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Alberta Energy and Utilities Board Decision 2005-005 Alberta Electric System Operator 2004 General Tariff Application Phase I January 31, 2005

Decision 2005-005: AESO - 2004 General Tariff …Decision 2005-005: Alberta Electric System Operator 2004 General Tariff Application – Phase I Application No. 1343002 Published by

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Page 1: Decision 2005-005: AESO - 2004 General Tariff …Decision 2005-005: Alberta Electric System Operator 2004 General Tariff Application – Phase I Application No. 1343002 Published by

Alberta Energy and Utilities Board

Decision 2005-005

Alberta Electric System Operator 2004 General Tariff Application Phase I January 31, 2005

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ALBERTA ENERGY AND UTILITIES BOARD Decision 2005-005: Alberta Electric System Operator 2004 General Tariff Application – Phase I Application No. 1343002 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

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Contents

1 INTRODUCTION................................................................................................................. 1 1.1 Phase I Revenue Requirement Application.................................................................... 1 1.2 Application Process........................................................................................................ 1 1.3 Application Context ....................................................................................................... 3 1.4 Decision ......................................................................................................................... 4

2 GENERAL PRINCIPLES.................................................................................................... 4 2.1 Prudence......................................................................................................................... 4 2.2 Use of Deferral Accounts............................................................................................... 7 2.3 Duty to Address “Accountability Gaps” ........................................................................ 9

3 2004 PHASE I REVENUE REQUIREMENT FORECAST........................................... 10 3.1 Commodity Price and Heat Rate Forecasts.................................................................. 10 3.2 Post-Application Forecast Updates .............................................................................. 11 3.3 Volume Forecasting Methodology............................................................................... 12

3.3.1 Probabilistic Volume Forecasting Approach ............................................... 12 3.3.2 Load Forecast Module ................................................................................. 12 3.3.3 Generation Dispatch Module ....................................................................... 13

4 WIRES COSTS ................................................................................................................... 14 4.1 Transmission Facility Owner (TFO) Wires-Related Costs.......................................... 14

4.1.1 TFO Wires Cost Forecast............................................................................. 14 4.1.2 Direct Assign Projects.................................................................................. 16 4.1.3 Increased TFO Supply Inventory to Facilitate Faster Customer Interconnections.......................................................................................................... 17

4.2 Non-Wires Costs .......................................................................................................... 18

5 ANCILLARY SERVICES COSTS ................................................................................... 19 5.1 Operating Reserves Forecast........................................................................................ 19 5.2 Other Ancillary Services Forecast ............................................................................... 20

5.2.1 Generator Remedial Action Schemes .......................................................... 20 5.2.2 Black Start.................................................................................................... 20 5.2.3 Transmission Must Run (TMR)................................................................... 21 5.2.4 Under Frequency Mitigation........................................................................ 22 5.2.5 Hydro Motoring ........................................................................................... 23 5.2.6 Fort Saskatchewan Load Shed ..................................................................... 23 5.2.7 Poplar Hill Agreement ................................................................................. 23 5.2.8 Interruptible Load Remedial Action Scheme .............................................. 23

5.3 Ancillary Services – General Provisions...................................................................... 25 5.3.1 AESO Ancillary Services Procurement Practices........................................ 25 5.3.2 Ancillary Services Self-Supply Arrangements ............................................ 25 5.3.3 Ancillary Services Requirements Study ...................................................... 25 5.3.4 Ancillary Services Procurement Code of Conduct ...................................... 26

6 TRANSMISSION LOSSES................................................................................................ 27 6.1 Transmission Losses Forecast Methodology ............................................................... 27 6.2 Management of Transmission Losses .......................................................................... 28

EUB Decision 2005-005 (January 31, 2005) • i

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7 OTHER MATTERS ........................................................................................................... 28 7.1 AESO Code of Conduct ............................................................................................... 28 7.2 Consideration of Supply Customer Views in EUB Decisions ..................................... 29 7.3 Minimum Application Filing Requirements / Uniform System of Accounts .............. 29 7.4 Benchmarking .............................................................................................................. 29 7.5 Negotiated Settlement Matters..................................................................................... 30

8 PHASE II MATTERS ........................................................................................................ 32 8.1 Requirement for Updated Phase II Rates ..................................................................... 32 8.2 Deferral Accounts & True Up...................................................................................... 33 8.3 Customer Owned Substation/Customer Owner Transmission (COS/COT) Credits ... 33

9 CONCLUSION ................................................................................................................... 34

10 ORDER ................................................................................................................................ 35

APPENDIX 1 – PARTIES SUBMITTING ARGUMENT & REPLY................................... 37

APPENDIX 2 – ORDER U2004-429 ......................................................................................... 38

APPENDIX 3 – SUMMARY OF BOARD DIRECTIONS ..................................................... 39 List of Tables Table 1. AESO Phase I Revenue Requirement ($ millions)................................................. 10

Table 2. Commodity Price Forecast....................................................................................... 10

Table 3. TFO Wires Cost Forecast......................................................................................... 15

Table 4. Operating Reserve Costs and Volumes................................................................... 19

Table 5. Other Ancillary Services Costs ................................................................................ 20

Table 6. Transmission Losses Cost and Volumes ................................................................. 27

ii • EUB Decision 2005-005 (January 31, 2005)

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ALBERTA ENERGY AND UTILITIES BOARD Calgary Alberta ALBERTA ELECTRIC SYSTEM OPERATOR Decision 2005-005 2004 GENERAL TARIFF APPLICATION – PHASE I Application No. 1343002 1 INTRODUCTION

1.1 Phase I Revenue Requirement Application Under cover of a letter dated April 19, 2004, the Alberta Electric System Operator (AESO) filed an Application dated April 20, 2004 for the approval of its 2004 Phase I Revenue Requirement (the Application). Specifically, the Application requested the following relief: (1) Approval of the AESO’s applied-for 2004 forecast revenue requirement amounts for wire

costs, ancillary services and transmission line losses for future rate setting purposes. (2) Confirmation from the Board that the AESO’s entire 2004 forecast revenue requirement

is subject to deferral account treatment. (3) Confirmation from the Board that the AESO shall continue to employ its existing and

approved tariff (including Rate Riders B and C), and annual deferral account reconciliation adjustment process for the calculation of rates and the recovery of all actual incurred costs until such time as the Board approves changes to those processes.

(4) Such other relief as the AESO requires or the Board deems appropriate. The Application did not request the consideration or approval of the AESO’s 2004 “Own Costs” since the Board had already approved these costs in Decision 2004-012. The AESO also indicated that it was not requesting Board approval of any adjustments to its existing rates. However, for information purposes only, the AESO included in the Application a schedule providing pro forma rate calculations taking into account the overall 2004 forecast revenue requirement and 2004 forecast billing determinants.1 Pursuant to section 4.1 of the Board’s Negotiated Settlement Guidelines (Guidelines),2 the AESO also requested approval to commence a negotiated settlement process (NSP) in respect of the 2004 Phase I Revenue Requirement amounts set out in the Application. 1.2 Application Process On May 10, 2004, the Board issued a Notice of Application and Process (Notice) in respect of the Application, which was circulated to a broad list of interested parties. The Notice established a preliminary schedule for the consideration of the Application through a written process. The

1 AESO Application Appendix D, pp. 46-47 (as amended June 10, 2004) 2 Informational Letter IL 98-04 (Revised)

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2004 General Tariff Application – Phase I Alberta Electric System Operator

Notice also included the Board’s approval of the AESO’s request to commence a NSP. Subsequently, a Board Staff Observer was assigned to participate in the NSP. On July 16, 2004, the AESO submitted an application for approval of a negotiated settlement signed by several interested parties (Settlement). The signatories to the Settlement had agreed to the revenue requirement requested by the AESO in the Application as well as changes to rates for that portion of 2004 remaining after the Board had approved the Settlement. To the latter extent, the Settlement went further than the Application, which proposed no rate changes, deferring those matters to the anticipated Phase II proceeding. Beyond these two significant issues, the Settlement addressed only a handful of relatively minor issues. Parties who objected to approval of the Settlement, such as IPCAA and Calgary, did support approval of the revenue requirement and the changes to rates contemplated by the Settlement. Other parties did not object to the Settlement, but their positions appeared to be based, at least in part, on their anticipation that a Phase II application would be forthcoming. By letter dated July 20, 2004, the Board established a schedule for the consideration of the Settlement. The Board noted that the Settlement was not comprehensive and was not signed by all interested parties participating in the 2004 Phase I Application process or the NSP. The Board invited comments on the terms of the Settlement as well as items not covered by the terms of the Settlement. The Board also invited parties who had not signed the Settlement to comment upon all issues raised in the Application. The Board received no objections to the process or schedule set out in its July 20 letter and ultimately received Argument and Reply from those parties listed in Appendix 1 by August 13, 2004.3 On October 1, 2004, in response to a request for comments in respect of Application 1357161 (Article 24 Amendment Application), the AESO provided an update on its views respecting the closing off of 2004 matters. The AESO indicated that, while it would shortly be combining its 2005 Phase I and Phase II applications into a single comprehensive application, save for the proposed amendments to Article 24 contemplated in Application 1357161, it was not necessary to file a 2004 Phase II application. On October 7, 2004 the Board requested comments on the evolving views of the AESO with respect to a 2004 Phase II application, including whether these views affected parties’ positions with respect to the Phase I Application. The Board received submissions from IPCAA, FIRM, Powerex Corporation (Powerex), TransAlta Utilities Corporation (TransAlta), and EnCana Corporation (EnCana). Although several parties indicated that they had anticipated that the AESO would file a 2004 Phase II Application, the general consensus from these parties was to support the AESO’s proposal not to have a 2004 Phase II Application in the circumstances. The AESO replied on October 29, 2004. On November 2, 2004, the Board received correspondence from the AESO indicating that all parties who had signed the Settlement were now in agreement that the Settlement should be withdrawn. In light of the withdrawal of the Settlement, the AESO noted that the AESO rates currently in effect as a result of the Board’s approval of the 2003 negotiated settlement in

3 The Board also received an earlier letter from IPCAA dated July 13, 2004, which the Board has taken into account in considering the Application.

2 • EUB Decision 2005-005 (January 31, 2005)

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Decision 2003-077 would continue in effect for the remainder of 2004 and until new rates were approved. With the withdrawal of the Settlement on November 2, 2004, the Board was left in the position of considering the Application only, which did not provide for any rate changes, and with the understanding that no Phase II application for 2004 would be filed by the AESO.4 In the circumstances, for administrative purposes of this Decision, the Board considers the record for this proceeding to have closed on November 2, 2004. 1.3 Application Context Direction 7 of Decision 2003-077 required the AESO, by January 31, 2004, to propose a process that would achieve complete approval of the AESO’s Phase I application prior to the commencement of the applicable year. On January 30, 2004, the AESO responded to this Direction and outlined the AESO’s intentions regarding the filing of its future applications. The AESO indicated that it intended to file a 2004 Phase II application and to largely carry forward the results of the 2004 GTA process into 2005 rather than making a separate 2005 Phase II application. The AESO adopted this approach in anticipation of the implementation of the Government of Alberta’s Transmission Development Policy (Policy) and the regulation that was to follow. On June 11, 2004 the AESO further advised the Board and stakeholders that due to changes in the expected timing of the regulation to implement the Policy as well as a higher than anticipated workload in relation to other regulatory proceedings, the AESO did not anticipate filing its 2004 Phase II application until sometime in the early fall of 2004. The Transmission Regulation5 (Regulation) was enacted on August 11, 2004. On August 31, 2004, the AESO filed an update of its January 30, 2004 letter, which noted the AESO’s intention to file a 2004 Phase II application based on the 2004 Phase I application. The AESO reiterated its intention to file a single Phase II application covering both 2004 and 2005 early in the fall of 2004. However, in light of the delays experienced in the filing of the 2004 Phase II application, the AESO clarified that if 2004 deferral accounts were addressed using the AESO’s present, retrospective reconciliation methodology, the AESO would only apply the reconciliation using new 2004 rates on a prospective basis – i.e. only in respect of the portion of 2004 during which the new 2004 rates were in effect. Furthermore, in light of the expectation that a Board decision on the 2005 Phase II was not likely until some time in 2005, the AESO intended that new 2005 rates based on 2005 forecast costs and billing determinants would only be applied on a prospective basis following the issuance of the 2005 Phase II decision. The AESO also noted that certain aspects of the Regulation were different than expected in the AESO’s January 30, 2004 correspondence, necessitating changes in the manner and timing in which the AESO intended to address its response to certain policies outlined in the Policy. In

4 Application No. 1357161 respecting the Article 24 Amendments is technically a Phase II issue, but is being

treated separately. It is the only Phase II issue before the Board that might have some impact on the AESO’s 2004 tariff.

