167,244 47034 179829

Increase (Decrease) % 8% (4%) 47% 4%




APPENDIX 1 – HEARING PARTICIPANTS

Principals and Representatives (Abbreviations Used in Report)

Witnesses

Alberta Electric System Operator (AESO) J.H. Smellie, Esq. G.M. Nettleton, Esq.

J. Martin, P.Eng. N. Millar, P.Eng. C. Moline, C.A. C. Monar, P. Eng, MBA J. Mossing A. Reimer, P. Eng.

Aboriginal Communities (ABCOM) J. Graves

Alberta Direct Connect Consumer Association (ADC) R.C. Secord, Esq.

A. Rosenberg, Ph.D D. Sullivan L. Doig, P. Eng, MBA

Alberta Pacific Forest Projects (Alpac) W.D. Hildebrand

Alberta Urban Municipalities Association (AUMA) C. R. McCreary, Esq.

Alberta Irrigation Projects Association (AIPA) J.H. Unryn

AltaLink Management Ltd. (AML) H.D. Williamson, QC.

ATCO Electric Limited (AE) L. G. Keough, Esq. K.Beattie, Ms.

British Columbia Hydro and Power Authority (BCH) C. H. Sanderson, Esq. K. Hughes, Ms.

Richard Stout, P. Eng., MBA

Cities of Lethbridge and Red Deer (Cities) K.L. Hurlburt, Ms.

Consumers’ Coalition of Alberta (CCA) J. A. Wachowich, Esq.

COS Coalition (COSC) 134, M. Forster, Esq.

W.D. Hildebrand, P. Eng., MBA

Enbridge Pipelines Inc. (Enbridge) A. Kerkovius, Esq.

EnCana Corporation (EnCana) L.B. Ho, Ms. D.G. Davies, Esq.

134 COS Coalition comprises: Air Liquide, ATCO Power, Calpine Canada, City of Medicine Hat, Canadian Natural

Resources Limited, EnCana Corporation, Imperial Oil, Petro Canada, Shell Canada Ltd and Shell Canada Products, Suncor Energy.



Principals and Representatives (Abbreviations Used in Report)

Witnesses

EPCOR Utilities Inc. (EPCOR) D. Crowther, Esq.

FIRM Group (FIRM)135 N. McKenzie, Esq.

FortisAlberta Inc. (Fortis) T. Dalgleish, Q.C.

Industrial Power Consumers Association of Alberta (IPCAA) M. Forster, Esq.

M. Drazen, P. Eng. D. Macnamara, Esq. R. Gallant (Electrical Technologist) R. Mikkelsen, P. Eng, MBA

Powerex (PWX) C. H. Sanderson, Esq. K. Hughes, Esq.

Public Institutional Consumers of Alberta (PICA) N.J. McKenzie, Ms

TransAlta Utilities Corporation (TAU) T. Dalgleish, Q.C.

TransCanada Energy Ltd. (TCE) A. Ross, Esq.

D. Levson, P. Eng. L. Sibbald, P. Eng.

Utilities Consumer Advocate D. Gray

Alberta Energy and Utilities Board Board Panel

R. G. Lock, P. Eng., Presiding Member J. I. Douglas, FCA, Member M. W. Edwards, Acting Member

Board Staff C. Wall, Board Counsel J. Cameron, CGA D. Ploof J. Halls

135 FIRM Group comprises: Alberta Association of Municipal Districts and Counties (AAMD&C), Alberta

Federation of Rural Electrification Associations (AFREA), Alberta Irrigation Projects Association (AIPA), Consumers' Coalition of Alberta (CCA), Alberta Urban Municipalities Association (AUMA), Public Institutional Consumers of Alberta (PICA)



APPENDIX 2 – SUMMARY OF BOARD DIRECTIONS

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

1. As stated above, the Board notes that the incentive parameters for 2005 are still not available for Board review. The Board also notes that in other utility decisions, such as 2005-019 dealing with AltaLink’s revenue requirement, the Board has denied amounts for incentive payments even though they were supported by detailed discussion of payout parameters. The Board does not consider that it can reasonably approve a revenue requirement for this item when the AESO cannot identify to stakeholders either the amount proposed for incentives or the parameters to be used in measuring performance. The Board directs the AESO to exclude from its revenue requirement and collection through the deferral account process any amounts related to employee incentive payments. ................................................................... 3

