bcuc-aeso-1 · aeso recommends that a restriction be placed upon the use of ptp service by the...

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BCUC-AESO-1 Reference: Ex. C9-5, Evidence of AESO, p. 6

Ex. B1-4, IR No. 1.14.3

Preamble: The AESO evidence states that 100% of long-term PTP service for the past two fiscal years has been purchased by BC Hydro. The statement provides as support a reference to the BCTC Response to BCUC information request No.1.14. The data provided in that response (Ex. B1-4, IR No. 1.14.3) only extends to fiscal 2001/02 and does not identify customers by name.

Request: To clarify the record, is the AESO’s statement referring to fiscal years 2002/01 and 2001/02, and on what basis has the AESO correlated BC Hydro to a particular customer number?

Response: The excel spreadsheet, entitled “bcuc_ir_1-14.3.xls”, was posted on the BCTC website and contained data for the past 5 fiscal years, including 2002/2003 and 2003/2004, at rows 119 to 147 in the spreadsheet. The AESO reference for the data was the excel spreadsheet.

The AESO notes that the data provided in the Acrobat file containing BCTC’s Response to Information Request No. 1. 14.3 reference a 5 year period (April 2000 to April 2004) but did not show the 2002/2003 and 2003/2004 data.

BCTC’s response to the AESO 2 5.2 indicated that Customer 2 in Response 1.14.3 was BC Hydro.

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BCUC-AESO-2

Reference: Ex. C9-5, Evidence of AESO, pp. 8-10 Receipt and Delivery Point Flexibility

Preamble: AESO notes in regard to Receipt and Delivery Point Flexibility that PTP-only customers have no ability to “park” transactions while finding a buyer and cannot establish a trading “hub” because they do not have Network Load, which allows the Network customer to gain a competitive advantage.

AESO recommends that a restriction be placed upon the use of PTP service by the Network customer and its affiliates to address its concerns with Receipt and Delivery Point Flexibility.

Request: 2.1 Is the competitive advantage of the Network customer referred to in this context gained on the basis of the structure of the OATT, or rather on the characteristics of the Network customer compared to PTP customers? Please explain.

2.2 Would a competitive advantage that arises on the basis of differences between customer characteristics constitute undue preference in the OATT?

2.3 Please describe in some detail the restriction that AESO would recommend and how it would be implemented and administered.

2.4 Please explain how such a restriction would reduce the competitive advantage afforded a Network customer. Would the restriction remove entirely the competitive advantage afforded the Network customer?

Response: 2.1 The competitive advantage associated with Receipt and Delivery Point Flexibility is due to the structure of the OATT. The structure establishes and distinguishes Network Service and PTP service. Flexibility is inherent in the Network service and not in the PTP service. A Network Customer is the only party who can make PTP reservations from import POR's to their Network Load POD and then make PTP reservations from freed up generation resource POR's to export POD's. Any Network Customer is advantaged compared to PTP customers, regardless of the characteristics of the Network Customer.

The structural advantage needs to be considered in view of the facts and circumstances in BC. These are listed in the AESO’s Evidence at A.12 and further discussed in BCTC-AESO-2.1.

There could also be secondary considerations in assessing the magnitude of competitive advantage conferred by the structure to the network customer. Network Customers with certain characteristics may be better able to capitalize on the on the flexibility provided compared to other Network Customers. In the BC situation, the Network Customer has substantial network resources, including substantial energy storage capability which permits it to capitalize on the flexibility provided more

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BCUC-AESO-2 than a Network Customer without such capability.

In theory, a way to avoid the inequitable treatment of PTP customers is for PTP customers to become network customers. Such a movement is unlikely to occur in BC for a number of reasons.

First, only selected PTP customers meet the requirements of Network Service. Network service is only available to customers serving loads in BC. Section 29.1 of the terms and conditions described conditions to become a network customer. The requirements include descriptions of the network load to be served at each delivery point.

Second, among customers that meet the requirements of Network Service, there appears to be little prospect to move to Network Service at any time soon. Industrial customer’s stated preference for customer choice is a “Buy-Sell” arrangement using BC Hydro’s NITS contract as noted at page 21 of BCTC’s application.

Thirdly, most existing and potential PTP customers including IPP's and out-of-province entities do not serve loads in BC and therefore do not meet the requirements for Network service.

Thus, the competitive advantage conferred to the existing single Network Customer in BC through the structure will remain a feature for some time. Such a feature is the reality in BC and the OATT should reflect this reality.

If additional Network Customers do begin to evolve, the Commission can address such changes through periodic reviews of the OATT.

2.2 A competitive advantage that was completely independent of a tariff’s structure or characteristics would not constitute undue preference in the tariff. A competitive advantage partially or completely due to a tariff’s structure or characteristics may contribute to or create an undue preference. In such cases, the specifics of the tariff and the magnitude of the competitive advantage would need to be examined on an individual basis.

In this case, the competitive advantages raised by AESO are, in the AESO’s view, due to the structure and characteristics of the OATT and the magnitude of the inequity is substantial giving rise to the AESO’s requests for amendments.

2.3 The AESO envisions its recommended restriction would operate based on the following parameters:

(1) One half of the available transfer capacity of the Alberta-BC interconnection (both directions) should be set aside for reservation by PTP customers other than the Network Customer and its affiliates.

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BCUC-AESO-2 (2) An amount of capacity on the BC-US interconnection (both

directions) should be set aside for reservation by PTP customers other than the Network Customer and its affiliates. The amounts set aside on the BC-US interconnection should be equal to the amounts set aside on the Alberta-BC interconnections.

(3) Near the time of delivery, the Network Customer and its affiliate should be able to reserve and use any of the amounts set aside for PTP customers, which remain unreserved.

The first parameter would restrict the Network Customer and its affiliates from reserving 50% of the capacity available to deliver energy from BC to Alberta. Since the BC to Alberta in capacity is typically about 700 MW, about 350 MW would be set aside for PTP customers other than the Network Customer. An equal amount (350 MW) would be reserved of the capacity available to deliver energy from the US to BC.

The second parameter would restrict the Network Customer and its affiliates from reserving 50% of the capacity available to deliver energy from Alberta to BC. An equal capacity amount would also be set aside for PTP Customers other than the Network Customer, on the capacity available to deliver energy from BC to the US. In the near term only about 200 MW of on-peak capacity and about 700 MW of off-peak capacity is typically expected to be available from Alberta to BC. This would restrict the Network Customer and its affiliates from reserving about 100 MW of on-peak capacity and about 350 MW of off-peak capacity. As the transfer capacity from Alberta to BC increases, a portion of the increased capacity would also be available to the Network Customer and a portion to other PTP customers.

Under the third parameter, the Network Customer and its affiliate would be able to use any capacity unused by other PTP customers near the time of delivery.

The effect of the first two parameters on BC’s total export and import capability are shown as follows:

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BCUC-AESO-2 Capacities in MW

BC Export Capacity

BC Import Capacity

BC Export Capacity

BC Import Capacity

Typical CapacitiesBC to USA 3150 3150BC to AB 700 600USA to BC 2000 2000AB to BC 200 700

Total Capacity before Restrctions 3850 2200 3750 2700

RestrictionsRestriction 1 from BC to AB and From US to BC

BC to AB -350 -300US to BC -350 -300

Restriction 2 from AB to BC and From BC to US

AB to BC -100 -350BC to US -100 -350

Total Restricted Capacity -450 -450 -650 -650% Restricted Capacity 12% 20% 17% 24%

Unrestricted Capacity 3400 1750 3100 2050% Unrestricted Capacity 88% 80% 83% 76%

On Peak Off Peak

Adoption of all parameters would enable parties, other than the Network Customer and its affiliates, access to deliver energy from the US to BC and to Alberta and from Alberta to BC and to the US. The Network Customer and its affiliate would retain the ability to market surplus power on behalf of the Network Customer. The suggested restriction would have no effect on the Network Customer’s ability to reserve and use about 83% to 88% of the available export capacity from BC.

The suggested restriction would affect the ability to reserve capacity but not totally prohibit use of the remaining 12% to 17% of BC’s available export capacity by the Network Customer and its affiliate.

Other requirements needed to achieve the parameters noted above are as follows:

- The restrictions would apply on an hour to hour basis.

- The restriction would apply in aggregate to all types of reservations by the Network Customer or its affiliate (i.e., firm, and non-firm).

- Reservations would not be affected unless the Network Customer or its affiliate exceeded the restriction. In such an event, reservations by the Network Customer would be reduced.