5 AR 74/2004 EUB Decision 2005-005 (January 31, 2005) • 3

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particular, the AESO noted that sections 19 through 22 of the Regulation now contemplated that loss charges would be developed in accordance with the AESO rule mechanism under section 20 of the Electric Utilities Act (EUA) rather than as a tariff matter. In addition, the AESO indicated that it intended to deal with the generator interconnection policy in the context of the 2006 tariff application, in order to provide an opportunity for a possible alignment of the generator contribution zones with its development of new rules respecting transmission losses. 1.4 Decision In light of all of the circumstances, the Board has determined that it is reasonable and in the public interest to approve the revenue requirement as filed in the Application. In arriving at this determination, the Board notes that although parties raised a number of concerns with the Application, they all agreed, whether through the Settlement or otherwise, that the revenue requirement applied for by the AESO ought to be approved. Notwithstanding this approval, the Board has addressed a number of the concerns raised by parties since many of them relate to the ongoing regulation of the AESO by the Board. The Board agreed with parties that it was desirable to provide some guidance to the AESO and to clarify the Board’s role in regulating the AESO’s tariffs. The Board has approved the Application with the understanding that no 2004 Phase II application will be filed. Accordingly the AESO’s existing 2003 rates approved by the Board in Decision 2003-077 would otherwise have continued until a 2005 Phase II tariff is approved sometime later this year. However, in order to approve the 2004 revenue requirement prior to December 31, 2004, the Board issued Order U2004-429 on December 2, 2004. That Order not only approved the applied-for revenue requirement of $757.6 million, it also directed the AESO to apply, on or before December 15, 2004, for interim rates to be effective January 1, 2005. The AESO complied with this direction and the Board approved interim rates effective January 1, 2005 in Order U2004-476, dated December 23, 2004. Accordingly, the 2003 rates approved in Decision 2003-077 applied until December 31, 2004. In Order U2004-429, which is reproduced in Appendix 2 to this Decision, the Board indicated that it would provide reasons for approving the Application at a later date. This Decision sets out the Board’s reasons for doing so and addresses the concerns raised by parties noted above. 2 GENERAL PRINCIPLES

Before considering in greater detail the components of the revenue requirement requested in the Application, the Board finds it worthwhile to address two of the key principles about which parties continued to have significant disagreement. Those principles concern the prudence considerations applicable to the AESO’s costs and the use of deferral accounts in light of the relevant provisions of the EUA. 2.1 Prudence The parties devoted a fair amount of argument to the question of how the AESO ought to be regulated by the Board given its unique status as a statutorily created entity with a not-for-profit legislative mandate. Particular attention was directed towards the standards of prudence and reasonableness that were urged to be applied by the Board with regard to the AESO’s costs. 4 • EUB Decision 2005-005 (January 31, 2005)

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This is not the first time that this issue has been debated by the parties. In Decision 2004-012, the Board clearly provided its determination with regard to this issue. Given the fact that the parties have once again raised the matter, the Board considers it worth emphasizing what it has said:

The Board has some difficulty with the AESO’s position based on the express responsibilities conferred on the Board by the EUA in relation to any tariff application, including that of the AESO. In particular, section 122 of the EUA makes it clear that the Board must consider whether any applied for costs are prudent and that the applicant has a reasonable opportunity of recovering those costs, without guaranteeing recovery. These requirements apply expressly to the AESO. [Footnote 2: EUA, section 122(2)] In the Board’s view, if its responsibilities in considering an AESO tariff were to differ from other tariffs based on the AESO’s not-for-profit status, the legislation would have been worded differently. The AESO acknowledged that its forecast Own Costs were subject to reasonableness and prudence standards and the Board sees no reason not to apply similar standards to actual costs. Accordingly, the Board does not accept that all variances from forecast will necessarily be recoverable from customers if subject to deferral account treatment. The Board wishes to make it clear that any approved deferral accounts will be subject to the appropriate reasonableness and prudence tests and will not automatically be flowed-through to customers. The Board does, however, take some comfort in the fact that the AESO has adopted a governance structure that includes final approval by its Members before any material changes in budget are implemented. The Board also notes the AESO’s commitment to apply to the Board for material cost changes arising from significant and unforeseen changes in circumstances. Ordinarily, deferral accounts are only approved by the Board for costs that cannot reasonably be forecast, especially where they are effectively beyond the control of the applicant. However, the Board does consider that the AESO’s unique statutory role justifies deferral account treatment for its Own Costs so that variances from forecast will be reviewed for reasonableness and prudence. The Board considers that this treatment provides the AESO with a reasonable opportunity to recover its prudent, actual costs, without guaranteeing the recovery of actual costs. Therefore, as indicated in its January 28, 2004 letter, the Board approves the use of deferral accounts for the AESO’s Own Costs, subject to the application of the appropriate reasonableness and prudence tests at the appropriate time.6

The Board considers Decision 2004-012 to have put to rest a number of the arguments that continued to be made in the present proceeding. The Board’s views have not changed since that Decision was issued. However, in light of the continued debate among the parties, and in particular the “sense” alluded to by AE7 and IPCAA8 that the Board may be affording preferential treatment to the AESO, it is apparent to the Board that further clarity is required.

6 Decision 2004-012, page 8. 7 ATCO Electric Argument, p. 1 8 IPCAA Argument, p. 5

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In the Board’s view, there are two closely related questions at issue in relation to the Board’s regulation of the AESO:

1. What costs is the AESO entitled to include in its tariff? 2. What is the nature of the AESO’s entitlement to recover those costs?

In the Board’s view, the clear answer provided by the EUA to the first question is “prudent costs approved by the Board”: EUA, sections 30(2)(a)(iv), 122(1) and 122(2). The clear answer provided by the EUA to the second question is that a Board-approved tariff must provide the AESO with a “reasonable opportunity to recover” all of the prudent costs of the AESO: EUA, section 122(2). In this latter respect, the Board does not agree with the AESO’s position that the operation of section 30 and section 122(3) of the EUA exempts the AESO from the “reasonable opportunity to recover” policy. In the Board’s view, section 30 simply requires the rates in the AESO’s tariff to be sufficient to recover the Board-approved costs. Actual costs accumulated in deferral accounts that have not been reviewed by the Board for prudence cannot be said to have been approved by the Board in the relevant sense so as to guarantee their recovery by the AESO. The AESO is subject to the same regulatory principles as any electric utility regulated by the Board.9 Where differences may arise is in how those principles are applied to the AESO in light of its unique statutory role and its significant statutory obligations to ensure the safe and reliable operation of the Alberta Integrated Electric System (AIES or System) and to ensure non-discriminatory access to that System for the exchange of electricity. In other words, while the AESO is only entitled to a reasonable opportunity to recover prudent costs, what is prudent for the AESO might be imprudent for owners of transmission facilities or electric distribution systems. By the same token, what is a reasonable opportunity for the AESO to recover those costs may differ from the opportunity provided to the owners of transmission facilities and electric distribution systems in their tariffs. What is prudent and reasonable for a for-profit investor or municipally-owned utility may not be prudent and reasonable for a not-for-profit statutorily created utility and vice versa. Treating utilities according to the same principles does not require the Board to reach identical conclusions in respect of them and the Board cannot accept that it must reach the same conclusions in relation to the AESO as it would an electric utility, whether investor or municipally owned. The Board must have regard to the particular circumstances of the regulated entity in determining both questions. One of the challenges posed by the EUA to the Board in its regulation of the AESO tariff is to reconcile with the Board’s general tariff jurisdiction a number of unique factors that do not arise in the regulation of electric utilities. Primarily, these factors are:

1. Corporate Structure – The AESO is a statutory corporation with a membership and governance determined in accordance with Part 2, Division 1, of the EUA.

2. Budget – Section 14(3) of the EUA requires the AESO to be managed so that, on an annual basis, no profit or loss results from its operations.

9 The AESO is not, in fact, an “electric utility”: EUA, section 1(1)(o). While a number of sections of the EUA specifically mention the AESO or its tariffs as distinct from those of electric utilities, the Board notes that sections 120 and 121 do not contain such a distinction. These sections apply generally to all tariffs regulated by the Board.

6 • EUB Decision 2005-005 (January 31, 2005)

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3. Duties – Part 2, Divisions 2 and 4, of the EUA impose significant duties and obligations on the AESO in respect of the AIES and the Power Pool. The Board’s role in relation to the AESO’s carrying out of these duties is somewhat different than it is in relation to electric utilities.10

4. Costs – Most of the AESO’s annual costs are not its own costs, but costs attributable to transmission facility owner (TFO) tariffs and the provision of ancillary services.

5. Deferral Accounts – Section 122(3) of the EUA expressly provides that some or all of the AESO’s costs may be subject to deferral account treatment.

The AESO’s particular status as a statutory, non-profit entity cannot be ignored, however, its unique status does not mean that it is immune from the consequences of taking imprudent actions. In the Board’s view, while the AESO’s not-for-profit status does mean that it is not motivated in the same way as investor-owned utilities to maximize profit, the absence of shareholder oversight may result in there being little incentive to control costs. In Decision 2004-012, the Board held that the AESO’s non-profit status and the fact that its budget was approved by the AESO board, whose members are bound by the EUA to act in the public interest, were merely two factors among many that the Board must take into account in assessing the prudence of the AESO’s costs.11 The Board acknowledges that the views it has so far expressed about prudence have been based largely on its consideration of the AESO’s Own Costs. However, the other cost components of the AESO’s tariff are subject to external factors, making them more difficult to forecast reliably. With respect to these costs components, the Board is of the view that in carrying out its responsibilities under the EUA to ensure the safe and reliable operation of the AIES, the AESO must make prudent decisions in respect of any procurement or activity that influences flowed-through costs. To this end, the Board does not consider it reasonable to hamper the AESO in the carrying out of its duties by limiting the AESO to its approved forecast in all cases on the basis that any exceedances are, by definition, imprudent. Indeed, given its duties, the AESO might be subject to claims of imprudence if it failed to incur certain costs, whether internal or external, in order to respond to the needs of the AIES and market participants. In other words, it would be arguably unreasonable for the Board to approve a tariff containing limitations on the AESO’s ability to recoup from customers costs necessary for the AESO to ensure the level of safety and reliability of the AIES required by the EUA.12 2.2 Use of Deferral Accounts The Board’s views expressed in this Decision and Decision 2004-012 require the AESO to ensure that its forecasts are as accurate as possible in order to minimize deferral account balances. This is true regardless of the existence of section 122(3) of the EUA. The Board also considers this view to be consistent with section 5(h) of the EUA, with its express purpose of minimizing regulation, which the Board considers to include after-the-fact regulation of deferral account balances.