2. In the event that the AESO does not take action either to voluntarily remove notionally denied costs from its revenue requirement or to convince the Board that these costs are prudent and appropriate, the Board may consider an actual disallowance of some or all of these costs. In the event of such disallowance and where the AESO has not provided the necessary justification, the AESO shall not seek to recover these costs in any fashion from its customers through regulated activities...................................................................................... 4

3. The Board notes that the AESO has engaged in a consultative process with its stakeholders and expects that this process will lead to more timely filings of its own costs in the future. With respect to the 2006 placeholder, the Board notes that own costs are a very small portion of the total revenue requirement. The Board does not, therefore, consider it necessary to have a special process later this year to review a final 2006 own cost proposal. The Board notes the AESO has also stated that it will provide the EUB and interveners with explanations and justifications for any variances to its 2006 own costs. The Board will accept the placeholder and notes that prudent variances from forecast will be trued up through the deferral account process. As with 2005, however, the Board directs the AESO to remove employee incentive payments until the relevant amount and acceptable performance criteria are identified.......... 5

4. The AESO has stated it is a non-profit organization and simply does not have the means to employ highly specialized staff in order to forecast commodity prices when another credible source is readily available. The Board is concerned that the EDC information was unable to be disclosed in such a manner as to understand its basis and concludes that an understanding of such information would be helpful in that these forecasts provide the AESO with a foundation for its tariff structure. To that end, the Board directs the AESO at the time of its next GTA to assess the business case for developing its own view on such a forecast using its knowledge of external information and its operating knowledge............................................. 7

5. The Board therefore directs the AESO, in its refiling, to unbundle the wires portion of the DTS rate into bulk, local and POD segments. The Board notes this is necessary to facilitate the cost allocation decided upon below. ................................................................................. 26

6. As a summary of the above findings the AESO, in its refiling, is directed to amend its DTS rate design as follows:............................................................................................................. 29 • 20% of all wires costs will be collected on an all hours energy basis ..................................



• Levy a customer-related POD charge, as suggested in the TCCS........................................ • Levy a demand charge on bulk wires utilizing a 12 CP allocator ........................................ • Levy a demand charge on local and POD related costs utilizing an NCP allocator. ............

7. The Board has determined that the following should form the basis for charges to BCH for Fort Nelson services. DTS service charges should include the following:............................. 33 1. the postage stamp rate for bulk wires costs; ......................................................................... 2. the greater of the postage stamp rate for local wires costs or the actual cost of the AE line

providing service to Fort Nelson; ......................................................................................... 3. the postage stamp rate for the AESO’s own costs and other industry costs; and ................. 4. the postage stamp rates for each of operating reserve charges, voltage control (TMR) and

other system support charges. ...............................................................................................

8. The Board notes that no parties commented against the AESO’s proposed modification to these two rates. The Board has reviewed the proposed modifications and considers them to be in compliance with the changes required by the Transmission Regulation as noted above and therefore approves the AESO’s proposed modifications to these rates. The Board directs the AESO to update its proposals accordingly in its refiling, using the values which result from the Board’s recommended rate design, as discussed in section 5.5 of this Decision..... 37

9. FIRM proposed a credit of $200/MW/month. This proposal is based upon actual costs customers have paid for all their transformation requirements, including the generation related requirements of dual use customers. The Board does not consider this to be appropriate. As stated above, this is not the basis of the DTS revenues that are being credited back to the customers. The Board does note, however, that the actual average of the three sample configurations provided by the AESO is $660/MW/month, somewhat less than their proposed credit. The Board considers that this is a more appropriate amount to credit customers to maintain neutrality between self supply and system supply. The Board directs the AESO to use this amount for the calculation of future PSC Credits. The Board is willing to entertain adjustments in the future to reflect changes in costs over time. .......................... 39

10. The Board finds that the treatment proposed by the COS Coalition is reasonable. The AESO is directed to amend the wording of its proposed PSC Credit accordingly. Subject to this direction, and the change in the amount of the credit referenced above, the PSC credit is approved.................................................................................................................................. 40