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BCUC-AESO-2 - The restriction would cease to be effective at 50 minutes prior to the

start of a delivery hour for that hour. Any capacity available after such time may be reserved by the Network Customer and its affiliate without restriction for that hour.

The AESO recognizes that other details may be necessary so that the proposed restriction can be implemented. All steps should be supportive of and consistent with the above.

2.4 The restriction would reduce the competitive advantage afforded a Network Customer by improving access to other customers to PTP services. The restriction would not remove entirely the competitive advantage as the Network Customer would still retain receipt and delivery point flexibility and the free option on the unrestricted capacity.

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BCUC-AESO-3

Reference: Ex. C9-5, Evidence of AESO, p. 9

Preamble: On page 9 of the AESO evidence, response A.20 states that FERC has acknowledged that the practices of “Hubbing and Parking” result in undue preference and require a remedy. Footnote 1 cites a NOPR described in the information request as FERC SMD NOPR Appendix C.

Request: What is the date of the cited document and what comments has FERC made and what actions has it taken since then?

Response: The FERC’s Notice of Proposed Rulemaking (“NOPR”) “Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design” (Docket No. RM01-12-000) was issued on July 31, 2002. The NOPR is regularly referred to in the electric industry as the SMD (Standard Market Design) NOPR.

Since the SMD NOPR was issued, the FERC has requested and received comments on it and has held a number of Technical Conferences. Activities in respect of the SMD NOPR were superseded on April 28, 2003 when the FERC’s “White Paper on Bulk Power Market Design” (White Paper) was issued. The White Paper focuses on RTOs while citing deference to regional needs.

To the AESO’s knowledge the undue preference concerns raised by the FERC concerning Hubbing and Parking remain unresolved.

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BCUC-AESO-4

Reference: Ex. C9-5, Evidence of AESO, pp. 10-17, “Free Option”

Preamble: AESO discusses its concern about a “Free Option” that is afforded the Network Customer by its ability to purchase PTP services at no net cost. It recommends on page 17 that given the continuation of a single Network Customer model, the most appropriate tariff-based option would be the introduction of a restriction on the Network’s Customer’s ability to acquire PTP services.

Request: 4.1 Is the “Free Option” concern of AESO a concern in any other jurisdictions in North America? If so, please provide the associated context and discuss what measures, if any, have been implemented to address the concern.

4.2 Please describe in some detail the restriction that AESO would recommend and how it would be implemented and administered.

4.3 Please discuss AESO’s expectation of the impacts such a restriction would have on the Network Customer and its domestic customers.

4.4 Given AESO’s data analysis, what would be the expected absolute and percentage impact of its proposed restriction on the potential for trade and the amount of capacity available for PTP service?

4.5 Would there be any loss of efficiency or utilization of transmission capacity with a restriction on the Network’s Customer’s ability to acquire PTP services? If so, what would be the expected value of this loss. If not, why not?

Response: 4.1 AESO is not aware of another jurisdiction which has addressed and taken measures with regard to the “Free Option”. While the Free Option is caused by the structure of the FERC 888 OATT, the extent of the Free Option in BC arises due to the combined effects of the factors described in A12 of the AESO’s evidence. The AESO is not aware of other jurisdictions where all of these conditions exist.

4.2 Please refer to the AESO’s Response to BCUC-AESO-2.3.

4.3 & 4.4

Since the Network Customer and its affiliate seldomly use 100% of the import and export capacity from BC, the impact of the restriction on the Network Customer and its domestic customers is not expected to be material.

Attachment “BCUC-AESO-1-4.4.xls” presents the AESO’s analysis of the impact of the proposed restrictions had they been in place during the period July 1, 2001 until September 30, 2004. Results of this analysis, as it relates to the Network Customer affiliate, may be summarized as

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BCUC-AESO-4 follows:

- None of the exported energy to the United States would have been affected.

- 10% of the exported energy to Alberta would have been affected.

- 1% of the imported energy from the United States would have been affected.

- 24% of the energy imported from Alberta would have been affected.

The above analysis is conservative given that the Network Customer and its affiliate are assumed to not use intertie capacity which remained unused just prior to the delivery hour. The AESO notes that the third principle of its proposed restriction described in AESO-BCUC-2.3 would allow such use.

4.5 Since the restriction would be removed on an hour to hour basis, no loss of efficiency or utilization of transmission capacity is expected.

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BCUC-AESO-5

Reference: Ex. C9-5, Evidence of AESO, p. 10 Ex. B-7, Revised OATT, p. 68, section 28.6

Preamble: AESO suggests placing a restriction on the use of PTP by Network customers and its affiliates. Section 28.6 of the OATT restricts network customers from using NITS service for sales of capacity and energy to non-designated loads or provision of transmission service by the Network customer to third parties.

Request: 5.1 Would placing the suggested restriction on Network customers prohibit them from using either PTP or NITS service for some transactions? Why or why not?

5.2 Would the Network customer’s affiliate retain the ability to market surplus power on behalf of the Network customer? If so, how?

Response: 5.1 The suggested restriction on the use of PTP service by the Network Customer and its affiliate would not prevent the Network Customer and its affiliate from using PTP service. The suggested restriction on PTP service is described in more detail in response BCUC-AESO-2.3.

The suggested restriction on NITS would prohibit the use of secondary non-firm service as described under clause 28.4 of Part III of BCTC’s proposed OATT Terms and Conditions and as described as Network Economy in A.38 of AESO’s Evidence. The Network Customer would retain use of all other features of Network Service.

5.2 Yes, please refer to the AESO’s Response to BCUC-AESO-2.3.

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Ex. B1-11, BCTC Response to AESO IR 3.12.4

Preamble: In response to AESO IR 3.12.4, BCTC comments that if BC Hydro purchased more transmission than it needs, to the exclusion of other system users, PTP revenues are reduced and NITS costs would be higher.

Request: Does AESO agree with the BCTC response, and if so, is it fair to conclude that the “Free Option” posited by AESO is not always free? If not, why not?

Response: The AESO does not agree. BCTC’s response does not acknowledge the value of the PTP rights acquired by the Network Customer. The PTP rights are valuable to the Network Customer and its affiliate’s power marketing activities.

To understand this value one can consider the average annual trade potential from MID-C to Alberta at Full Hourly Rates.1 The reduced NITS charges to the Network Customer for 1 MW of PTP Service purchased by a third party would be $10,151.2 PTP Service for 1 MW for the entire one-year period would be $55,188.3

The difference, being $45,037, accounts for the 7,149 hours where the trading potential is limited or non-existent and where a third party would be unlikely to purchase PTP Service.

For these 7,149 hours the cost to the Network Customer to purchase PTP rights is zero as these hours are expected to be unused and will fall to the account of the Network Customer. By purchasing annual service, including the 7,149 hours that are likely to be unused by third parties, the Network Customer has acquired the PTP rights.

The value of the hourly PTP rights to a third party is assumed to be, at a minimum, equal to the costs of $10,151 and possibly more as a third party would purchase the service with the expectation of recovering its costs including some profit. By exercising the Free Option, the Network Customer has acquired PTP rights with a value of $10,151 (and possibly more), which offsets the contribution to reducing NITS charges of $10,151 by the third party.

Furthermore, in order to avail of “hubbing and parking” flexibility, the Network Customer must hold two PTP reservations. The first reservation from the US Border POR to the Network Load POD and the second reservation from the GMS.MCA.REV POR to the Alberta Border POD. Both reservations would cost $110,376 ($55,188 x 2) per MW per year and use of the Free Option is actually

1 AESO Evidence Table 1: Trade potential between MID-C and Alberta at Full Hourly Rates was 5,478 hours. The

annual average is 5,478 ÷ 3 years = 1,611.

2 1,611 hours x 1 MW x $6.30/MW-hour = $10,151

3 8,760 hours x 1 MW x $6.30/MW-hour = $55,188

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BCUC-AESO-6 double.

To summarize, by exercising the Free Option, the Network Customer has:

(a) acquired parking and hubbing flexibility by making two reservations

(b) spent $110,376 on PTP service and reduced its NITS by $110,376

$110,376 + ($110,376) = $0.

(c) forgone a $10,151 contribution by the third party to reduce NITS and obtained the PTP rights expected to earn $10,151

$10,151 + ($10,151) = $0.

(d) retained the “optionality” for all other hours by obtaining the LT PTP rights

Depending on the “trading” value of the PTP rights, the Network Customer’s “Free Option” is either almost free or indeed completely free with some upside potential.