10 For example, the Board must consider applications for approval of need identification documents under section

34 of the EUA though the primary responsibility for planning the transmission system lies with the AESO. 11 Decision 2004-012, p. 5. 12 Reflecting this view, in Decision 2004-012, the Board did not accept the proposal of some parties that the AESO

should be subject to caps, bounds or thresholds in respect of its 2004 Own Costs. EUB Decision 2005-005 (January 31, 2005) • 7

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The Board agrees with Calgary that section 14(3) of the EUA places an obligation on the AESO to manage its affairs in such a way that no profit or loss is realized on an annual basis. As stated above, the AESO bears a significant onus to ensure that its forecasts are as accurate as possible in order to minimize the use of deferral accounts. Meeting this onus clearly assists the AESO in conforming to section 14(3). However, the Board is not obliged to ensure that the AESO meets this no-profit duty, particularly through its approval of the AESO’s tariff. The Board is obliged by section 122(2) of the EUA to ensure that the AESO’s tariff provides it with a reasonable opportunity to recover prudent costs. The non-profit status of the AESO is a factor for the Board to consider in determining whether the AESO’s tariff provides it with the required opportunity for prudent cost recovery. Therefore, as contemplated by section 122(3) of the EUA, the Board may be persuaded, as it was in Decision 2004-012, that deferral account treatment for some or all of the AESO’s costs is appropriate. The discretion, however, is the Board’s and not the AESO’s. Merely because the AESO requests across-the-board deferral account treatment does not mean that the Board will accept such treatment as necessarily in the public interest. What the Board said about deferral accounts in Decision 2004-012 is worth repeating here:

Ordinarily, deferral accounts are only approved by the Board for costs that cannot reasonably be forecast, especially where they are effectively beyond the control of the applicant. However, the Board does consider that the AESO’s unique statutory role justifies deferral account treatment for its Own Costs so that variances from forecast will be reviewed for reasonableness and prudence. The Board considers that this treatment provides the AESO with a reasonable opportunity to recover its prudent, actual costs, without guaranteeing the recovery of actual costs. Therefore, as indicated in its January 28, 2004 letter, the Board approves the use of deferral accounts for the AESO’s Own Costs, subject to the application of the appropriate reasonableness and prudence tests at the appropriate time.13

Accordingly, it should be clear that the Board does not accept the AESO’s argument that it cannot be exposed to any risk of cost disallowance. When the Board is presented with an AESO deferral account balance, further practical and fairness considerations will necessarily arise. Somewhere between the extreme of not allowing deferral accounts at all, so that the AESO would be limited to its approved forecast, and the other extreme of allowing complete recovery (or refund, as the case might be) of all deferral account balances, lies a reasonable middle ground that the Board considers it must tread. The real issue before the Board is what to do in the circumstance where the Board concludes that certain amounts collected in the AESO’s approved deferral accounts are imprudent. Rather than “withholding” funds from the AESO, AE suggested that the Board clearly identify and “disallow”, at least on a notional basis, AESO costs that the Board deems to be imprudent. In AE’s view, the act of identifying imprudent costs should be sufficient to lead to self-correcting behaviour by the AESO. Although the Board is prepared to accept the logic of AE’s argument and would consider notional disallowance in the appropriate circumstances, if it subsequently became clear to the Board that notional disallowance had not, in fact, resulted in self-correcting behaviour, the Board may be more inclined to make actual disallowances, again depending on the particular circumstances.

13 Decision 2004-012, page 8.

8 • EUB Decision 2005-005 (January 31, 2005)

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Although, the Board does have the jurisdiction and the discretion to direct an actual rather than a notional disallowance as proposed by AE, this discretion could only be exercised very carefully. The Board agrees in part with the observation of IPCAA that it may not be possible to deliver the “consequences” of imprudence to the AESO without creating a greater harm for the AESO’s customers. The difficulty in this respect arises from the same concern that the Board expressed earlier in relation to the potential effect of limitations built into the AESO’s tariff that might effect the AESO’s ability to meet its important duties under the EUA. Therefore, with respect to the use of deferral accounts, the Board confirms that it is appropriate for the AESO to employ the use of deferral accounts both for its Own Costs and in respect of other revenue requirement elements and the Board approves the deferral accounts requested in the Application, accordingly. Whether the AESO will be subjected to notional or actual disallowance will depend on the circumstances associated with the particular costs and whether the Board is ultimately satisfied that the AESO will self-correct if only notional disallowance is ordered. In the Board’s view, this approach will ensure that the AESO is provided with the reasonable opportunity to recover its prudent costs required by the EUA. 2.3 Duty to Address “Accountability Gaps” The Board notes that the parties and AESO have addressed, albeit only in an abbreviated manner, their positions respecting the scope of the duties and responsibilities of the AESO. The Group14 submitted that the duties and responsibilities set out in sections 16 and 17 of the EUA should be interpreted in the context of the general purpose of the EUA as set out in section 5 of the EUA. In those instances where there is no specific direction provided to the AESO, it was the Group’s view that it was the responsibility of the AESO to step in and provide a leadership role to establish some direction for any “accountability gaps” not specifically established in the legislation. The AESO did not disagree with the suggestion that it should be proactive in carrying out its duties, functions and responsibilities although it did not share the Group’s view of specific gaps that the Group indicated were present.15 As issues have arisen regarding the scope of the AESO’s discretion, the Board believes it would be of assistance to the parties and to the AESO to provide some general comments respecting the matter. However, the Board is not prepared to provide its assessment of any specific allegations respecting accountability gaps identified in the proceeding. A review of the above noted provisions of the EUA is supportive of the position advanced by the Group that the AESO has far reaching duties and responsibilities and given this broad scope, it would logically follow that the AESO should be expected to take a proactive role in the development and resolution of issues that fall under its scope. The Board considers these comments of the Group to be supported by the Regulation, which has empowered the AESO with rule making authority in relation to certain matters that would have previously been dealt with by the Board in the context of AESO tariff applications. However, as the Regulation was released after the parties provided their reply submissions, the parties have not had an opportunity in the context of this proceeding to address the impact of the Regulation

14 “The Group” as referenced in this Decision includes the ASTC Power Partnership, the Independent Power

Producers Society of Alberta (IPPSA), and TransCanada Energy. A complete list of parties filing argument and reply is provided in Appendix 1.

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on the nature and extent of the AESO’s duty to be proactive in respect of specific AESO responsibilities. The Board is of the view that this is an important issue and one that should be more fully explored. In this regard, the Board would expect the matter may be identified and addressed by parties within the AESO’s 2005/2006 tariff application proceeding. 3 2004 PHASE I REVENUE REQUIREMENT FORECAST

A breakdown of the AESO’s 2004 revenue requirement forecast by major cost components (including comparisons to forecasts and actual/recorded costs in the two immediately preceding years) is as set out in the following Table. Table 1. AESO Phase I Revenue Requirement ($ millions) 2004

Forecast 2003

Recorded 2003

Approved Forecast

2002 Actual

Wires Costs TFO Wires-Related Costs 389.8 336.6 339.9 363.8 Non-Wires Costs 9.6 6.6 6.6 3.2 Prior Period Adjustment (0.3) Total Wires Costs 399.1 342.9 346.5 367.0 Ancillary Services Costs Operating Reserves 105.0 120.1 167.0 155.6 Other Ancillary Services 58.4 55.8 39.0 67.6 Poplar Hill/ILRAS 2.9 2.6 2.4 2.6 Total Ancillary Services 166.3 178.5 208.4 225.8 Losses

159.9 174.6 142.7 115.9

Revenue Requirement 725.3 696.0 697.6 708.7 Source: Application Table 2.5, p. 17 of 47 3.1 Commodity Price and Heat Rate Forecasts The AESO utilized the services of EDC Associates to obtain key commodity price forecasts such as the average pool price, the forecasted average natural gas price, and the forecast market heat rate. Table 2. Commodity Price Forecast 2004 Forecast 2003 Actuals 2003 Forecast Average Pool Price ($/MWh) 54.05 62.99 47.93 Average Gas Price ($/GJ) 6.14 6.30 4.23 Average Market Heat Rate (GJ/MWh)

8.8 10.0 11.3

Source: Application Table 2.1.2, p. 2 of 47 No parties disputed the qualifications of EDC Associates. While the Group suggested that the revenue requirement forecast should be updated to reflect developments occurring after the filing date of the Application (addressed in a separate section below), the Board notes that no parties disputed the reasonableness of the forecasts themselves. The Board has reviewed the forecasts

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and, noting the lack of objection, the Board finds the commodity price and heat rate forecast inputs to be reasonable. For the purposes of future AESO Applications, however, the Board is somewhat concerned with the fact that the proprietary nature of the forecasts provided by EDC Associates may unnecessarily restrict the ability of parties to investigate the derivation of the forecasts. In this regard, the Board notes that the proprietary nature of EDC reports was cited by the AESO as a reason for not providing additional information on the derivation of the forecasts.16 As a forecast of the hourly pool price may be derived from the combination of the load forecast and the projected generation dispatch order, the Board considers that it should be possible for the AESO to develop a reasonable forecast of pool prices using information available internally. In any event, given the direct relationship between pool prices and these parameters, the Board considers that it would be beneficial to ensure that the pool price forecast is fully consistent with the assumptions used for forecast load and generation dispatch. In this regard, the Board is again concerned that the use of the EDC Associates forecast, which may be based on a different model and assumptions set than used by the AESO, may lead to inconsistencies that could be prevented if the pool price forecast were to be developed internally by the AESO using its own models. In light of these concerns, the Board expects the AESO either to develop the internal capability to forecast pool prices or to satisfy the Board that it would be unreasonable to do so. The Board expects that both the manner in which pool price forecasts are derived, as well as the resulting pool price forecasts themselves, will be examined by parties in the context of the forthcoming 2005/2006 tariff application proceeding. 3.2 Post-Application Forecast Updates With the exception of the updates to the TFO wires costs forecasts to reflect the impact of Decision 2004-046 in respect of AltaLink’s 2004 Interim Tariff Application, all forecasts in the Application are based on the information available at the time the Application was filed by the AESO on April 20, 2004. Certain parties suggested in argument that other aspects of the AESO’s revenue requirement forecast should be updated after the original filing date of the Application in certain circumstances. In particular, the Board notes the Group’s submission that the Board direct the AESO to update its forecasts to include actual monthly amounts prior to completion of the evidentiary record, particularly in circumstances where the process is delayed into the forecast year. While the Board recognizes the desire of the Group to have the most accurate forecast possible, the Board notes that the quality of forecast information will always improve as the time moves closer to the effective date of the tariff under consideration. Accordingly, there will always be a temptation to want more current information to “improve” on forecasts that were prepared on the basis of the best information available at the time of filing. However, the Board also recognizes that the pursuit of perfection in the forecast has associated costs, both financial (to the applicant) and proceeding efficiency (for all parties and the Board). This is true of the AESO as noted by the AESO in this proceeding. Consequently, the Board is not prepared to provide a general direction to the AESO to update its forecasts with actual information as that information 16 CAL-AESO-02

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becomes available. Rather, the Board will evaluate the need for regulated entities to update their forecast information with actual data as necessary under the particular circumstances of the application before it. 3.3 Volume Forecasting Methodology The AESO utilized a volume forecast methodology that integrates several forecast models configured within three primary programming modules including a load forecast module, a generation dispatch module, and a losses forecast module. The results from the load forecast module are used as one input into the other forecasting modules. The AESO’s volume forecasting methodology produces forecasts used in the Application to develop forecasts for transmission losses, operating reserves, generator outputs and export and import volumes. 3.3.1 Probabilistic Volume Forecasting Approach In the Application, the AESO has significantly altered its basic approach for forecasting the volume of energy to be transmitted over the AIES. In contrast to prior years, which utilized a “deterministic” approach, the AESO adopted a “probabilistic” approach under which both the AESO’s load forecast module and the generation dispatch forecast module now use Monte Carlo simulations in an effort to more accurately model the uncertainty in model outputs caused by the uncertainty associated with key input variables such as Alberta Real GDP, generation output, and interchange with Saskatchewan and BC. The Board notes that no parties objected to the AESO’s proposal to adopt a probabilistic approach. The Board commends the AESO for its efforts in the development of these new methods and considers that the adoption of the probabilistic approach should improve both future load and generation dispatch forecasts. 3.3.2 Load Forecast Module The forecast Alberta Internal Load (AIL) for 2004 was derived by the AESO using a load forecast module based on the historical relationship between load growth and Alberta Real GDP growth established over 6 consecutive years. The load forecast module used actual metering data from 2002 to develop forecast load shapes to produce the 2004 forecast of AIL. Six years of historical load data was used to establish a relationship of actual load growth to the growth of Alberta Real GDP. The AESO developed its forecast of Alberta Real GDP on the basis of its interpretation of the information from publications periodically issued by different financial institutions. On the basis of this analysis, the AESO forecast that the Alberta Real GDP would be 3.6% for 2004. As described in Appendix A of the Application, the AESO forecast AIL for 2004 to be 63.2 TWh with an annual peak of 8,821 MW, representing a growth of 1.79% for energy and 1.61% for peak as compared to the AESO’s 2003 forecast. The forecast increase represents a 0.8% growth in AIL versus the 2003 Recorded amount.