11. While the Board notes that there are currently no customers using the DOS 1 hour rate the Board agrees with the interveners that there may be merit in retaining the availability of the rate. The Board considers that opportunity rates should be reasonably flexible so as to maximize their revenues and consequent contribution to overall costs. The Board also does not consider there to be any material administrative burden to retaining the rates. Therefore the Board directs the AESO to retain the DOS 1 hour rate. The other opportunity rates are approved as filed. .................................................................................................................... 41

12. With respect to the request of AE that the Board should provide clear directions respecting the classification of system and customer costs, the Board considers that the AESO should approach any situation in which there may be “shades of grey” in this designation exercise, with the position that a debatable interconnection project cost should be presumed initially to be customer-related unless clearly demonstrated otherwise................................................... 49

13. Notwithstanding the Board’s suggestion to review the merits of a non-linear maximum investment function and provide its findings at the next GRA, the Board notes that the notion of a non-linear function was discussed only at a conceptual level during the Application



proceeding. As such, the Board considers that a linear maximum investment function must continue to be utilized in the short term. Accordingly, the Board hereby directs the AESO to amend Article 9.4 of the Terms and Conditions proposed for the Application such that a minimum investment allowance reflects: ............................................................................... 57 • A minimum investment allowance of $2.5 million; and....................................................... • An additional investment of $100,000 per MW of project capacity.....................................

14. In light of this finding, the Board considers that it is still necessary to maintain the dual-use formula to ensure that AESO customers that are primarily generators are not able to gain an effective exemption from the clear policy intent of the Government’s Transmission Policy and the Transmission Regulation whereby generators are to pay for their local interconnection costs. Accordingly, the Board hereby directs the AESO, in its refiling, to re-instate the dual-use formula as described in Article 9.3 of T&Cs of the currently approved tariff. The Board considers that alterations to the wording of the dual-use clause should only be done for the purposes of maintaining consistent numbering and references to other parts of the AESO’s T&Cs................................................................................................................... 61

15. The Board notes that no parties opposed the proposal to permit the staging of load levels for the purposes of determining maximum investment allowances. The Board likewise supports and approves this proposal. However, the Board notes that the proposal to permit load staging in the determination of available investment is not specifically described in the AESO’s proposed Article 9.4 or elsewhere in the AESO’s Article 9 contribution policy T&Cs. As such, the Board shares the concern of FIRM respecting the obligation of a customer to provide a refund if the staging assumptions used initially do not materialize. Accordingly, the Board hereby directs the AESO to propose a specific additional provision of Article 9 which more specifically describes the consideration of staged loads for both investment allowance and refund determination purposes with its refiling Application........ 62

16. The Board agrees, however, that a full customer contribution should be required in respect of the difference in cost between a lower cost distribution option and the selected transmission option. Accordingly, the Board directs the AESO to amend Article 9.1 to reflect the Board’s above noted findings as part of its refiling.............................................................................. 63

17. In light of the above noted findings, the Board considers that Article 9.8 must be amended. Accordingly, the Board directs that, in its refiling, the AESO provide a revised version of Article 9.8 based on the wording of the existing Tariff’s Article 9.8. The proposed revision should exclude current sub-Articles (a)(i) and (ii) as they are no longer relevant, given the investment formula approved by the Board............................................................................ 65

18. In light of the above, the Board considers that the AESO should have the option of reinstating a minimum contribution threshold if, in the AESO’s opinion, the administrative burden requires this. Accordingly, the Board hereby directs the AESO in its refiling to advise the Board as to whether the minimum contribution refund threshold as provided in the existing AESO Tariff’s Article 9.8 (c) should be reinstated and, if so, to amend its T&Cs accordingly.............................................................................................................................. 66

19. Accordingly, the Board hereby directs that, in its refiling of the Application, the AESO shall redraft Article 9.3 so as to exclude in its entirety the Article 9.3(a) portion of the Article. ... 68

20. Accordingly, the Board directs the AESO in its refiling Application to apply the 12% prepaid O&M surcharge such that: ...................................................................................................... 69 • The surcharge will be determined separately for the optional and non-optional facilities;..



• The portion of a DTS interconnection project’s prepaid O&M surcharge based on cost of the optional facilities will be fully charged out to the interconnecting DTS customer, consistent with the Board’s disposition of other optional facility costs; and, ......................