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BCUC-AESO-7 Reference: Ex. C9-5, Evidence of AESO, p.16

Preamble: AESO suggests that the effect of the “Free Option” would be mitigated where there are many network customers, such as in Alberta, and notes that customers in Alberta such as Epcor and Enmax would pay a real cost.

Request: Please provide the derivation of the rates indicated for Enmax and Epcor under A.34.

Response: The AESO encloses the attached Excel workbook file “BCUC-AESO-1-7.0 Attachment.xls” in which the chart for A.34 and source data are included as the first two tabs. The source data is an average for the month of January 2004 for “RETAILER” and “LOAD” Participant ID’s from the publicly available “Metered Volumes” Report on the AESO’s website (www.aeso.ca). Please note the chart has been revised slightly by consolidating two ATCO Electric Participant ID’s and noting Direct Energy as Direct (ATCO). Direct Energy assumed ATCO Electric’s load serving responsibilities in April 2004.

For ease of comparison to BCTC’s Network Service Monthly Load Ratio Share calculation, the same data and chart for the January 2004 Coincident Peak have also been included in tabs 3 and 4.

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BCUC-AESO-8 Reference: Ex. C9-5, Evidence of AESO, p pp. 10-12

Ex. B1-7, BCTC October 29, 2004 Submission and Revised OATT; and Ex. B1-11, BCTC Response to AESO IR 3.3.1

Preamble: Section 28.6 of the revised OATT states that the Network Customer shall not use NITS for sales of capacity and energy to non-designated loads or to provide transmission service to third parties. Section 28.6 states that all Network Customers taking NITS shall use PTP service for any third-party sale which requires use of the Transmission Provider’s Transmission System.

BCTC response to AESO IR 3.3.1 states that BCTC enforces Section 28.6 of the WTS by refusing Network Economy transmission requests and associated e-tags that do not specify the Network load as the POD, and by not offering Network transmission on export paths in the short-term market.

Request: In AESO’s view, could its concern about the use of Network Economy be remedied by more stringent or consistent enforcement of the use of Network Economy under section 28.6? If not, why not?

Response: No. Given the structure of the OATT and how the Network Customer’s use of “hubbing and parking”, the “Free Option” and Network Economy may interact, the AESO believes more consistent enforcement or more stringent provisions in respect of Network Economy will not, in isolation, remedy these concerns.

The problem is not the enforcement of rights under the tariff but rather the nature and extent of the rights afforded to the Network Customer by the OATT structure.

The AESO’s main concern with Network Economy4 is the priority associated with the service that discourages the participation by other PTP customers in non-firm transactions and advantages the Network Customer as a “superior” trading partner whose transactions will not be interrupted. More consistent enforcement for Network Economy will not change the reservation priority rights granted to the Network Customer under the OATT.

When considered in conjunction with significant PTP transmission holdings that have been acquired or can be acquired through the “Free Option”, the use of the Network Economy priority provides the Network Customer with almost exclusive access to the US and Alberta Interties, to the exclusion and disadvantage of others.

4 Discussed in A.49 of the AESO’s Evidence.

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BCUC-AESO-9

Reference: Ex. C9-5, Evidence of AESO, pp. 18-23, Network Economy

Preamble:

Request: 9.1 On page 19, AESO indicates that given the “Free Option” and the fact that there is only a single Network Customer in B.C. (BC Hydro), there is no need to establish a unique Network Economy tariff, or to establish a refund mechanism for the purchase of PTP service by the Network Customer. If there was more than one network customer and network economy service was part of the OATT, how would AESO recommend that it be priced, if at all, and under what priority? Why?

9.2 If there was a restriction in place that addressed AESO’s “Free Option” concern, how would AESO’s concern about Network Economy service be impacted, and what would it recommend in regard to availability and pricing?

9.3 On pages 21 and 22 AESO provides estimates of network economy reservations. In AESO’s estimation, what proportion of network economy reservations displaced non-firm transactions that otherwise would have occurred? Please provide an estimate or indication of the lost incremental value of these displaced transactions.

9.4 Please discuss the provisions for network economy service that exist or may have existed in other jurisdictions, and any measures that have been implemented in such jurisdictions to address any concerns similar to the concerns of AESO.

Response: 9.1 Under the assumptions that multiple Network Customers exist in BC and Network Economy service is a part of the OATT, the pricing of Network Economy should remain at no cost. The AESO would propose in such a circumstance that Network Economy service be granted no greater priority than non-firm PTP services. By eliminating a priority advantage, PTP customers would have equivalent access to non-firm transmission as Network Customers.

However, as noted in AESO’s response to Information Request BCUC-AESO-2.1, the AESO is not aware of any initiatives in British Columbia that would create additional Network Customers of significant size to materially change the concerns expressed by the AESO. The OATT should reflect the specific circumstances as they exist in British Columbia. The OATT can evolve, if multiple Network Customers develop, through periodic reviews before the Commission.

Furthermore, even under the alternative assumption that additional Network Customers were to develop in British Columbia, it would still be the AESO’s recommendation that Network Economy is removed from the OATT. New and existing Network Customers would then purchase PTP

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BCUC-AESO-9 services like other customers. If a Network Customer purchased PTP services to meet the needs of their domestic load customers, the AESO would suggest a refund mechanism to reimburse such Network Customers for such PTP purchases, if they incurred a material net cost for such purchases.

As long as one significant Network Customer exists today, the implications of this must be taken into account in the approved OATT.

9.2 The restriction described in the AESO’s Response to Information Request BCUC-AESO-2.3 does not address AESO's concerns about Network Economy service. Network Economy service currently has a higher priority than all non-firm PTP services. Thus even if non-network customers had improved ability to reserve non-firm PTP services, such services may not be available if the Network Customer was able to reserve, on a priority basis, the non-firm capacity available using Network Economy. AESO recommends Network Economy be eliminated from the tariff and that the Network Customer simply use non firm PTP service like other customers.

9.3 The AESO attempted to acquire information necessary to answer this question in Information Request AESO-BCTC-2-10.5. BCTC’s response indicated that such information is not readily available and provided monthly statistics on economic interruptions in response to AESO-BCTC-3-7.1. Beyond an indication of the number of hours of interruption and number of reservations interrupted by Network Economy,5 the AESO is not able to quantify the value of interrupted transactions. In order to answer the Commission’s question the specifics of each interrupted transaction (Date/Time, MW Reserved and Reservation Price) is necessary along with assumptions on market participant behaviour and likely price outcomes.

The AESO has examined the specific case of April 18, 2002 HE 14 from the information provided in Response to AESO-BCTC-3-5 in order to obtain an indication of the changes in value resulting from the Network Economy displacements for this hour.

Network Economy displacements of Enmax (225MW) and TransAlta (100MW) resulted in 325 MW of PTP reservation revenue being forgone. The rates initially paid by Enmax and TransAlta were each $1.3/MW-Hour and this was assumed to be equal to the posted offer price. The foregone PTP revenue is approximately $2/MW-Hour, or a total or $650 when rates for "Regulating Supply & Voltage Control from Generating Sources" and "Scheduling, System Control and Dispatch" are included.

5 BCTC Response to AESO-BCTC-3-7.1.

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BCUC-AESO-9 The trade margin after losses based on the MID-C hourly price and the Alberta Pool Price was about $27/MWh6. The transmission charges based on full rates was about $15/MW-Hour based on full BCTC rates and about $10/MW-Hour based on the prices that would have been paid by Enmax and TransAlta. The value of the interrupted trade was approximately $17/MWh ($27-10/MWh) or $5,525.

In the hour in question BC Hydro exported 420 MW to Alberta. A review of the Alberta pool offer curve indicates that a further 325 MW would have reduced pool price by approximately $20/MWh and rendered trades from Mid-C uneconomic. The AESO has assumed that BC Hydro would react to the increased flows and reduce exports to make up the balance of the 420 MW. This was the worst-case outcome for BC Hydro. It is entirely possible that all three parties would adjust their energy schedules in which case the outcome would change for each and improve for BC Hydro.

The following table outlines the changes in value that could result for the hour if the displaced transactions were to proceed. The change in trade value for BC Hydro has been assumed to be the same as that for Enmax and TransAlta.