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The Board has reflected upon the concerns expressed by Calgary and considers them to be twofold:

1) a specific concern with the accuracy of the forecast for the test period, and

2) a general concern with the transparency and comprehensibility of the AESO methodology.

With respect to Calgary’s first concern, the Board notes that the AESO has acknowledged an error in the description of its forecast. The Board has reviewed the AESO’s explanation and now considers the AESO’s forecast to be reasonable and it is accepted for the purposes of this test period. With respect to Calgary’s second concern, the Board agrees that the AESO bears the onus of demonstrating that its forecasts are reasonable and based on an acceptable methodology. Forecasts should be developed in a manner that is transparent and should utilize a methodology that can be easily understood by stakeholders. However, the Board also considers that parties may best raise concerns respecting the AESO’s methodology during the stakeholder sessions that the AESO routinely holds. Where this avenue is available, the Board encourages stakeholders to do so. Should the parties not be able to resolve concerns, of the nature encountered in this case, they can be addressed in the formal hearing process. 3.3.3 Generation Dispatch Module As with the AESO’s 2004 load forecast module, the AESO employed Monte Carlo simulations in its generation dispatch forecast module in accordance with the adoption of a probabilistic approach to the development of 2004 forecasts. The generation dispatch module is driven by a simulation of an ordered list of generators keyed into the model in a form of multiple energy tiers as functions of price or inferred heat rate (the assumed generation “stacking-order”). The stacking order information incorporates the dispatch behaviour of individual generators as well as export/import patterns observed in the market over the course of the latest six months. The simulation relies on the stacking order to match energy to the forecast aggregate load including losses. Input information used in the generation dispatch module included historical outage information, generator maximum capabilities, ramp rates, start up and shut down times, a simulated turnaround schedule to account for annual maintenance, a hydro energy forecast based on expected hydro resources, and capability to provide operating reserves. The generation simulation also included information on generator additions and/or deletions based on expected commissioning or decommissioning dates in 2004. The outputs from this generation dispatch module simulation include volume forecasts for:

• Operating Reserves both Active and Standby • Standby Operating Reserves to be activated • Exports and Imports; and • The output of individual generating units.

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Forecast outputs are produced with an hourly resolution in the form of a probability distribution consisting of 100 equally probable dispatch scenarios. Notwithstanding the fact that the generation dispatch module utilizes Monte Carlo simulations to deal with uncertainties in key input variables, the assumed generation stack order used in the generation dispatch module appears to be the critical determinant of the outputs of the model. The Board notes, however, that in the generation stack order provided by the AESO in FIRM-AESO-18 Attachment A, Genesee 3 may have been assumed to be operating and normally in merit, although the Board notes that FIRM-AESO-18 Attachment C does indicate that the AESO assumed an in-service date of October 1, 2004 for this unit. To the extent that Genesee 3 may have been included in the generation stack order for the purposes of deriving 2004 forecasts, the Board considers that this would impact the validity of such forecasts, and in particular would impact the AESO’s forecast of loss volumes. No parties commented on the AESO’s generation dispatch module and the Board once again commends the AESO for advancing the development of this approach, which the Board considers should improve future forecasting. However, in light of the concern just expressed, the Board cautions the AESO to ensure that care is taken in setting the assumptions used in the generation dispatch module to avoid the risk that future forecasts may be disallowed. 4 WIRES COSTS

4.1 Transmission Facility Owner (TFO) Wires-Related Costs

4.1.1 TFO Wires Cost Forecast The Application contains a TFO Wires-Related Costs forecast of $389.8 million, representing an increase of $49.9 million, or 15%, as compared to the approved 2003 forecast ($339.9 million). The TFO cost forecast as set out in the April 20, 2004 initial filing of the Application was revised by the AESO on June 10, 2004 to take into account the interim 2004 TFO rates for AltaLink and TransAlta approved by the Board in Decision 2004-046. Apart from these adjustments, no adjustments were made to the TFO cost forecast to reflect other changes in TFO costs resulting from the disposition of pending TFO-related proceedings after the date of the Application filing. The AESO proposed that any differences between the AESO’s revenue requirement as reflected in the Application (following the adjustments from Decision 2004-046) and the disposition of individual TFO proceedings, the Board’s Review and Variance process, judicial review, or any other means by which a TFO’s revenue requirement may change, would be adjusted in a future AESO deferral account process. A breakdown of the AESO TFO wires cost forecast by TFO is provided in the following Table:

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Table 3. TFO Wires Cost Forecast Transmission Facility Owner 2004 Forecast

$(M) 2003 Forecast

$(M) AltaLink 160.3 133.3 ATCO Electric Ltd. Foster Creek Substation Isolated Generation Subtotal

170.0 0.0

(5.1) 165.0

132.6 1.4

(6.1) 127.9

ENMAX Power Corporation Beddington Substation Subtotal

32.9 0.5 33.4

34.4 n/a 34.4

EPCOR Transmission Inc. 2003 Interim to Final Adj. Subtotal

32.6 (1.9) 30.6

34.0 n/a 34.0

City of Lethbridge 4.4 2.8 TransAlta 2002 Interim to Final Adj. Subtotal

2.3

(9.9) (7.6)

2.7 n/a 2.7

City of Red Deer 1.8 1.8 Aquila Networks (Farm) 1.9 1.9 Unassigned capital additions 0.0 1.1 Total Wires-Related Costs 389.8 339.9 Source: Application Table 2.2.1.1, p. 4 of 47 While the Group requested that the AESO provide additional information in relation to the TFO Wires-Cost forecast, no parties object to the forecast. The Board also notes that no parties objected to the amendment of the forecast to reflect the impact of Decision 2004-046 on the forecasts of AltaLink and TransAlta. Accordingly, having reviewed the forecast and finding it reasonable, the Board approves the TFO Wires Cost component of the AESO 2004 Revenue Requirement forecast. Although the AESO expressed some concerns regarding the timing of TFO decisions and the consequential impact of time lags on the AESO’s TFO Wires-Cost forecast in its January 30, 2004 correspondence pursuant to Directive 7 from Decision 2003-077, this issue was not pursued in the Application or by parties to the 2004 Phase I proceeding. In any event, the Board considers that the practice of basing the AESO TFO Wires Cost forecast on approved TFO tariffs is well established. Also well-established is the practice that any changes in TFO costs arising from TFO deferral account reconciliations have generally been handled by way of amendments to the approved TFO tariffs. Therefore, the approved TFO Tariff rates will often include a component to adjust for prior deferral account reconciliations, thereby ensuring that cost adjustments may be appropriately flowed through to AESO customers. The Board sees no need to change these practices unless and until the AESO or other parties can demonstrate that the practices provide a legitimate basis for concern. With respect to the concerns of the Group regarding possible discrepancies between the TFO Wires Cost forecast and the capital project forecast provided by the AESO in response to IPPSA-AESO-11, the Board does not consider that any possible discrepancies identified in relation to the projects of ENMAX and AE have a material impact on the revenue requirement forecast.

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Any remaining uncertainties in regards to these projects should be rectified in due course and appropriately flowed through to the AESO and its customers through the process described in the preceding paragraph. The Board agrees with the Group that the provision of a capital project breakdown of the sort provided by the AESO in response to IPPSA-AESO-11 was of considerable benefit to parties and to the Board for the purposes of this Application. The Board notes in particular that since no update to the Transmission Development Plans previously provided by the Transmission Administrator was provided to the AESO until the AESO published its 10 Year 2005-2014 transmission system plan on December 31, 2004, the response to IPPSA-AESO-11 filled a significant gap in the available information about the AESO’s future transmission facility project plans. The Board notes, however, that the AESO is now required by provisions of the Regulation to provide long range planning documents on a regular basis. Accordingly, the Board does not agree with the Group that a specific direction to the AESO to provide a breakdown of future TFO facility project plans is necessary at this time. 4.1.2 Direct Assign Projects The Board shares the strong interest shown by parties regarding TFO direct assign project cost estimation and project management procedures. However, for the reasons outlined below, the Board does not consider that it would be appropriate to rule in detail at this time on all of the matters raised by parties in argument in respect of this Application. The Board notes that, in addition to the consideration of parties in the context of the AESO 2004 Phase I proceeding, similar issues are also presently before the Board in TFO proceedings that are either currently underway or recently reviewed by the Board, including the AltaLink 2004-2007 GRA (Application 1336421) and the ATCO Electric 2003 Transmission and Distribution Deferral Account and Annual Filing for Adjustment Balances (Application 1351926). The Board further notes that the AESO responded to Board requests to provide additional information in respect to its direct assign project activities in both of these proceedings, but that such assistance was provided following the close of the filing of argument and reply in the present proceeding. In the circumstances, the Board is also persuaded by the observation of the AESO in its reply submission that the regulation to implement the Transmission Development Policy (i.e. the Regulation) was not available to parties at the time the parties’ argument and reply submissions were filed. The Board also considers that the observation of the AESO in its reply argument that implementation of the Policy through the Regulation could alter the AESO’s role and obligations in respect of direct assign projects in ways that may not have been anticipated in the submissions of parties has been borne out in practice through the release of the Regulation. The Board notes in particular that section 13(1) of the Regulation requires the AESO to make rules respecting the preparation of transmission facility cost estimates and cost reporting by TFOs. The Board considers that these rules will address many of the same issues raised by parties in respect of the Application. The Board understands that the AESO intends to consult broadly with parties in the development of these rules. The Board supports this initiative. As well, the Board notes that the Regulation requires that within a reasonable period of time following the establishment of these rules, the TFOs are required to make an application to the Board to make their tariffs consistent with the rules.

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In the circumstances, therefore, the Board has only the following general comments with respect to the direct assign project issues raised in this proceeding: 1. The Board accepts that the accuracy of cost estimates will vary according to the stage of the

project when the estimate is made and will further vary over the life of the project. Therefore, the Board’s assessment of the reasonableness of direct assign cost estimates must take the particular circumstances into account. However, given the possibility of significant differences between AESO and TFO forecasts for their tariff purposes and actual costs of any direct assign projects, the Board shares the concerns of parties that accountability for these differences rests in the appropriate place, which may well be the AESO. Accordingly, to the extent that parties do identify accountability gaps as between the AESO and a TFO in the execution of direct assign projects, the Board considers that any such accountability gaps must, somehow and at some point, be bridged.

2. The Board accepts that some consideration of project costs does take place at the facility

application stage. However, the Board does not consider transmission facility proceedings under the Hydro and Electric Energy Act (HEEA) to be the appropriate forum in which to assess the prudence and reasonableness of direct assign project costs for tariff purposes. HEEA proceedings are conducted according to the objects and purposes of that legislation, not the tariff provisions of the EUA, making them poorly suited to addressing tariff concerns.17

3. As noted earlier in Section 2.3 of this Decision, the Board considers the scope of the AESO’s

discretion under the EUA to reflect a requirement that the AESO be proactive in respect of those costs, internal or external, that are recovered through its tariffs. Since planning the AIES is a core responsibility of the AESO, as found by the Board in Decision 2004-012,18 the Board is of the view that the AESO does bear some ongoing responsibility to mitigate the risk of actual direct assign costs becoming imprudent over the life of the project. The Board does not consider it reasonable for the AESO to assign this responsibility to stakeholders. The Board expects these matters to be discussed among the AESO and stakeholders in the AESO’s intended consultation process about the development of rules pursuant to section 13(1) of the Regulation.

4. Pursuant to sections 25 and 26 of the EUA, respectively, the Board has complaint jurisdiction

to review not only the content of any rules promulgated by the AESO, but the conduct of the AESO in implementing the rules, including any rules respecting direct assign project costs. At the same time, in light of the rules, the AESO’s conduct and the Board’s views of each, the Board will continue to exercise its jurisdiction to ensure the justness and reasonableness of these costs in both the AESO and TFO tariffs.