• The portion of the prepaid O&M surcharge related to non-optional facilities is added to other non-optional facility costs and evaluated against the maximum investment function to determine the amount of customer contribution that may be required in respect of the standard facility portion, if any.............................................................................................

21. Having considered all of the above, the Board hereby directs the AESO to provide an amended Article 9.10 of the Terms and Conditions in its refiling application in accordance with the following parameters: ............................................................................................... 71 1. Payment of all of the charges pursuant to Subsection 17(2) shall be made prior to the date

of construction. The Board recognizes that Subsection 17(3)(e) only requires the owner of a generator to pay the charges owing under Subsection 17 (2)(b) before commencement of construction of the local interconnection facility. However, the Board considers that prepayment of all costs, either customer contribution or system contribution, should be paid prior to the start of the commencement of activities related to the construction of any new transmission facilities necessary to provide the requested service. This will benefit the public interest by providing the maximum level of security from the outset. This will also encourage new generators to achieve commercial operation at the earliest time in order to realize their refunds, and will also be in the interests of all Albertans as they seek to realize the benefits of such generation as soon as it can reach commercial operation. .......................................................................................

2. Any refund paid to a generating owner pursuant to Subsection 17 (4) shall be paid out no later than 10 years following the date of original payment but shall not be due and owing until after the commercial operation date for the generating unit has been achieved provided that the commercial operation date is before the expiration of the 10 years. This will, of necessity compress the refund period to a remaining period of less than 10 years in most, if not all, circumstances. For purposes of clarity, commercial operation date means the date agreed to by the AESO and the generator owner when the plant requires the transmission assets requested for delivery of energy to the AIES..................................

For example, assume that a charge is paid to the AESO by the generator owner on January 1, 2006 pursuant to Subsection 17 (2). In accordance with Subsection 17 (4)(a) of the Transmission Regulation, and assuming satisfactory performance, the generator owner would be entitled to receive a full refund of its payment by no later than December 31, 2015. However, if the commercial operation date is January 1, 2008, the AESO will only have 8 rather than 10 years to pay out the refund.........................................................

3. In the event that a generator owner does not commence the delivery of energy at the levels agreed with the AESO at the time that the generator contributions were provided to the AESO by the commercial operation date for any reason whatsoever, then for each year or portion thereof that the date is delayed, the refund for that year or portion thereof will be forfeited.....................................................................................................................

Again, in consideration of the example above, in the event that the commercial operating date is not January 1, 2008 as originally provided to the AESO but is January 1, 2009, then the AESO shall deem that entire period to be one in which the generator owner failed to meet satisfactory performance standards and as such, the AESO will be entitled to retain that portion of the refund that otherwise would have been payable that year. The overall schedule over which the refund is to be paid will not change. .................................



4. Once commercial operation of the generating unit has commenced, in the event that a generator owner fails to meet satisfactory performance standards, any refund will be forfeited for that period.........................................................................................................

5. The refund amount shall be structured in a backend loaded manner over the refund period such that 25% of the total refund shall be paid out in equal payments per year over the first half of the refund period and 75% shall be paid out in equal payments per year over the last half of the remaining period. ....................................................................................

Using the example outlined above, in the event that a generator owner becomes eligible for a refund as of January 1, 2008 (the commercial operation date) and again assuming that the payment period ends December 31, 2015, then, for the years 2008 to 2011, 25% of the total eligible refund is available to be refunded in 4 equal payments while for the years 2012 to 2015, 75% of the total eligible refund is available to be refunded in 4 equal payments. ..............................................................................................................................

6. The AESO shall apply any forfeited refund amounts to a deferral account and any balances in that account shall be considered a revenue offset to its revenue requirement in a subsequent GTA.................................................................................................................

7. No interest shall be payable by the AESO to a generator owner on any refund amounts.73

22. Although the Board considers that the ultimate terms of reference for the harmonization initiative should be established by the AESO and participating stakeholders, the Board considers that it would be beneficial for the harmonization process to, at minimum, address the following issues: ................................................................................................................... • The development of a common definition of standard POD facilities as between Disco’s

and AESO (TFO) connected customers................................................................................ • Consideration of whether it is appropriate to establish defined “cutoffs” such as a

maximum MVA capacity for the consideration of the interconnection of a new customer to a Disco and/or a minimum threshold for the consideration of the interconnection of a new customer to a TFO system.............................................................................................