Enmax TransAlta BC Hydro No NE Interruption (MWh) 225 100 95 Actual (MWh) 0 0 420 Difference (MWh) 225 100 -325 Trade value change @ $17/MWh7 $3,825 $1,700 ($5,525) Increased PTP Revenue @ $2/MWh $650 Total $3,825 $1,700 ($4,875)

In the hypothetical worst case BC Hydro appears to lose $4,875 in export revenue by not interrupting the Enmax and TransAlta transactions using Network Economy.

As noted previously in Response to BCUC-AESO-6.0, the value of PTP rights to the Network Customer are more valuable than NITS cost-offsetting PTP revenue and in cases such as this one pale in comparison.

9.4 Network Economy exists due to the implementation of a FERC 888 OATT. The extent of the problem arising in B.C. with Network Economy is a result of the OATT structure and the effects caused by the combination of factors described in A12 of the AESO’s Evidence. The AESO is not generally aware of other jurisdictions where all of these conditions exist.

6 AESO Evidence Appendix A - Trading Potential.xls Calculation Tab: Cell Z7009

7 Based on margin after all transmission costs (including BCTC costs)

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Preamble: On page 24, AESO states that it is aware of other jurisdictions where alternatives to the first-come first-served “Internet Racing” have been employed.

Request: Please describe the alternatives AESO is aware of and the jurisdictions that have employed them.

Response: The AESO is aware of the following alternatives to the first come first served “internet race”:

- The PJM reservation protocol which employs an “equal share” distribution method that ensures no one party can reserve all of the available capacity by being first in the “internet race”. Related documents are available from PJM’s website as follows: http://www.pjm.com/documents/downloads/agreements/tariff.pdf http://oasis.pjm.com/rpdoc.html

- -FERC regulated jurisdictions (CAISO, NYISO) where (financial) transmission rights are regularly auctioned.

- Some European jurisdictions that employ explicit intertie capacity auctions (e.g. Netherlands and Ireland) and may employ a holding restriction (Ireland – 40%).

- The Nordic Region (Nordpool), which runs an implicit intertie auction in conjunction with the market trading process.

- The Alberta Intertie Auction Process (Appendix J8) approved by the BCUC Order NO. G-43-98: British Columbia Hydro and Power Authority Wholesale Transmission Services Decision, April 23, 1998.

The AESO notes that auction based processes are unlikely to produce market-based results without mitigation of the “Free Option” concern. Even the coordinated auction contemplated by the Alberta Intertie Auction Process9 with revenue sharing between Alberta and BC would only have diluted the “Free Option” to a “50% Free Option”.

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BCTC-AESO-1

Reference: Evidence of the Alberta Electric System Operator

Preamble: 1.1 Please provide the name(s) and CV(s) of the individual(s) whose evidence has been provided by the AESO in this proceeding.

Request:

Response: 1.1 At the present time the AESO expects the following panel of witnesses to appear and adopt the AESO Evidence:

Doug Simpson, Market Operations Specialist Rob Senko, Director Regulatory Affairs Richard Way, Consultant Dean Short, Consultant

Their CVs are attached.

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Douglas H. Simpson 2500, 330 – 5th Avenue SW

Calgary, AB T2P 0L4 Business: (403) 539-2494 doug.simpson@aeso.ca

ACADEMIC BACKGROUND

Journeyman, Power Systems Electrician, 1985 Electrical Power Diploma, British Columbia Institute of Technology, 1981

PROFESSIONAL EXPERIENCE

AESO Market Operations Specialist 2003 to present Senior Analyst, Operating Policies and Procedures 2002 – 2003 POWER POOL OF ALBERTA, System Controller 1999 – 2002 ALBERTA POWER LIMITED/ATCO ELECTRIC, Supervisor, System Control Centre 1997 – 1999 ALBERTA POWER LIMITED Shift Supervisor, System Control Centre 1991 – 1997 Systems Operations Supervisor, System Control Centre 1988 – 1991 Electrical Technologist, Substation Construction/Maintenance

1981 – 1988

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Robert P. Senko 2500, 330 – 5th Avenue SW

Calgary, AB T2P 0L4 Business: (403) 539-2786

rob.senko@aeso.ca

ACADEMIC BACKGROUND

CMA Designation, Calgary Alberta, 1990 Public Utilities Finance; Cost of Service & Rate Design Courses, 1993-1998 Ivey School of Business Executive MBA Program, 2003

PROFESSIONAL EXPERIENCE

AESO, Director, Regulatory 2004 to present

ALTALINK MANAGEMENT LTD. Director, Regulatory 2002 – 2004 ENMAX CORPORATION, Manager, Business Development 2000 – 2002 TRANSALTA CORPORATION Supervisor, Transmission & Distribution Pricing & Audit 1997 – 1999 Senior Regulatory Analyst 1989 – 1995 Accountant/Analyst 1982 – 1989

NWT POWER CORPORATION, Director, Regulatory 1995 – 1997

AFFILIATIONS

• Miistakis Institute for the Rockies – Director/Treasurer • Society of Management Accountants of Alberta - Member

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Richard (Dick) W. Way Way Consulting Ltd. Profile Mr. Way advises on a range of electricity matters, including market design, regulation, power contracting, transmission, grid operations and strategic planning. Mr. Way has broad experience in industry restructuring in Alberta, Ontario and Northwest USA. He is recognized for his in-depth knowledge of the electric power industry and his experience as a witness in a variety of regulatory forums, including rate applications, Power Purchase Arrangements approvals, sale transactions and contract disputes. Mr. Way was employed at TransAlta Corporation from 1974 to 2004 starting as a generation engineer, then holding several middle management and executive positions including Generation Scheduling, Power Planning, Network Operations, Energy Marketing, and Energy Risk Management. He held instrumental roles as the electric industry restructured over the past 10 years including the separation of functions, the adoption of Power Purchase Arrangements and the divestiture of regulated businesses. He was vice-president, Regulatory Affairs from 1998 to 2004. Mr. Way has a Masters of Business Administration degree and a Bachelor of Science in chemical engineering degree, both from the University of Calgary.

Richard (Dick) W. Way Way Consulting Ltd. 27 Whitefield Place NE Calgary, AB, T1Y 5J9 Phone: (403) 293-3460 Email: Richard.Way@shaw.ca

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Biographical Sketch Richard (Dick) W. Way Way Consulting Ltd. Education:

1974 Bachelor of Science - Chemical Engineering University of Calgary, Alberta

1983 Master of Business Administration (Finance) University of Calgary, Alberta Summary of Experience: Way Consulting Ltd. (2004 to present) Mr. Way has provided consulting services to a number of clients on a range of electricity matters, including market design, regulation, transmission tariffs and strategic planning. TransAlta Corporation (1974-2004) Mr. Way has a wide range of experience holding positions in generation operations, generation planning, system operations and control, transmission planning, power pool operations, wholesale energy marketing, and risk management. Mr. Way was a member of a 1994 committee which led to restructuring Alberta's electric industry under the Electric Utilities Act. Mr. Way was a member of the Power Pool Council from 1995 to 1998 and oversaw the development of the exchange rules, staffing, system development and operating practices of the pool which began operating January 1, 1996 as the new structure took effect. Mr. Way represented TransAlta in a joint venture which filled the Transmission Administrator role from 1996 to 1998, particularly in (1) establishing rates and processes for importers and exporters and (2) ancillary service contracts. Mr. Way participated in the process leading to the Electric Utilities Amendment Act of 1998. He then led the development and finalization of 20 year Power Purchase Arrangements for TransAlta's 4500 MW of previously regulated generation. The PPAs became effective in 2001, replacing ongoing regulation and providing a secure revenue for TransAlta. As TransAlta evolved with a focus on generation, Mr. Way participated in sales of TransAlta's transmission, distribution and retail businesses and lead applications for regulatory approvals of the transactions. Mr. Way lead initiatives in Ontario’s market related to market design, market rule changes and transmission tariffs and codes. Mr. Way has testified before regulatory tribunals on numerous occasions.