4.1.3 Increased TFO Supply Inventory to Facilitate Faster Customer Interconnections

The Application indicates that, since all capital projects included in the TFO wires cost forecast have been direct assigned to a TFO, no unassigned capital project costs were included in the AESO’s 2004 wires cost forecast. The AESO noted, however, that as a result of the ongoing work of the Interconnection Process Team being led by the AESO, the AESO may be requesting

17 The relationship between Board approval of need identification documents under section 34 of the EUA and

HEEA approval of transmission facilities themselves is a complicating factor. 18 Decision 2004-012, p. 7

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TFOs carry or stock certain long lead-time equipment to facilitate reduced interconnection times for customer projects. As the work of the Interconnection Team had not produced a definable forecast of required long-lead time equipment, no costs for long-lead time equipment have been included in the Application’s TFO wires cost forecast. No parties commented on this issue. However, the Board considers that any proposal to request that TFOs stock additional equipment inventory to facilitate more timely interconnections should be put before the Board in the context of a future AESO tariff application so that parties may have an opportunity to assess the enhanced interconnection service against the incremental TFO Wires-Related costs that would be associated with providing such enhanced service. 4.2 Non-Wires Costs The AESO 2004 Revenue Requirement Forecast includes a Non-Wires cost forecast of $9.6 million, which represents an increase of $3.0 million or a 45% increase from the 2003 Approved Forecast of $6.6 million. These costs relate to the costs of Invitation to Bid on Credits Agreements (IBOC) and Location Based Credit Standing Offer Agreements (LBC SO), which were programs initiated to provide incentives for generators to locate closer to major Alberta load centres, thereby providing some deferment or relief of transmission system deficiencies that would otherwise have been dealt with through the instigation of Wires projects. The Forecast IBOC costs for 2004 have increased by $0.5 million to $3.2 million from the 2003 Approved Forecast of $2.7 million. The increase in IBOC costs was anticipated to occur as a result of an anticipated increase in the participation of IBOC units in the Operating Reserves market, thereby increasing the number of hours in 2004 that the IBOC units would be on-line and eligible for compensation from the AESO pursuant to the IBOC agreements. Under the LBC SO program, the AESO retains dispatch rights to location-specific generation in return for location-based credits. The AESO forecast a 2004 LBC SO agreement cost of $6.4 million, an increase of $2.5 million from the 2003 Approved Forecast of $3.9 million. The AESO expected the increased cost to occur primarily because: (a) the market heat rate in 2004 was expected to be lower, thereby increasing the costs of paying the operators for dispatching these units out-of-merit, (b) the AESO projected the LBC SO units to provide increased volumes of energy as compared to 2003; and (c) three LBC SO units would be in service for the full year in 2004 instead of a partial year as was the case in 2003. Calgary commented on the extent to which the AESO cited concerns with either commercial sensitivity of the requested information or other confidentiality restrictions as the rationale for not providing information about AESO ancillary services and non-wires cost forecasts.19 While, in some instances, the Board shares Calgary’s concerns, the Board notes that Calgary did not seek to obtain relief pursuant to the Board’s Rules of Practice in regard to its perceived deficiencies of the AESO’s responses. The Board also notes that Calgary’s stated concerns regarding their ability to test the AESO’s non-wires cost forecasts did not cause Calgary to recommend to the Board that it should not approve the AESO’s overall 2004 revenue requirement forecast as filed.20

19 Calgary Argument, pp. 12-13

20 Calgary Argument, p. 1

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In light of the foregoing, the Board considers that no parties provided any information that would prevent the Board from accepting the AESO’s forecasted non-wires costs as filed. 5 ANCILLARY SERVICES COSTS

5.1 Operating Reserves Forecast Operating Reserves are provided by generators that withhold capacity so that the system may quickly respond to temporary shortfalls in supply caused by the loss of a generating unit, inter-tie capabilities, and moment-to-moment fluctuations in load and are procured by the AESO on a daily basis through the Alberta Watt Exchange and through Over-The-Counter purchases. The AESO projected the 2004 Operating Reserves Forecast to decline by $62.0 million to $105.0 from the 2003 Approved Forecast of $167.0. A breakdown of the active and standby reserves costs and volumes in 2003 and 2004 is provided in Table 4 below. Table 4. Operating Reserve Costs and Volumes

Costs ($M) Volumes (MWh)

Operating Reserve 2004 Forecast

2003 Approved Forecast

2004 Forecast

2003 Recorded

2003 Approved Forecast

Active Reserves Regulating Spinning Supplemental

Subtotal

36.4 38.8 8.5 83.7

48.2 49.3

24.7 122.2

1,365,835 1,973,148 1,973,148 5,312,131

1,357,750 1,967,601 1,966,144 5,291,495

1,374,923 1,744,256 1,873,245 4,992424

Standby Reserves Regulating Premium Spinning Premium Supplemental Premium Regulating Activation Spinning Activation Supplemental Activation

Subtotal

2.6 2.4 0.8 5.8 7.8

1.8 21.3

6.7 4.2 1.9

15.4 14.9 1.6 44.8

1,054,080 922,320 395,280 91,283

128,630 53,472 2,645,065

1,164,656 994,332 369,574 91,437

124,229 60,667 2,804,895

1,506,880 1,016,880

489,120 148,745 156,395

27,407 3,345,427

Total Operating Reserves

105.0

167.0

7,957,196

8,096,390

8,337,851

Source: Application Table 2.3.1.1, p. 7 of 47 No parties provided specific comments addressing the operating reserves forecast.21 While Calgary’s Argument highlighted its concern with the magnitude of variances between previous AESO operating reserves forecasts and actual amounts requiring distribution through deferral account mechanisms22, Calgary did not provide any recommendations on alternate methodologies that would improve the operating reserves forecast as compared to the methodology used by the AESO. The Board also notes Calgary’s proposal to deal with the variability of forecasts based on commodity price forecasts by way of a true-up of mechanism

21 The Board acknowledges the comments of Calgary in regards to possible errors in the AIL forecast as well as

Calgary’s observation that errors in the load forecast affect other aspects of the AESO’s forecast, including volume forecasts used to estimate operating reserves costs. The Board has addressed Calgary’s views in Section 8.2 of this Decision.

22 Calgary Argument Paragraph 6.20 EUB Decision 2005-005 (January 31, 2005) • 19

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similar to that used by regulated natural gas utilities. However, the Board will address this matter in Section 8.2 of this Decision. The Board commends the AESO for the completion of the system improvements to facilitate multiple-block trading by existing operating reserves suppliers and therefore accepts the AESO’s explanation that operating reserve margins should be expected to decrease as compared to prior years. 5.2 Other Ancillary Services Forecast In addition to operating reserves, the AESO also procures a number of other Ancillary Services to maintain the secure and reliable operation of the AIES. Other Ancillary Services are typically procured through negotiated agreements between the AESO and one or several parties. A comparison of the AESO 2004 forecast for Other Ancillary Services costs with the approved 2003 forecast is provided in Table 5 below. Table 5. Other Ancillary Services Costs Other Ancillary Services 2004 Forecast

($M) 2003 Approved Forecast ($M)

Generator Remedial Action Schemes (RAS) 0.4 0.4 Black Start 2.2 2.2 Transmission Must Run (TMR) 49.3 26.1 Under Frequency Mitigation 6.5 5.2 Hydro Motoring 0.0 4.2 Fort Saskatchewan Load Shed 0.0 0.9 Poplar Hill 1.8 1.9 Interruptible Load Remedial Action Scheme (ILRAS) 1.1 0.5 Total Other Ancillary Services

61.3

41.4

Source: Application Table 2.3.2.1, p. 9 of 47 5.2.1 Generator Remedial Action Schemes The AESO enters into Generator Remedial Action Schemes (RAS) in order to respond to sudden loss of supply in order to stabilize system frequency following a system disturbance that might otherwise require the shedding of firm load. The Brazeau fast ramping scheme, procured through an agreement with TransAlta, is the only generator RAS scheme included in the AESO’s 2004 revenue requirement forecast. No parties raised any concerns with respect to the AESO’s $0.4 forecast of generator RAS costs. The Board has reviewed the costs and finds them to be reasonable. 5.2.2 Black Start Black Start service is acquired by the AESO from generators with the ability to self-start, and provide start up power to other generators. Black Start is integral to the AESO’s system restoration plan and enables restoration of the AIES in the event of a blackout. The 2004 Forecast amount for Black Start services of $2.2 million did not represent any change from the 2003 Approved Forecast. However, the 2003 Approved Forecast of $2.2 million was not achieved in 2003 due to the uncertainty surrounding liability protection. With the introduction of the new Liability Protection Regulation, Black Start service was expected to be fully contracted for 2004. 20 • EUB Decision 2005-005 (January 31, 2005)

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No parties raised any concerns with the $2.2 million forecast cost of Black Start services and the Board finds the forecast to be reasonable. 5.2.3 Transmission Must Run (TMR) TMR is generation required to be on-line and running at specific outputs in specific parts of the AIES in order to ensure adequate voltages are maintained following transmission or generation contingencies on the system. TMR service is primarily required to support the AIES in the Northwest area of Alberta. Commercial agreements negotiated by the AESO with its TMR suppliers are generally structured to compensates the TMR provider based on the ratio of the hourly pool price in $/MWh to the cost of natural gas in $/GJ. Accordingly, this ratio (referred to as the “market heat rate”) is a principal driver of the level of the TMR forecast. There is an inverse relationship between variable TMR payments and market heat rate such that the lower the market heat rate, the higher the TMR costs and the higher the market heat rate, the lower the TMR costs. The Application notes that the significant increase in the 2003 recorded cost of TMR as compared to the 2003 Approved Forecast arises from the 2003 actual market heat rate of 10.0 GJ/MWh being lower than the 11.3 GJ/MWh heat rate used to prepare the 2003 forecast. Similarly, the lower market heat rates predicted for 2004 of 8.8 GJ/MWh were expected to further increase the frequency that contracted TMR units would be required to dispatch. Due to the decline in the expected 2004 market heat rate, the 2004 Forecast of $49.3 million is substantially ($23.2 million) higher than the 2003 Approved TMR Forecast ($26.1 million). The Board is very concerned with the dramatic rise in TMR costs that first came to light in the Application. The Board notes that, whereas Decision 2003-077 reflected a forecast of $26.1 million, actual TMR costs incurred in 2003 were $45.2 million with the AESO forecasting a similar increase in 2004.23 The Board has indicated that the AESO should be granted considerable discretion to establish its own priorities in accordance with the AESO’s duty to ensure that the transmission system remains safe and reliable and is operated economically. However, the Board is concerned about the increased costs of TMR and would make the following observations. First, the Board is concerned that the Capital Projects Summary provided by the AESO in IPPSA-AESO-11 Attachment A does not include a project that would address voltage support requirements in Northwestern Alberta. The Board considers the absence of a capital project to address increasing NW TMR costs to be somewhat surprising in light of indications in the AESO’s Own Costs Application that NW development and reduced reliance on transmission must run generation would be a priority in the AESO’s 2004 transmission enhancement and expansion initiatives.24 Second, the Board is of the view that the increased TMR costs seen in 2003 (actual) and 2004 (forecast) is not a relatively short term phenomenon arising because of a temporary reduction in the market heat rate. In particular, the Board notes that to the extent that AESO long term