• Consideration as to whether it is feasible or appropriate to adopt a common form for a cost based maximum investment function (i.e. a standard formula that would provide a greater cost allowance for the purposes the Disco’s and AESO’s respective investment policies with increases in the capacity of the interconnection.......................................... 73

23. The Board notes that the AESO, in its Argument, advised that it agreed with AE that the provisions in its proposed Article 6.3 (b) of its T&Cs may not be enforceable as presented in the Application and that it wished to delete the reference to “Affiliates” in that article. The Board accepts the AESO’s proposal and directs the AESO to amend this provision accordingly in its refiling. ....................................................................................................... 76

24. The Board is prepared to grant the request of the AESO that no further action be taken on principles as a result of this proceeding. However, the Board directs the AESO to consult with stakeholders in the interim and address merchant interconnection principles in the 2007 GTA. ....................................................................................................................................... 80

25. The Board also considers that if a party wishes to arrange a one time payout in lieu of the 5 year notice that such payout should include consideration of bulk system costs. The Board notes that in Section 5.5.1 it has unbundled the DTS rate and ruled that the ratchet should not apply to bulk system costs. As noted above, however, there is some certainty that a customer continuing to use the system as a going concern will make a contribution to the fixed costs of the bulk system. This is not the case when a customer chooses to leave the system. For



purposes of calculating a one time payout, therefore, the AESO is directed in its refiling to propose a payout formula which includes consideration of bulk system costs. ..................... 83

26. The Board notes the AESO did not comment upon Fortis’ concerns in its reply. The Board has reflected upon the Fortis argument and considers it to have merit. The Board does not consider it necessary or reasonable for Fortis, or its customers, to bear the costs of supplying letters of credit for construction projects at this time, given the practical realities outlined by Fortis above............................................................................................................................. 84

27. The Board notes EnCana’s comments upon the use of the term “sole discretion” and “sole opinion” while FIRM comments upon the need to “act reasonably”. The Board considers that the AESO has a need to retain a certain degree of flexibility in its day to day dealings with its customers however, as the AESO has noted, this ability is not unfettered. The Board agrees with FIRM’s suggestion that a clause be added to the T&Cs as set forth above and directs the AESO to amend its T&Cs accordingly................................................................................... 87

28. The Board also considers, however, that when a customer enters into a contract with the AESO, the customer should have some certainty around what their rights and responsibilities are. Customers commit themselves to payment of significant amounts of money through monthly demand billings. The Board considers it reasonable that a customer should be able to determine their rights and responsibilities from the T&Cs and any relevant pro-forma documents attached thereto. Therefore, the Board directs the AESO in its refiling to review its T&Cs to ensure that customers’ rights and responsibilities are clearly spelled out and the appropriate pro-forma contracts are attached. The Board also directs the AESO to clarify in its BPDs, as suggested by FIRM, that customers’ rights and responsibilities are spelled out in the T&Cs................................................................................................................................. 87

29. Finally, the Board notes FIRM’s suggestion that Article 1.1, regarding “force majeure”, be amended such that Board orders and decisions do not qualify as force majeure items. The Board agrees with FIRM, for the reasons stated in the AML and ATCO Phase II decisions, and therefore directs the AESO to amend the T&Cs accordingly. ......................................... 87



APPENDIX 3 – ABBREVIATIONS

AIES Alberta Interconnected Electric System ATC Available Transfer Capacity BPD Business Practice Document COS Customer Owned Substation COS Study Cost of Service Study CP Coincident Peak DTS Demand Transmission Service Disco/Disco Distribution Facility Owner FIRM Farm, Irrigation, Residential and Municipal

interveners. Group of interveners as described in list of participants.

GTA General Tariff Application NCP Non-Coincident Peak NERC North American Electric Reliability

Council NBV Net Book Value O&M Operations and Maintenance POD Point of delivery POS Point of supply PSC Primary service Credit RFP Request for Proposal STS Supply Transmission service TFO Transmission Facility owner TMR Transmission Must Run T&C Terms and conditions of Service WECC Western Electric Co-ordinating Council