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Dean A. Short Background Mr. Short is a Certified Engineering Technologist and 21-year electricity industry professional formerly with ATCO Electric Ltd. including a secondment to the Grid Company of Alberta (GridCo), ESBI Alberta Ltd. (EAL) including a secondment to ESB National Grid (ESBNG) in Dublin, Ireland and Optimum Energy Management Inc. Mr. Short is currently President of Soverus Inc. and has been an independent consultant for the past three years providing consulting services in various areas of electric industry restructuring and deregulation and primarily in transmission authority tariff, regulatory and commercial functions. Relevant Experience • Provided advice on the review of transmission tariffs and implications and compatibility of tariffs

with the LMP Market for the system operator in Ireland. • Provided advice to Alberta Energy on development of the Alberta Government’s Transmission Policy

and Transmission Regulation. • Provided advice on the redesign of the Transmission Connection Agreement including review of

Connection Charging Policy and redesign of the agreement for the system operator in Ireland. • Provided advice to SETrans RTO operator designate ESBI/ESBNG/Accenture on the scope of

settlement and billing of the SETrans Open Access Transmission Tariff. • Led a project team that completed a redesign of the Transmission System Connection Offer Process

for the system operator in Ireland. • Led the development of a detailed User Requirement Specification for a new Transmission Billing

System for the system operator in Ireland. • Provided advice on the establishment of the Customer Service function for the system operator in

Ireland. • Led the analysis project team and provided expert witness testimony before the Alberta Energy and

Utilities Board in July 2001 for the 2000 Deferral Accounts proceeding in respect of analysis of incumbent generation offer behavior.

• Provided advice and support to a group of customers and generators within an “Industrial System” in Alberta on the establishment of a benefits sharing settlement agreement and operations protocols to maximize the benefits of the industrial system.

• Provided expertise and business support to the establishment of an electricity retail services business in Alberta.

• Developed the demand transmission tariff design currently in use in Ireland. • Developed the Transmission Billing System (MS Access database) in use in Ireland from Feb 2000

through July 2003. • Led the development of agreements and protocol for the first Interconnector (Intertie) capacity

auction in Europe on the Interconnector between Ireland and Northern Ireland. • Led the development of the marginal loss factor based methodology for allocation of transmission

losses to physical bilateral energy trades in Ireland. • Led the establishment of the Customer Service function for Alberta’s Transmission Administrator

(EAL). • Personally dealt with over 60 generation developers in respect of 70 potential projects totaling over

4,000 MW while with Alberta’s Transmission Administrator (EAL). • Led the development of an Intertie capacity rights auction process for Alberta’s Transmission

Administrator (GridCo). • Led the development of commercial terms and implementation for an import capacity remedial action

scheme, which increased import capacity, BC to Alberta, by 200 MW for Alberta’s Transmission Administrator (GridCo).

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BCTC-AESO-2

Reference: Evidence of the Alberta Electric System Operator, Q11 and Q12, Page 5

Preamble: The AESO says: “The AESO generally endorses the Order 888 framework. However whenever a generic tariff is adopted to a specific jurisdiction, care must be given to examining the specific facts and circumstances in that jurisdiction which may negatively affect the objectives of open and non-discriminatory access”.

Among the “facts and circumstances” identified by the AESO are:

“(a) There is only one Network Customer in B.C. Other jurisdictions have multiple Network Customers.

(b) The Network Customer in B.C. is also the largest user of PTP service. All other PTP users of the system are much smaller.

(c) The Network Customer is an active participant in neighbouring competitive markets.

(g) The electrical geography places B.C. transmission as the sole conduit between US and Canadian Markets. Such electrical geography is not present in most jurisdictions as they have multiple interconnections.”

Request: 2.1 Please provide a list of the jurisdictions that the AESO has reviewed.

2.2 Please indicate which of the jurisdictions reviewed continues to use an open access FERC Order No. 888 Pro Forma-style tariff.

2.3 Please indicate the number of network customers in each jurisdiction reviewed, and if possible, indicate if load service obligations continue to be met using a FERC Order No. 888 Pro Forma-style network service.

2.4 With respect to those jurisdictions that continue to use network service to meet their load service obligations, has the AESO done any studies to ascertain what proportion of network users also continue to be relatively large purchasers of PTP service for exports? If so, please indicate which jurisdictions are large purchasers of network service, and also have relatively large demands for PTP service.

2.5 For each jurisdiction reviewed by the AESO, please indicate the number of interconnections, the size of the interconnections in MWs of transfer capacity between the control and outside markets, and the size of the peak load (MW) within the control area.

2.6 Please list any “unique facts and circumstances” that the AESO is contemplating here that are not listed in the AESO’s response to Q2 in its evidence.

2.7 Please identify any of the “facts and circumstances” in the AESO’s

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BCTC-AESO-2 response to Q12 of the AESO’s evidence, which are not applicable in the context of the comment in Q22 of the AESO’s evidence.

2.8 For each of the “facts and circumstances” that do not apply to the comments in Q22 of the AESO’s evidence, please describe in detail why these justify BCTC amending its proposed tariff, despite the reasoning provided by BCTC for not doing so (as quoted by the AESO in its response to Q21 of the AESO’s evidence).

Response: 2.1-2.4 & 2.7 & 2.8

Each and all of the items described in A12 of the AESO’s Evidence contribute to the context which exists in BC and it is in that aggregate context that the concerns raised by AESO need to be viewed.

Each item listed in A12 may not be unique to BC however each item forms an important element of the overall context in BC. For example, one of the items noted is that the Network Customer in BC is the largest user of PTP service. The inclusion of the item is not to imply that use of PTP services by a Network Customer is unique to BC. Nor was the inclusion to imply that no Network Customers in other jurisdictions use PTP services. The item was included because that fact is a key element of the context in BC. The context in BC would be very different if the Network Customer and its affiliate were not participants in neighbouring markets and were not users of PTP service. If the Network Customer and its affiliate were not large users of PTP service, then this would have a significant impact on the AESO’s views. The reality in BC is that the Network Customer and its affiliate are large users of PTP services, which leads directly to the AESO’s concerns regarding the level of open access to transmission and also is a consideration, in the AESO’s view, that the Network Customer and its affiliate will be able to adapt to tariff changes and restrictions without significant cost.

Similarly, the fact that BC has a single Network Customer was cited as it is a key feature of the BC context. The inclusion of the item is not to imply that there are no other jurisdictions with such a feature. The item was included solely because it is a key feature of the BC context.

AESO did not conduct a formal review of multiple jurisdictions and does not have detailed data on information requested in 2.3 and 2.4. AESO is generally familiar with jurisdictions in the Pacific Northwest, California, PJM, and New York, as well as Alberta and Ontario.

Many jurisdictions, particularly in the Pacific Northwest, continue to use FERC Order 888 Pro Forma-style tariffs and as noted in the preamble, the AESO generally endorses the FERC 888 tariff. Alberta and Ontario do not use FERC order 888 Pro Forma-style tariffs. PJM, California and New York employ financial transmission rights as well as FERC approved tariffs that are not required to be Order 888 compliant as the transmission

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BCTC-AESO-2 providers are an independent ISO or RTO.

The AESO considers that the BC context must be taken into account in determining the justness and reasonableness of the OATT. The suitability of any generic OATTs must carefully be considered in the context of the specific jurisdiction.

2.5 A diagram from the WECC’s 10 Year Coordinated Plan Summary dated September 2004 follows:

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BCTC-AESO-2

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BCTC-AESO-2

The diagram shows transfer capabilities between state jurisdictions. Washington and Oregon are combined since the Washington Oregon border is a transmission corridor with multiple lines. In some cases, the diagram shows a single intertie even though there may be more than one line providing the capacity. Ten WECC areas in the US are shown. Texas is not within WECC. The Baja Mexico is within WECC, but has been excluded from the analysis as AESO is unfamiliar with the Mexican regulatory structure.

The AESO did not consider individual interties with capacity of less than 300 MW in its analysis since such interties are smaller than many generating units and have smaller impacts on markets. As discussed in its Response to BCH.AESO-05, the Alberta-Saskatchewan intertie is significantly less than 300 MW and the Saskatchewan-US interconnection is also significantly less than 300 MW.

The diagram illustrates:

- Alberta has one major intertie – namely with BC.

- Alberta has one conduit to the US market – via BCTC.

- BC has two major interties with its two neighbouring markets. The two interties are also a part of the conduit between Alberta and the US markets.

- The WECC areas with the fewest interties are Montana, Colorado, New Mexico and Arizona; each have three major interties.

- The remaining six jurisdictions have five or more major interties.

- There is no other instance of a “sole conduit” like the conduit formed by BCTC between Alberta and Mid-C.

All of the WECC areas in the US have at least three times the number of interties as Alberta. The intertie capacities of the US areas are all more than double the rated capacity of the Alberta interconnection.

The AESO does not have control area peak load information readily at hand nor did AESO cite peak load as a significant fact or circumstance.

2.6 The AESO has interpreted the question to refer to Q 12, not Q 2 as written.

Other facts and circumstances which exist in BC and are not common in many jurisdictions include the large size of BC’s hydro resources which provide multi-year energy storage capability.