23 Application, Section 2.5, p. 17 24 Application 1322864, p. 8

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transmission planning may be contemplating the need for significant expansions in AIES transmission infrastructure on the basis of forecasts of significant additions of base load co-generation plants, the same scenario would also imply that market heat rates will also remain low so long as natural gas prices remain at or above recent levels. As such, to the extent that TMR costs remain inversely related to market rates in the future, the Board considers that there may be substantial cause for concern that TMR costs will be systematically persistent. In light of these factors, the Board expects that the AESO will take the Board observations into account in developing its long term transmission plan. In addition, the Board shares the concerns of FIRM with respect to the AESO’s willingness to disclose TMR-related information in its IR Responses. While the Board recognizes that the FIRM’s concerns related to the AESO’s response to FIRM-AESO-10, the Board noted other instances in which information sought to clarify the AESO’s TMR forecasts and recent cost record was not provided on the basis of a claimed commercial sensitivity. In this regard, the Board notes that IPCAA-AESO-07 appeared to be a straightforward request that the AESO provide a breakdown of TMR volumes and dollars on a regional basis but that the AESO declined to provide a response on the basis of the commercial sensitivity of the information sought. The Board notes that the AESO did not elaborate further on the nature of the perceived commercial sensitivity of such information in its response. The Board emphasizes that any refusal to provide confidential information must comply with the requirements of Section 29 of the Board’s Rules of Practice. As IPCAA did not seek a more informative response to its information request by filing a motion under the Rules of Practice and as no parties have objected to the AESO’s TMR forecast, the Board is prepared to accept the TMR forecast as reasonable. Notwithstanding, the Board would like to note that had IPCAA requested a better response to its undertaking, the Board may have been inclined to grant such a request. The Board considers that the type of information requested by IPCAA in this case is reasonably sought and helpful to understanding both the derivation the AESO’s forecasts and for the facilitation of an open planning process. For example, the Board notes that the Board’s decision in respect of the ATCO Electric Dover to Deerland transmission project depended to an extent on an assessment of the impact of different route alternatives on AESO projections of the Northwest region TMR under different routing alternatives.25 On August 16, 2004, the AESO filed an application to amend Article 24 of its Terms and Conditions, which provides for payments to generators for the provision of “conscripted” TMR services.26 On December 16, 2004, the Board ruled that the existing Article 24 would become interim effective December 17, 2004, so that any amendments to Article 24 determined to be reasonable by the Board may, if appropriate, be applied from and after that date. The Board notes that any changes to TMR costs arising from the disposition of Application 1357161 will be reconciled through Rider C adjustments and/or the disposition of the reconciliation of the AESO’s 2004 deferral accounts, as applicable. 5.2.4 Under Frequency Mitigation The AESO’s Under-Frequency Mitigation scheme is configured to automatically trip a specified amount of load if the system frequency drops below 59.5 Hz following a system disturbance. 25 Decision 2003-027, p. 12

26 Application No. 1357161.

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The AESO procures these services through contracts with service providers. The 2004 Forecast was based on 2003 Recorded costs and represents an increase of $1.3 million from the 2003 Approved Forecast amount of $5.2 million. No parties raised any concerns in regard to the AESO’s forecast cost for Under Frequency Mitigation, which the Board has reviewed and finds to be reasonable. 5.2.5 Hydro Motoring The AESO included a 2004 Forecast of zero as the AESO has determined that load and system developments have eliminated the need for Hydro Motoring service. The Board accepts the determination of the AESO that this Hydro Motoring service is no longer required and therefore accepts the AESO forecast of zero cost in respect of this cost item. Before leaving this matter, the Board notes that the AESO’s response to BR-AESO-06 suggests that the determination that Hydro Motoring was no longer required was made after the completion of a number of transmission and generation facilities in Central and Southern Alberta. The Board wishes to note the initiative of AESO staff in undertaking a review of the requirement for Hydro Motoring which has saved more than $4 million in 2004 alone. However, the Board considers that this matter serves as an example of the significant value that may be derived by AESO customers from the provision of adequate resources to facilitate proactive planning. The potential for similar situations to occur in the future may also be reduced through the requirement for the AESO to prepare long range planning documents in accordance with the requirements of the Regulation. 5.2.6 Fort Saskatchewan Load Shed A 2004 Forecast of zero has been assigned to Fort Saskatchewan Load Shed service as a result of upgrades completed in the region. The Board accepts the determination of the AESO that this service is no longer required. 5.2.7 Poplar Hill Agreement The AESO procures TMR generation and voltage support through a long-term contract between the AESO and ATCO Power in order to maintain transmission reliability in the Northwest part of the province. Because the majority of the payment under the agreement is fixed, the forecast is not affected by variations in heat rates to the same extent as TMR provided under agreements with other TMR suppliers. No parties raised any concerns in regard to the AESO’s forecast in respect of the Poplar Hill agreement, which the Board has reviewed and finds to be reasonable 5.2.8 Interruptible Load Remedial Action Scheme If the Alberta-BC intertie tie trips concurrent with high levels of import, the system will become generation deficient, system frequency will decline and firm load would have to be shed quickly in Alberta to arrest the frequency decline and maintain system reliability. Under an Interruptible Load Remedial Action Scheme (ILRAS), the AESO contracts with Alberta loads that are armed to trip automatically if the Alberta-BC intertie is disrupted during high import periods.

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ILRAS service has historically been provided under a contract with FortisAlberta Inc. (Fortis).27 However, Fortis has expressed concerns that while all Alberta consumers benefit, as the sole supplier to the AESO, a subset of Fortis’s customers are taking all the risk associated with possible outages that may arise under the ILRAS arrangement.28 To address Fortis’s concerns, the AESO issued a Request for Expressions of Interest (RFI) for ILRAS. Through the RFI, the AESO determined that other suppliers (industrial plant owners) would be interested in providing a similar service. However, as additional service providers would require additional capital investments to upgrade communication equipment to comply with the technical requirements of ILRAS service, the AESO expected that procuring ILRAS from additional service providers would result in higher overall costs as compared to the existing arrangement with Fortis. The AESO’s 2004 Forecast for ILRAS has increased by $0.6 million to $1.1 million as compared to the 2003 Approved Forecast of $0.5 million. According to the AESO in the Application, the forecast increase was based on the AESO’s estimate of the incremental costs that would be incurred if the AESO procured this service competitively from new suppliers. As the AESO did not consider that it would be reasonable to incur a substantial cost increase without a corresponding increase in service levels, the AESO intended to continue to procure ILRAS from Fortis. However, in recognition of the impact of this Decision on Fortis customers, the AESO proposed to engage in further discussions with Fortis and other stakeholders regarding the appropriate cost and other parameters of ILRAS service. The AESO indicated that it intends to pursue formalizing a long-term agreement with Fortis, but was not advancing conversations with the other potential suppliers at this time. The AESO considered that it would be inappropriate to pursue further discussions with ILRAS suppliers other than Fortis if the purpose of the discussions would only be to assist in benchmarking a new charge level for the existing service provider. No party raised any concern with the AESO’s forecast of ILRAS costs. However, the Board finds the AESO’s request for an increase based on the incremental cost of procuring ILRAS from other suppliers to be inconsistent with its clearly stated intention not to pursue discussions with other potential suppliers. Nevertheless, the Board is prepared to accept the forecast for 2004 given that it will be subject to deferral account reconciliation in due course and given the direction to the AESO below. The Board also notes that the renewal of ILRAS service with Fortis does not address the concern that a subset of Fortis’s customers may be taking risk associated with possible outages, notwithstanding that these risks do not appear to be substantial.29 Accordingly, while the Board has no specific objections at this time to the continuation of ILRAS service arrangements with Fortis, the Board considers that the AESO should continue discussions with other potential suppliers at this time. Accordingly, the Board directs the AESO to report on the outcome of those discussions with other potential suppliers in its next possible tariff application.

27 Formerly Aquila Networks Canada (Alberta) Ltd. 28 Application, p. 11 of 47

29 FIRM-AESO-12(a)

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5.3 Ancillary Services – General Provisions

5.3.1 AESO Ancillary Services Procurement Practices The AESO is required by section 17(f) of the EUA to manage and recover the costs for the provision of ancillary services. The Board has considered Calgary’s concern regarding the long term fairness and transparency of the ancillary services markets and, in particular, the increasing volume of over the counter (OTC) purchases. In the Board’s view, however, an investigation of the long term effects of OTC procurement is primarily a market design matter and may be more properly pursued in conjunction with the review of the design of the electricity wholesale market currently being conducted by the MSA and the Department of Energy. Accordingly, the Board will not direct the AESO to undertake a review of the OTC market or to investigate whether any ancillary services instruments currently being purchased through the OTC market should instead be purchased through Watt-Ex. 5.3.2 Ancillary Services Self-Supply Arrangements The Board notes that Calgary urged the AESO to look at allowing customers to make their own financial arrangements for ancillary services through market-based transactions or through bilateral transactions with ancillary service providers. In support of its position, the Board notes that Calgary indicated that an examination of customer participation in the ancillary service market would be in compliance with the Board’s directive, at page 58 of Decision 2001-32, to include rate proposals for customer self-supply of ancillary services in a future GTA.30 Calgary submitted that the Board should direct the AESO to consult with customers to evaluate and identify arrangements whereby customers may make their own financial arrangements for ancillary services and that any such arrangements that are devised should be outlined in the 2005 Phase I GTA.31 Because self-supply arrangements would be addressed through changes to the AESO’s T&Cs, the Board considers this issue to be a Phase II matter, which would be more appropriately deliberated in conjunction with the AESO’s 2005 Phase II Application or a subsequent Phase II Application proceeding. The Board encourages the AESO to engage stakeholders in consultation with respect to this matter. 5.3.3 Ancillary Services Requirements Study Calgary submitted that while it understands and supports that AESO’s rationale for procuring ancillary services in accordance with the guidelines, policies, and/or standards published by the North American Electric Reliability Council (NERC) and the Western Electricity Coordinating Council (WECC), in Calgary’s view, some of the reasons for these standards have been in place for many years and may no longer be optimal.32 Calgary submitted that the Board should direct the AESO to prepare a study of Alberta’s ancillary services requirements and report on how those requirements match with applicable NERC and WECC standards. 30 Calgary Argument paragraph 7.10 31 Calgary Argument paragraph 7.11 32 Calgary Argument paragraph 7.12

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The Board notes that Directive 3 from Decision 2002-099 directed the Transmission Administrator to develop an action plan for addressing the appropriate reliability criteria for planning and operating the AIES. The Board further understands that a review of the appropriate reliability criteria for the AIES undertaken pursuant to Directive 2002-099-3 is currently underway under the direction of the AESO. Noting this initiative, the Board does not consider that it is necessary to provide a specific direction to the AESO to study Alberta ancillary services requirements in relation in light of applicable NERC and WECC standards at this time. 5.3.4 Ancillary Services Procurement Code of Conduct Calgary commented that, while the Board was not persuaded in its disposition of the 2004 AESO Own Cost proceeding to find it necessary to establish a code of conduct for the AESO, a number of issues, particular issues related to ancillary services trading, beg for standards and rules to be established. Calgary submitted that while one option may be to leave standards in the hands of the AESO, further delay in addressing potential conflicts could be detrimental to both individual stakeholders and the developing Alberta electricity market.33 Pursuant to section 16 of the EUA, the AESO has the dual responsibility to provide for the safe, reliable and economic operation of the AIES and to promote a fair, efficient and openly competitive market for electricity. Consequently, the Board considers that practices regarding the procurement of ancillary services must strike an appropriate balance between safe, reliable and economic operation and the promotion of a fair, efficient and openly competitive market. In the Board’s view, if the AIES is not safe, reliable and economic, a fair, efficient and openly competitive electricity market cannot develop. Therefore, it would not necessarily be inappropriate for the AESO to give greater weight to considerations of safety and reliability than to market fairness and efficiency if to do otherwise would compromise the safety and reliability of the system. By the same token, if the AESO could achieve the same level of safety and reliability in two different ways, one of which promoted market efficiency and fairness and one of which did not, it might be unreasonable for the AESO to choose the manner which did not promote the development of the market. Depending on the nature of the safety or reliability concern and the attendant impact on market development, it might be reasonable for the AESO to proceed in a manner that would achieve the necessary level of safety and reliability at some expense to the development of the market. In other words, the Board considers the AESO’s responsibility to provide a safe, reliable and economic AIES to have a certain degree of primacy over its responsibility to promote market development.34 Accordingly, it is not clear to the Board that the AESO staff responsible for ancillary services procurement should necessarily be restricted to only have access to information that is generally available to other market participants as Calgary suggests. Similarly, the Board considers at this time that, while the AESO staff responsible for the procurement of ancillary services (AS) should not be permitted to attempt to reduce their ancillary services purchases through an ability to influence the actions of AESO system control staff, the reverse situation whereby system control centre staff provide may provide real-time information to AESO ancillary services 33 Calgary Argument paragraph 9.11

34 The Board notes the different verbs used to express the two aspects of the AESO’s overall duty in section 16: the AESO has a duty to “provide” for the safe, reliable and economic operation of the AIES; the AESO is bound only to “promote” a fair, efficient and openly competitive market for electricity.