Multi-year energy storage is not common in many jurisdictions and provides a significant competitive advantage to the Network Customer.

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BCTC-AESO-3

Reference: Evidence of the Alberta Electric System Operator, Q14, Page 6

Preamble: The AESO says: “Little retail competition has developed, even in the large retail sector, and few purchases of transmission service are being made related to competitive retails [sic] sales.”

Request: 3.1 Please confirm the AESO’s understanding that BC Hydro’s existing WTS tariff may not be used by non-BC Hydro generators seeking to sell energy to industrial customers.

3.2 Please confirm the AESO’s understanding that BCTC’s proposed OATT, if approved as filed, will provide the first opportunity for retail access using BC Hydro’s transmission system.

Response: 3.1 Not confirmed. The definition of an “Eligible Customer” described at Section 1.11 of the proposed OATT has not changed when compared to BC Hydro’s Tariff Supplement 30. Specifically, with respect to retail access, the definition outlines: “(ii) Any retail customer taking unbundled transmission service pursuant to a provincial requirement that the Transmission Provider offer the transmission service, or pursuant to a voluntary offer of such service by the Transmission Provider, is an Eligible Customer under the Tariff”.

In the June 25, 1996 BCUC Decision regarding BC Hydro’s Wholesale Transmission Services Application, industrial customer access matters are summarized at page 39. The Commission confirmed at page 40 that “where existing contracts allow customers access to alternate supplies, nothing in the Network Service or Point to Point Service tariffs will be seen as abrogating this right.”

The AESO assumed, in respect of BCTC’s reference to the AESO’s Evidence, that some degree of choice was available to some customers in British Columbia.

Information Requests AESO-BCTC-2-11.4, AESO-BCTC-2-11.3, AESO-BCTC-2-12.1 and AESO-BCTC-3-11.1 were asked to understand the extent to which other purchasers (or sellers) of electricity currently exist in British Columbia, whether they are wholesale, retail, industrial or otherwise.

3.2 Please refer to the AESO’s response to BCTC-AESO-3.1.

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BCTC-AESO-4

Reference: Evidence of the Alberta Electric System Operator, Q19, Q21 and Q22

Preamble: The AESO says: “There is no reason to discriminate in the PTP service provided to Network Customers as compared to PTP-only Customers.”

Request: 4.1 Please describe the extent to which the “discrimination” described by the AESO is a function of the terms and conditions of the proposed OATT tariff, compared with the extent to which it is a function of BC Hydro’s flexible generation assets. In answering this question, please address whether or not any other customer could avail itself of the advantages ascribed to BC Hydro by simply becoming a Network Customer itself.

Response: 4.1 Please refer to AESO’s Response to Information Request BCUC-AESO-2.1.

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BCTC-AESO-5

Reference: Evidence of the Alberta Electric System Operator, Q20 and Q23

Preamble: The AESO says: “The FERC have acknowledged “Receipt and Delivery Point Flexibility” features of the Order 888 Pro forma Tariff and the practices of “hubbing and parking” result in undue preference and require a remedy.”

The AESO also says: “Placing a restriction upon the use of PTP services by the Network Customer and its affiliates would address the concern.”

Request: 5.1 Is the restriction contemplated by the AESO intended to be absolute (i.e., is the AESO contemplating a complete prohibition against BC Hydro and Powerex, for example, using PTP service)?

5.2 If the answer to 5.1 is “no”, please describe in detail the nature of the restriction being contemplated.

5.3 If the answer to 5.1 is “yes”, given the terms and conditions of Part III of the proposed OATT, is the AESO proposing that BC Hydro and its affiliates have no opportunity to directly sell generation to loads not designated as Network Loads?

5.4 If the answer to 5.3 is “yes”, what service would BC Hydro and its affiliates use for export?

5.5 Please describe how any proposal to limit access to PTP service, including the AESO’s proposal outlined in the responses to 5.1 and 5.2 above, is consistent with the intent of the Heritage Contract and the Energy Plan goal of maintaining low rates?

5.6 Is the AESO aware of any jurisdiction with a FERC Order No. 888 Pro Forma-style tariff in place that has restricted the use of PTP services by a Network Customer and its affiliates in order to preclude hubbing and parking?

5.7 Has FERC imposed such a restriction on any utility within its jurisdiction, or issued any order to change the terms of the FERC Order No. 888 Pro Forma tariff to address this concern? If so, provide any relevant references and FERC decisions.

Response: 5.1 No, please see AESO’s Responses to Information Request BCUC-AESO-5.1 and Information Request BCUC-AESO-5.2.

5.2 Please see the AESO’s Response to Information Request BCUC-AESO-2.3.

5.3 Not applicable.

5.4 Not applicable.

5.5 The proposed restriction as described in the AESO’s Response to

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BCTC-AESO-5 Information Request BCUC-AESO-2.3 would permit the Network Customer and its affiliate to continue trading in neighbouring markets and exporting surplus power with little impact. Thus any impact on the rates would be minimal. The proposed restriction would also contribute to the Energy Plan goal of increasing private investment.

5.6 No. While hubbing and parking is caused by the structure of the FERC 888 OATT, the extent of hubbing and parking in B.C. arises due to the combined effects of the factors described in A12 of the AESO’s Evidence. The AESO is not aware of other jurisdictions where all of these conditions exist. The present circumstances are unique. It follows that the AESO is not aware of other jurisdictions that have implemented the specific restrictions it is recommending here.

The AESO is aware of jurisdictions employing structural restrictions to address issues associated with large incumbents. For example, Alberta adopted the development and auction of Power Purchase Arrangements to decrease the concentration of supply in the Alberta market. For similar reasons, generation divestiture has occurred in some US jurisdictions. The BC Energy Plan takes a different approach and one where comparable restructuring activities are not contemplated. As such, similar restructuring activities cannot be relied upon to facilitate open access objectives. The achievement of open-access objectives in BC requires action using tariff mechanisms.

5.7 Please see the AESO’s Response BCUC-AESO-5.6.

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BCTC-AESO-6

Reference: Evidence of the Alberta Electric System Operator, Q26, Q28 and Q36; BCTC’s response to AESO IR 3 12.4

Preamble: At Q26 of its evidence, the AESO makes the following statement in the context of its so-called Free Option: “…the Network Customer has a competitive advantage and is encouraged to over-consume or buy more PTP service than the Network Customer otherwise would. Such over-consumption reduces access to PTP services for other customers.”

In its response to the referenced IR, BCTC explained why it believes that the Free Option incentive may not exist as described by the AESO in that question, and as the AESO subsequently articulated in its evidence.

Request: 6.1 Please confirm the AESO’s understanding that, under the proposed OATT, revenue generated by PTP sales will reduce the share of the transmission revenue requirement payable by Network Customers.

6.2 Please confirm the AESO’s understanding that any decrease in revenue from PTP sales will result in an increase in the portion of the transmission revenue requirement payable by Network Customers.

6.3 Please confirm the AESO’s understanding that, at any given time, there is a finite amount of transmission capacity available on the transmission system.

6.4 Please confirm the AESO’s understanding that, if a Network Customer reserves PTP service, there will be less transmission capacity available for reservation by other PTP customers.

6.5 Please confirm the AESO’s understanding that if a Network Customer reserved sufficient PTP transmission service so as to block access to transmission service by other PTP customers, there would be less contribution from PTP customers to fixed costs or the transmission revenue requirement, and NITS rates would increase.

6.6 Please confirm that behaviour by the Network Customer of the kind described in support of the Free Option argument would result in a real opportunity cost (and in particular, higher NITS rates) if the Network Customer did, in fact, “over consume” transmission in a way that blocked access by other PTP customers willing to make positive contributions to fixed costs.

6.7 If the AESO cannot confirm this, please describe why BCTC’s analysis in this regard is incorrect. In correcting BCTC’s analysis, please make specific reference to BCTC’s analysis as set out in its response to AESO IR 3 12.4.

Response: 6.1 Confirmed. Revenues generated by PTP sales will reduce the revenue requirement payable by the Network Customer.

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BCTC-AESO-6

6.2 Confirmed. Decreases in revenues generated by PTP sales will increase the revenue requirement payable by the Network Customer.