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procurement staff regarding elevated system risk should not be impeded though rules primarily designed to equalize the information available to AESO AS procurement staff and potential AS suppliers. In light of the foregoing, the Board is not persuaded at this time that it is either necessary or appropriate for the Board to direct the AESO to devise a Code of Conduct to govern the AESO’s trading/procurement practices in respect of ancillary services. In any event, the Board notes that the market fairness and efficiency issues of concern to Calgary may be most appropriately addressed in the context of the review of the design of the Alberta Wholesale Market currently being conducted jointly by the AESO and the Alberta Department of Energy. The Board has addressed the broader issue of an AESO Code of Conduct in Section 7 below. 6 TRANSMISSION LOSSES

The AESO is responsible to pay for the cost of losses and recovers these costs from generators, importers and exporters through a "normalized loss factor" applied against generator outputs, and imports and exports. The recovery of loss costs from each generator is equal to that generator's total annual output in MW-hours multiplied by that generator's normalized loss factor multiplied by pool price. The 2004 forecast of loss costs and volumes as compared with forecasted and recorded prices and volumes from prior years is set out in Table 6 below: Table 6. Transmission Losses Cost and Volumes 2004 Forecast 2003 Recorded 2003 Forecast 2002 Actual Transmission Losses Cost $159.9M $174.6M $142.7M $ 115.5M Volumes (GWh) 2,873 GWh 2,750 GWh 2,930 GWh 2,615 GWh Average Hourly Volume (MWh) 327 MWh 314 MWh 335 MWh 299 MWh Source: Application Table 2.4.1, p. 14 of 47 6.1 Transmission Losses Forecast Methodology The AESO has adopted a revised loss forecasting approach using data produced by the probabilistic load and generation dispatch modules described above in Section 3 of this Decision. Under the AESO’s method, a multi-variable correlation analysis is performed to establish the relationship between individual generator output obtained from the Generator Dispatch Module and the overall system losses. A simulation of the system losses for the forecast period is then re-computed using the individual generator outputs derived from the generation dispatch module. The Board notes that while certain parties took issue with the forecast record of the AESO in respect of transmission losses, no parties proposed an alternative to the forecasting methodology adopted by the AESO for the 2004 Application. Having reviewed the AESO’s adopted methodology and the resulting losses forecast in these circumstances, the Board finds them both to be reasonable.35

35 The Board notes that transmission losses will in future be determined according to the methodology prescribed

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6.2 Management of Transmission Losses The Board notes the Group’s submission that the EUA imposes a responsibility on the AESO to manage the cost of losses in a prudent manner and given this responsibility, the Board should direct the AESO to optimize line losses and to report on its activities. The Board considers that the nature of the AESO’s obligations to manage transmission losses may largely be considered to be a component of a broader question about the nature and extent of the AESO’s obligation to manage flow-through costs. The Board has already provided its views with respect to the latitude to be accorded to the AESO in its discussion on prudence in Section 2 of this Decision. Therefore, the Board does not consider it necessary or appropriate at this time to give specific directions to the AESO in regards to the management of line losses. 7 OTHER MATTERS

7.1 AESO Code of Conduct Article 12 of the Settlement provided that, pursuant to AESO commitments in the 2004 Own Costs proceeding, the AESO would promptly begin stakeholder consultations on its code of conduct, or other measures, to balance the AESO’s prioritization of, and activities related to, all its duties and obligations under the EUA.36 The concerns of parties who urged the Board to establish a rigorous process and timeline for the development of an AESO Code of Conduct appeared to be driven by their view that the AESO ought to be governed by a code based on the principles outlined in the Inter-affiliate Code of Conduct approved for the ATCO Group in Decision 2003-040 (ATCO Code). The ATCO Code was developed to address potential conflict issues that may arise between investor-owned utilities that may obtain from, or provide services to, non-regulated affiliates. The primary concern of the Board in establishing the ATCO Code was to protect regulated customers from possible abuses of the relatively complex relationships between regulated utilities and their unregulated affiliates. In contrast, the AESO was established by the EUA to carry out significant duties and responsibilities required by statute. While the Board addressed issues pertaining to the allocation of AESO Own Costs as between “regulated” and “non-regulated” activities, the Board notes that both of these basic activity classifications relate to statutory responsibilities rather than differentiating activities related to obtaining a regulated rate of return from activities that are related to obtaining returns from the competitive market. The Board notes that pursuant to section 10(2)(a)(i) of the EUA, the AESO must ensure that its bylaws establish a Code of Conduct to govern the actions of AESO members, officers, employees and agents. The Board also notes that the AESO has reiterated commitments that it offered within the 2004 Own Costs module to commence a stakeholder consultation process regarding the establishment of an AESO Code of Conduct. Finally, the Board notes that any person may make a complaint about the conduct of the AESO pursuant to section 26 of the EUA.

36 Although the Settlement was withdrawn, the Board finds reference to Article 12 of the settlement to assist in understanding the comments of parties in respect of this issue.

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Accordingly, the Board agrees with the AESO that it is not necessary for the Board to provide additional directions to the AESO about the structure and timelines to be followed in advancing the development of an AESO Code. 7.2 Consideration of Supply Customer Views in EUB Decisions The Board acknowledges the submission of the Group that power producers are customers of the AESO, that they form an integral part of the AIES and that the actions of power producers have a significant impact on end-user electricity costs. The Board can reassure the Group that its disposition of any application is based on a reasoned consideration of the evidence filed and the on merits of the arguments of all parties, including supply customers. The Board agrees with IPCAA that the proposed changes in cost responsibility as between load and supply customers introduced by the Regulation may affect how the Board takes into account the views of those different groups of customers. However, it is unnecessary for the Board to decide whether, and to what extent the Regulation may have done so. These changes to the Regulation will apply only to the AESO’s tariffs for 2006 and forward and can be considered by the Board in the context of those future proceedings as required. 7.3 Minimum Application Filing Requirements / Uniform System of Accounts The AESO has already filed its 2005 tariff application and must file its 2006 tariff application on or before February 1, 2005, as required by the Regulation. A Board decision on the AESO’s 2006 application must be issued no later than September 1, 2005. The Board has now directed that the 2005 and 2006 applications be dealt with in one proceeding. In these circumstances, it is unlikely that any consultations the Board might conceivably direct parties to undertake at this time or the near future could reasonably be expected to influence the form and content of the AESO’s 2006 application. In addition, there is a reasonable basis for concern that consultations in relation to these matters might become a significant distraction to AESO staff as they deal with the 2005 and 2006 applications in the coming months. Further, without concluding so, the Board is not convinced that there would be significant benefits to integrating the AESO into the current efforts to devise a uniform system of accounts to apply in respect of Board regulated utilities (TFOs and DISCOs) at this time, if at all. 7.4 Benchmarking As discussed previously, the Board considers that the legislature has conferred an enhanced responsibility and accountability on the AESO. The Board has determined that it is also the intention of the legislature that the AESO be granted additional discretion in the fulfillment of its statutory mandate. In recognition of this finding, and in light of the heavy near term workload imposed on the AESO to file and defend a fundamentally restructured 2006 Tariff, the Board does not consider that Calgary’s request for the Board to direct the AESO to commence a consultative process in respect of benchmarking is warranted at this time. Although some time has now passed since the AESO was created in 2003, the AESO is still in the midst of a significant transition. The Board considers that the AESO’s primary responsibility is to “keep the lights on” and therefore the Board is reluctant at this time to impose requirements on the AESO that may divert the AESO from addressing higher priority matters to ensure this is

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the case. Nevertheless, the Board fully expects the AESO to act prudently or face the potential disallowance of actual costs in the deferral account reconciliation process. The Board notes that the Own Costs portion of the AESO revenue requirement forecast is based on an assumed set of anticipated activities for a forecast year. As such, the Board considers that Calgary and other stakeholders may reasonably expect that the activities projected in the Own Costs forecast will be completed in the foreseen manner. If certain of the projected activities are not completed within the applicable test year, the Board expects that any AESO choice to divert resources to other activities will be prudent and that any resulting cost savings that may arise from not completing projected work will be reflected in the AESO’s actual test year costs. The Board notes that the AESO remains at risk that its overall performance is subject to prudence evaluation after the fact such that the AESO should be fully incented to make appropriate decisions in the normal course. 7.5 Negotiated Settlement Matters In the Introduction to this Decision, the Board outlined the request by the AESO for approval to commence an NSP, the filing of the Settlement, and the subsequent withdrawal of the Settlement. Because the Board had some concerns with the conduct of some parties, the fairness and effectiveness of the NSP, and the difficult situation the Board faced in considering whether to approve a non-unanimous, contested Settlement that was signed primarily by supply customers but no significant load customer or customer group, the Board wishes to comment on certain matters relating to the NSP and the Settlement. It is not necessary for the Board to rule on whether IPCAA breached the confidentiality restrictions imposed on a NSP by both the EUA and the Board’s Guidelines. However, it does appear to the Board that the AESO’s view that IPCAA disclosed certain positions that it and the AESO had taken during the NSP has merit. The Board cautions all participants in a NSP to be diligent in maintaining confidentiality of the information exchanged during the process. The Board acknowledges the frustration with the NSP expressed by IPCAA, but dissatisfaction with that process does not entitle any party to disclose otherwise confidential information in a Board proceeding. In any event, the Board would have had some general concern with the fairness of the NSP if the Settlement had not been withdrawn. Based on the material on record, it appears to the Board that there may have been difficulties with the effectiveness, and possibly the fairness, of the process that were encountered early on. The Board is particularly concerned that the NSP may not have met the requirements of Sections 1.4 (process clear and agreed to at outset) and 2.1 (reasonable opportunity to address issues) of the Guidelines. However, the Board makes no findings in this respect in the circumstances. The Board is also concerned that the AESO was previously signaling to parties that the AESO expected to terminate the settlement discussions and move onto argument and reply on the Application, which perhaps lulled parties like Calgary and IPCAA into believing that they should focus on the Application. However, the AESO changed its position and proceeded to conclude a Settlement with only some parties without clearly communicating this intention in a manner that respected the interests of other parties and the Board, particularly the AESO’s views on the prospects of a settlement. The Board expects any applicant engaged in a NSP to communicate these matters clearly to all parties and the Board to avoid any confusion and resulting delay in

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Board consideration of matters. It may be that clearer communication on the part of the AESO could have resulted in more load customers participating and agreeing to the Settlement. What resulted from the NSP was a somewhat lopsided Settlement that was executed primarily by supply customers after Calgary and IPCAA chose to withdraw from the process. Not only was the Settlement not unanimous, it was contested by Calgary and IPCAA, although they were prepared to agree to the only two substantive features of the Settlement, namely the increased revenue requirement requested in the Application and changes to rates for the balance of 2004 after Board approval of the Settlement. The AESO, however, objected to the Board “cherry picking” from the terms of the Settlement if it was not prepared to approve the Settlement as a whole. In these circumstances, the Board found itself in a difficult position, having to consider whether to approve a contested Settlement, which arose from an NSP that may not have conformed to the Board’s Guidelines, or to approve an Application that didn’t provide for rates to change as a result of the increased revenue requirement. Although the Board does have jurisdiction to consider and approve a contested settlement,37 the Board found neither option to be particularly attractive in the circumstances.38 Any settlement, however obtained, is not necessarily beneficial to the Board or other parties and the Board has considerably difficulty accepting the AESO’s decision to pursue a contested settlement in the circumstances because:

• All issues remained on the table, requiring the Board to consider the merits of both the Settlement and the Application.