6.3 Confirmed.

6.4 Confirmed.

6.5 Confirmed.

6.6 Not Confirmed. Please refer to the AESO’s Response to Information Request BCUC-AESO-6.0.

6.7 Please refer to the AESO’s Response to Information Request BCUC-AESO-6.0.

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BCTC-AESO-7

Reference: Evidence of the Alberta Electric System Operator, Q29

Preamble:

Request: 7.1 Would the AESO agree that since trading opportunities are market dependent and difficult to forecast, it is likely that long-term transmission contracts would have relatively low usage rates (when viewed retrospectively) as compared with short-term contracts bought nearer to real-time?

7.2 If the answer to 7.1 is “yes”, please provide any evidence that the behaviour shown by BC Hydro and described in the AESO’s evidence is driven by the so-called Free Option, as distinct from being rational optionality purchased by a trader to ensure that it has access to uncertain market opportunities as they arise.

7.3 If the AESO agrees that BC Hydro’s behaviour could be indicative of the latter (i.e., rational optionality purchased by a trader to ensure that it has access to uncertain market opportunities as they arise) what safeguards would the AESO include to ensure that the ability of a trader to employ rational optionality is preserved?

Response: 7.1 The AESO would agree that historical market data for Alberta and Mid-Columbia suggests that the potential for trade between the two markets is not continuous and is directional in nature. The AESO understands that certain market factors may be predictable. For example “Fish Flush” and corresponding low Mid C prices occur every year. Certain other short-notice market factors like generation forced outages are obviously not predictable.

7.2 In assessing whether to purchase long-term transmission contracts, the AESO would expect a trader to consider the costs associated with the contract versus the value of the “optionality” obtained with the contract. The AESO would also expect that where the cost to obtain the contract is not expected to meet the trader’s expectation of benefit arising from the “optionality” obtained, the trader would consider shorter-term lower cost alternatives to long-term transmission contracts. The AESO would also expect that where the cost to obtain any amount of “optionality” was “free”, any rational trader would acquire the “optionality”.

The AESO acknowledges that it would likely be difficult to distinguish the behaviour of the Network Customer being driven by the “Free Option” from the actions of a trader purchasing optionality to ensure that it has access to uncertain market opportunities.

However, evidence that would suggest the Network Customer’s behaviour is driven more by the Free Option includes:

(a) Purchasing and or holding long-term contracts where the interest

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BCTC-AESO-7 by 3rd parties is limited or non-existent.

(b) A substantially higher cost for PTP services versus energy flowed than by 3rd parties.

With respect to (a) above, the Network Customer has substantial LTF PTP holdings1 for export on both the Alberta and U.S. Interties. However, BCTC has acknowledged the lack of parties willing to pay for an expansion of export capacity suggesting that there are no viable new long-term firm export opportunities.2

With respect to (b) above, the AESO has determined that the average cost of PTP services per MWh transmitted is 5 times higher ($24.13/MWh) for the Network Customer (including affiliates) than 3rd parties ($4.69/MWh). Given that 3rd parties would seek similar opportunities to trade in and between the Alberta and Mid-C markets, the Network Customer’s significant expenditures would suggest behaviour that is driven more by the “Free Option” than a basic desire to acquire “optionality”.

The AESO’s analysis in determining the values noted above is attached as BCTC-AESO-1-7.2 Attachment.xls. The AESO has excluded West Kootenay Power from the 3rd parties calculations as no LTF PTP revenues were noted for West Kootenay Power in the Response to BCUC-BCTC-1-14.3 despite two 370 MW LTF PTP Contracts noted in the Response to AESO-BCTC-3-8.3. The AESO notes the same contracts were omitted from the Response to AESO-BCTC-2-11.2.

7.3 The proposed restrictions on PTP service for the Network Customer would continue to permit the Network Customer to access LT PTP services and retain “optionality”.

Please refer to BCUC-AESO-2.0 and BCUC-AESO-5.0.

1 Response to AESO-BCTC-2-11.1.

2 BCUC Order G-103-04 (November 19, 2004) Reasons For Decision: British Columbia Transmission Corporation - Transmission System Capital Plan, at Page 37: “The Commission Panel also accepts BCTC’s statement that the lack of parties willing to pay for an expansion of export capacity suggests that there are no viable new long-term firm export opportunities available at this time.”

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BCTC-AESO-8

Preamble:

Request: 8.1 Please provide a response to Q41 assuming more than one Network Customer.

8.2 Please confirm the AESO’s understanding that BCTC’s proposed OATT provides for the existence of more than one Network Customer.

8.3 Does the AESO consider it appropriate to base the provisions of BCTC’s tariff on the assumption of a single Network Customer when more than one Network Customer is possible?

Response: 8.1 The current and proposed OATT does not contain sufficient terms and conditions to allow the AESO to contemplate how the OATT might function with more than one Network Customer.3 Generally, the AESO would not expect the costs for the whole of the Network Customer group to be different. In aggregate, the PTP service revenue would lower NITS costs in the same way for a group of Network Customers as it would for one Network Customer. If the use of Network Economy by each Network Customer was in proportion to load ratio shares, then no cost shifting would be expected.

8.2 Confirmed.

8.3 Please refer to the AESO’s Response to Information Request BCUC-AESO-2.1.

3 For example: No protocol exists in the terms and conditions to suggest how Network Economy may be rationed

between several customers.

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BCTC-AESO-9

Reference: Evidence of the Alberta Electric System Operator, Q23, Q36 and Q41

Preamble:

Request: 9.1 Given that the AESO has in Q23 and Q36 suggested placing a restriction upon the use of PTP services by the Network Customer and its affiliates, please expand upon the apparent suggestion in Q41 that the network economy provisions could be replaced by the Network Customer’s use of PTP.

Response: 9.1 Please refer to the AESO’s Response to Information Request BCUC-AESO-2.1 for information on the proposed restriction. The restriction does not prohibit reservation and use of PTP services by the Network Customer and in fact the Network Customer has significant unrestricted PTP services available to it. The Network Customer is also permitted to utilize any of the restricted capacity remaining available near real time. Please also refer to the AESO’s Response to Information Request BCUC-AESO-4.4.

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BCTC-AESO-10

Preamble: The AESO states that it is not apparent to the AESO that there would be any significant incremental cost to the Network Customer if its network economy priority was eliminated, given the generation resources available to the Network Customer.

Request: 10.1 What does the AESO consider to be a “significant incremental cost”?

10.2 What criteria should the Commission use in justifying the imposition of an incremental cost on the Network Customer?

10.3 To the extent that the AESO’s conclusion is driven by the nature of generation resources available to the current Network Customer, is the AESO of the view that other potential Network Customers with less flexible generation resources should be denied the use of network economy service? If so, please explain.

Response: 10.1 There is no specific amount that the AESO considers to define “significant incremental cost”. The term is a relative one and in this context has been used in relation to the provision of open and non-discriminatory access to the transmission system. The significance of the incremental costs to achieve this objective requires consideration of the benefits derived from open access including benefits of increased utilization of the transmission network, more private investment in BC and the benefits that the Network Customer and its affiliate receive through open access to neighbouring markets.

The significance of incremental costs should also be viewed in the context of other costs BC has committed to incur to achieve the open access objective. Achievement of open access has required evolutionary changes to transmission organizations and business practices and caused certain expenditures. The formation of an independent transmission entity and development of an OASIS transmission reservation system are examples.

Some loss of flexibility and associated incremental cost is necessary in the BC situation as part of achieving the open access objective. However, when taking these factors into account it is not apparent to the AESO that such costs are significant.

10.2 As noted in 10.1 above, achieving the objective of an open access tariff may require some incremental costs. The achievement of the objectives of the tariff is justification for such costs. The Commission should not consider the loss of an unfair preference received by a particular customer under an existing tariff as justification for rejecting changes intended to make a tariff more equitable.

10.3 The AESO's conclusion was not driven by one factor in isolation. The

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BCTC-AESO-10 AESO's conclusion was reached in light of the combined effects of several factors as outlined in the AESO Evidence. The fact that the Network Customer has flexible generation resources, including significant energy storage capacity, means that costs associated with some loss of flexibility of use of the transmission system will be low. That, however, is only one of the factors to take into consideration.

The AESO’s view has focused on the BC situation as it is and as it is expected to be for some time. The BC situation is characterized by the existence of a single Network Customer. AESO is not aware of other potential Network Customers in BC in the near future. Please refer to BCUC-AESO-1-2.1.

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BCH-AESO-1

Reference: AESO Evidence, Introduction

Preamble: The AESO does not provide information as to who is responsible for developing its testimony.

Request: 1.1 Please provide the name(s) and position(s) of the person(s) at the AESO responsible for developing the AESO’s evidence and for the analysis contained therein.