• The AESO’s decision to pursue the Settlement raised the significant question of how

Board approval might affect future NSPs and the likelihood of their success. • The AESO did not satisfactorily explain why it did not, instead, propose the alternative of

amending the Application to permit an interim change to updated rates, which would have apparently enjoyed the support of all parties and would have easily accommodated the AESO’s decision not to file a 2004 Phase II application and might have kept the Board and parties reasonably on track.39

Recognizing that the Settlement was withdrawn and therefore, the Board did not have to make any determinations in relation to the foregoing concerns and questions, the Board would nonetheless like to caution parties that it may not look favourably on a party presenting it with such a settlement in a future case. Where difficulties similar to those that apparently arose in this case are encountered, the Board encourages parties to consider whether the NSP should be continued. In addition, parties may seek the Board’s assistance as provided in Section 1.5 of the Guidelines.

37 As per Section 12.4 of the Guidelines. For an example, see Decision 2001-04, TransAlta Utilities Corporation,

2001 Transmission Facility Owner Tariff and Negotiated Settlement (January 12, 2001). 38 The Board’s concern with approving the Application only as filed was exacerbated by the AESO’s eventual

advice to the Board and parties that it did not intend to file a Phase II application where such rate changes might have been addressed.

39 The AESO’s late change of position on the Phase II question resulted in significant delay in the Board’s consideration of the Settlement and the Application and created unnecessary confusion for the Board and parties.

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8 PHASE II MATTERS

Although this Application is a Phase I application, as the Board noted in the Introduction to this Decision, Phase II concerns were raised and, to some extent, were woven into the Board’s consideration of the Application. As a result of these concerns, the Board did direct the AESO to file interim rates to be effective January 1, 2005, based on the 2004 revenue requirement approved in Order U2004-429 for the reasons given in this Decision. As well, some outstanding Phase II matters require brief comment by the Board. 8.1 Requirement for Updated Phase II Rates The Application indicated that approval of the applied-for 2004 forecast revenue requirement was required for rate-setting purposes. However, the Application also provided that the AESO only intended to adjust rates for system access service using the overall approved 2004 forecast revenue requirement following Board approval of a 2004 and 2005 Phase II tariff application that, at that time, the AESO expected to file by June 2004. While the AESO had included rate calculations taking into account the overall 2004 forecast revenue requirement and 2004 forecast billing determinants, the AESO did not request that the Board approve adjustments to its tariff rates at that time. Nevertheless, in the Application cover letter, the AESO noted that stakeholders might wish to adjust the existing tariffs in order to minimize the use of the Rider C and/or the magnitude of adjustments arising from a year-end adjustment process. In consideration of the AESO’s support for minimizing the use of Rider C and year-end adjustments in general, the AESO requested the NSP, which would include discussions about the adoption of measures that would allow a transition to updated rates to occur within 2004. However, the AESO made it clear that if the negotiations were not successful and the Board was called upon to adjudicate the Application then:

• the hearing issues should be confined to consideration of the remaining elements of the 2004 forecast revenue requirement,40 and

• all tariff and rate design matters should be deferred until the AESO filed its Phase II Application, then expected to be filed by June 2004.

The Settlement filed by the AESO on July 16, 2004, included provision for adjustments to AESO rates reflecting the AESO’s forecast Phase I revenue requirement as agreed to in the Settlement. The adjusted rates set out in Schedule B of the Settlement were identical to the rates filed “for information purposes” with the Application. With the withdrawal of the Settlement on November 2, 2004, the AESO confirmed that its rates approved by the Board in Decision 2003-077 would continue in effect for the remainder of 2004 and until such time as new rates were approved, possibly well into 2005.41 Whether they supported the Settlement or not, all parties agreed that it was desirable to adjust rates for the balance of 2004 based on the 2004 forecast revenue requirement. The Board received no comments from any party in response to the indication accompanying the AESO’s withdrawal of the Settlement that, owing to the lateness in 2004, no rate adjustment would be

40 i.e. other than 2004 Own Costs approved in Decision 2004-012.

41 The AESO did not intend to apply for interim rates to be effective January 1, 2005.

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made so that 2003 rates would continue until the Board approved new rates likely sometime in 2005. In the Board’s view, leaving 2003 rates in place for such an extended period of time is not desirable and may result in unreasonable impacts on customers once the AESO’s 2004 and 2005 deferral accounts are reconciled in due course. In the circumstances, the Board considers that it would be most reasonable for these interim rates to be the rates that would have been approved by the Board if it had approved the Settlement, namely, 2003 rates adjusted to reflect the approved 2004 revenue requirement. For these reasons, in Order U2004-429, the Board directed the AESO to file an application for interim rates to be effective January 1, 2005. The Board notes that this application was filed with the Board on December 8, 2004 and approved by the Board in Order U2004-476 on December 23, 2004. 8.2 Deferral Accounts & True Up For the reasons set out earlier in this Decision, the Board has determined that it is just and reasonable to approve the deferral accounts requested by the AESO in the Application. The Board agrees with the AESO that, while potentially of interest down the road, Calgary’s discussion of an alternate mechanism to more regularly true up those aspects of the forecast revenue requirement along the lines of mechanisms used for truing up natural gas rate commodity forecasts was not relevant to the Board’s disposition of the present Phase I Application. The Board considers that such a true up mechanism is inherently related to Phase II rate design matters. However, in light of the AESO’s determination that it would not make a 2004 Phase II filing, the Board considers that this issue should be pursued by Calgary in the context of the 2005/2006 Application proceeding, if desired. 8.3 Customer Owned Substation/Customer Owner Transmission (COS/COT)

Credits FIRM noted the comparatively long period during which COS/COT credits have been made available on an interim refundable basis. FIRM recounted the expectations of the Board as expressed in Decision 2003-077 that COS/COT matters would be fully addressed in the AESO’s 2004 tariff proceeding. FIRM emphasized its concern that the resolution of outstanding COS/COT issues might once again be delayed in the event that the AESO were to combine the 2004 and 2005 Phase II tariff into a single application. FIRM also recommended that the Board should declare its expectations that the AESO would file a 2004 Phase II application notwithstanding the proposed adoption of new 2004 rates as set out in the negotiated settlement and that the interim refundable nature of COS/COT credits for 2004 would not be altered until the Board made a final ruling on the matter. As noted in Section 1 of this Decision, on October 1, 2004, the AESO filed correspondence in respect of Application 1357161 (Article 24 Amendment Application) which indicated that, contrary to prior representations, the AESO did not intend to file a 2004 Phase II Application. However, in correspondence to Board dated October 8, 2004, FIRM still considered that a Phase II proceeding was necessary to deal with both the AESO’s Article 24 Amendment Application and the outstanding , COS/COT credits issues. However, having regard to the congested

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regulatory schedule and the filing of the AESO’s 2005 Tariff Application,42 FIRM submitted that the AESO should, as an administrative procedure, file a separate AESO 2004 Phase II Application on the remaining issues (other than Article 24 amendments) with a proposal that their consideration take place in the AESO’s 2005 Tariff proceeding.43 In conjunction with this proposal, FIRM requested that the Board confirm the continuation of the interim refundable nature of COS/COT credits for 2004 and beyond until these issues have been finally addressed by the Board. The Board shares FIRM’s concern with the delays in the disposition of COS/COT credits matters as well as FIRM’s discomfort with the long period over which COS/COT credits have been made available on an interim refundable basis. However, in light of the present circumstances, the Board accepts and confirms that COS/COT credits must continue to be available only on an interim refundable basis during 2004 and until they are finally dealt with. The Board expects these matters to be finally dealt with in the context of the AESO 2005/2006 Tariff proceeding. Confirmation from the Board that the AESO shall continue to employ its existing and approved tariff (including Rate Riders B and C), and annual deferral account reconciliation adjustment process for the calculation of rates and the recovery of all actual incurred costs until such time as the Board approves changes to those processes. 9 CONCLUSION

For the reasons set out in this Decision, the Board issued Order U2004-429 approving the AESO’s applied-for 2004 revenue requirement of $757.6 million and directing the AESO to file interim rates to be effective January 1, 2005, based on the approved 2004 revenue requirement. Because Order U2004-429 has already approved the 2004 revenue requirement, the Order below only relates to the balance of the relief requested in the Application, including deferral accounts.

42 Application 1363012, filed October 3, 2004

43 At the time of the correspondence, the Board had not yet ordered that the 2005 and 2006 tariff proceedings would be combined.

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10 ORDER

For and subject to the reasons set out in this Decision, IT IS HEREBY ORDERED THAT: 1) The deferral accounts requested by the AESO in the Application are approved. 2) Subject to Order U2004-476, the AESO shall continue to employ its existing and

approved tariff (including Rate Riders B and C) and annual deferral account reconciliation adjustment process for the calculation of rates and the recovery of all actual incurred costs until such time as the Board approves changes to those processes.

Dated in Calgary, Alberta, on January 31, 2005. ALBERTA ENERGY AND UTILITIES BOARD (original signed by) R. G. Lock, P.Eng. Presiding Member (original signed by) Gordon J. Miller Member (original signed by) J. R. Nichol, P.Eng. Member

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APPENDIX 1 – PARTIES SUBMITTING ARGUMENT & REPLY

Party Representing Alberta Electric System Operator (AESO)

Alberta Electric System Operator

ATCO Electric (AE) ATCO Electric Ltd. The Cities City of Lethbridge

City of Red Deer FIRM Customers (FIRM) Alberta Association of Municipal Districts and Counties

Alberta Federation of REA’s Ltd. Alberta Irrigation Projects Association Alberta Urban Municipalities Association Aboriginal Communities Consumers Coalition of Alberta Public Institutional Consumers of Alberta

The Group ASTC Power Partnership Independent Power Producers Society of Alberta TransCanada Energy

Industrial Power Consumers Association of Alberta (IPPCA)

Industrial Power Consumers Association of Alberta

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APPENDIX 2 – ORDER U2004-429

Appendix 2 - Order U2004-429.pdf

(Consists of 1 Page)

38 • EUB Decision 2005-005 (January 31, 2005)

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APPENDIX 3 – 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. Accordingly, the Board directs the AESO to report on the outcome of those discussions with other potential suppliers in its next possible tariff application. .............................................. 24

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MADE at the City of Calgary, in the Province of Alberta, on

General Tariff Application Order U2004-429

2nd day of December 2004.

Alberta Electric System Operator 2004 Phase I Revenue Requirement Application

WHEREAS the Alberta Energy and Utilities (Application) by the Alberta Electric System revenue requirement, which includes the AESBoard in Decision 2004-012; AND WHEREAS the Board considers it in thRequirement for reasons to be given at a later AND WHEREAS the AESO will not be filing AND WHEREAS the AESO has not applied AND WHEREAS the Board does not conside2003 rates to continue until the Board determpotentially significant impact of AESO deferr AND WHEREAS interested parties generallyreflect the approved 2004 Revenue Requirem AND WHEREAS the Board will, in due courmaking this Order and addressing the other re THE ALBERTA ENERGY AND UTILITIESUTILITIES ACT, S.A. 2003, C. E-5.1, HEREB (1) The Revenue Requirement requested b

in the as filed amount of $757.6 Millio

(2) No later than December 15, 2004, the upon the approved 2004 Revenue Req

END OF DOCUMENT

EUB Order U2004-429

ALBERTA ENERGY AND UTILITIES BOARD

Application No. 1343002

Board (Board) currently has before it an application Operator (AESO) for approval of its 2004 forecast O’s “Own Costs” previously approved by the

e public interest to approve the 2004 Revenue date;

a 2004 Phase II application;

for interim rates to be effective January 1, 2005;

r it in the public interest for the AESO’s existing ines the AESO’s 2005 Phase II, in part due to the al account balances over such a long period;

supported an adjustment of the AESO’s rates to ent;

se, issue a Decision setting out its reasons for quests made by the AESO in the Application;

BOARD, PURSUANT TO THE ELECTRIC Y ORDERS THAT:

y the AESO for the test period 2004 is approved, n.

AESO shall file with the Board interim rates, based uirement, to be effective January 1, 2005.

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