1.2 Please identify the witness(es) that will defend the AESO’s evidence.

1.3 Please identify any party or parties external to the AESO (whether consultant or market participant) that:

(a) conducted any of the analysis used in the testimony;

(b) provided input into developing the testimony and/or reviewed the testimony; and

(c) assisted the AESO in any other way regarding its testimony.

Response: 1.1 – 1.2

Please refer to the AESO’s Response to Information Request BCTC-AESO-1.

1.3 The AESO consults regularly with members of the Alberta electric industry. Through such consultations the AESO has been informed of matters and issues which contributed to the AESO’s participation in this proceeding. The analysis contained in the AESO’s Evidence was prepared by or under the direction of the AESO’s testifying witnesses.

CALGARY:610049.1

BCH-AESO-2

Reference: AESO Evidence, Introduction

Preamble:

Request: Please confirm that the AESO’s mandate and statutory duties regarding “a fair, efficient and openly competitive market for electricity” are with respect to the electricity market in Alberta. If the statement cannot be confirmed, please provide an explanation including references to any enactment from which the AESO draws an extra-provincial mandate or duty.

Response: Confirmed. However, the AESO’s mandate also concerns matters which relate to transmission system interconnections with jurisdictions outside of Alberta given that such interconnection have both direct and indirect effects on the fair, efficient and openly competitive market for electricity in Alberta. These roles and responsibilities are set out both in the Electric Utilities Act, S.A. 2003, c.E-5.1 and in the Transmission Regulation A.R. 174/2004, in particular, section 8(1)(g) and section 15.

CALGARY:610049.1

BCH-AESO-3

Reference: AESO Evidence, Introduction, A.6, p.3 & A.49, p.22-23

Preamble:

Request: 3.1 Has the AESO, or its predecessors, ever attempted to reserve capacity over the BC-Alberta intertie (on its own behalf or on behalf of another party)? Has the AESO ever sought PTP service under BC Hydro’s WTS tariff (again, on its own behalf or on behalf of another party)? If not, why not?

3.2 Is the only reason why Alberta load serving entities have chosen not to reserve and/or purchase Long Term Firm capacity into Alberta on the BC transmission system because firm capacity is generally more expensive than non-firm capacity?

Response: 3.1 No, the AESO provides transmission system access within Alberta and facilitates operates Alberta's hourly wholesale electricity market. The AESO does not compete with participants in energy markets. The AESO has not considered it part of its mandate to acquire transmission capacity entitlements on systems outside of Alberta. Those have been considered as market participant activities. However, access issues to those facilities affect the functioning of the Alberta market and are, therefore, issues which touch and concern the AESO’s mandate.

3.2 The AESO has not been provided specific reasons for the decisions taken by its market participants. Please refer to A.49 of the AESO’s evidence for a discussion of why the AESO expects some customers choose non-firm transmission service rather than firm transmission service.

CALGARY:610049.1

BCH-AESO-4

Reference: AESO Evidence, A.4 & A.5, p.3

Preamble: The AESO states that the BC tie has a capacity of approximately 1000 MW and plays a key role in Alberta’s wholesale electricity market.

Request: 4.1 Please provide all operating procedures, transmission studies or other information that establishes 1000 MW of actual operating transfer capability (OTC), not just the nominal WECC path rating, is available on the BC-Alberta Intertie for market participants to use for both imports to and exports from Alberta.

4.2 Please provide a table that summarizes for each month of the past 4 years:

(a) the average Heavy Load Hour (HLH) OTC ratings;

(b) the average Light Load Hour (LLH) OTC ratings; and

(c) the minimum and maximum OTC rating for the HLH and LLH periods within the month,

for the Alberta-BC Intertie for both imports and exports as posted by the AESO or its predecessors on its website.

4.3 Under normal operating conditions during HLH can the AESO transmission system reliably deliver 1000 MW to the BC/Alberta border? If not, what amount of capacity can be provided on a reliable basis?

4.4 How many times over the past 4 years has the BC Intertie been rated at 1000 MW of ATC? Please provide details of the occurrences.

4.5 How many times over the past 2 years was the AESO’s OTC rating for the Alberta-BC Intertie lower than BCTC’s? How many times over the past 24 months was BCTC’s OTC rating for the Alberta-BC Intertie lower than the AESO’s? Please provide the number of occurrences that were in HLH periods and, separately, in LLH periods.

Response: 4.1 The AESO’s intention in A4 and A5 was not to state the actual operating transfer capability of BC-Alberta Intertie. The capability of the intertie is dependant upon the operating conditions on the BC and Alberta electrical systems. The 1000 MW referred to in A4 and A5 is indicative of the path size. ISO Rules, Operating Policies and Procedures 304 Alberta–BC Interconnection Transfer Limits (OPP 304) defines the transfer limits on 1201L/5L94 line according to the various operating conditions that may exist in Alberta.

The AESO notes that historically, the Alberta-BC intertie has been constrained below the 1000 MW level. New Regulations have been introduced in Alberta and now require expansions or enhancements so that under normal operating conditions interconnection facilities with neighbouring jurisdictions can operate on a continuous basis at or near the

CALGARY:610049.1

BCH-AESO-4 path rating.

4.2 The requested information is shown in the Table below and the AESO has also provided in spreadsheet format as “BCH-AESO-1-4.2 Attachment.xls”. This information was based upon import and export ATC data posted on the AESO’s website.

CALGARY:610049.1

BCH-AESO-4

Alberta to BC

2001 Average Max Min Average Max MinJanuary 195 520 0 458 590 50February 150 450 0 450 590 50

March 244 520 50 515 590 220April 285 520 130 526 600 300May 296 590 50 541 600 50June 295 600 50 555 650 300July 205 550 0 510 650 50

August 198 550 0 526 650 300September 218 550 50 520 650 100

October 201 500 0 515 600 150November 94 450 0 416 550 0December 56 300 0 314 500 0

HLH LLH

EXPORT ATC ANALYSIS (MW)

HLH LLH

CALGARY:610049.1

BCH-AESO-4

IMPORT ATC ANALYSIS (MW)BC to Alberta

HLH LLH2001 Average Max Min Average Max Min

January 781 800 700 646 800 600February 791 800 700 646 800 600

CALGARY:610049.1

BCH-AESO-4

4.3 No. Currently, the Alberta transmission system cannot reliably deliver 1000 MW to the BC/Alberta border. The amount of capacity that can be provided to BC/Alberta border on a reliable basis varies according to specific operating conditions and load levels as set out in OPP 304. This amount ranges from a low of zero MW when the Alberta Interconnected Electric System (AIES) Load is greater than 8099 MW to a high of 700 MW when the AIES load is below 6300 MW. Please also refer to the AESO’s Response to BCH-AESO-4.1.

4.4 The BC intertie ATC has not been posted at 1000 MW in the past four years. The highest levels have been 800 MW BC to Alberta and 650 MW Alberta to BC.

4.5 The Table below provides the requested information.

HLH LLH Total

AESO's ATC posting for the Alberta to BC Intertie Lower than

BCTC 249 215 464BCTC's ATC posting for the Alberta to BC Intertie Lower than

AESO's 3452 3694 7146AESO's ATC posting for the BC to Alberta Intertie Lower than

BCTC 321 232 553BCTC's ATC posting for the BC to Alberta Intertie Lower than

AESO's 2689 1286 3975

Comparison of ATC Values (Hours)

1. OTC data is not available.

2. This information is based upon ATC data posted on the AESO website and data provided to the AESO by BCTC in Response to AESO-BCTC-1-17.1f. The BCTC data is taken from file “IR_AESO_IR-1_No17-1f_ENdivTTC.csv” and is found in the columns entitled: AB_BC_ADJ_TTC_MW and BC_AB_ADJ_TTC_MW. According to the description found in the BCTC Response to AESO-BCTC-1-17.1f, the data in the columns are Total Transfer Capability minus Transmission Reliability Margin.

3. Alberta ATC has been calculated as follows: TTC – TRM =ATC

4. BCTC data provided is current up to September 30, 2004. For that reason, the comparison is for the period October 2002 to September 2004.

CALGARY:610049.1

BCH-AESO-5

Reference: AESO Evidence, A.5, p.3 & A.12(g), p.5

Preamble:

Request: Please confirm that Alberta parties can access US markets via the Alberta-Saskatchewan and Saskatchewan-MAPP Interties?

Response: Confirmed. The Alberta-Saskatchewan intertie is rated at 150 MW in each direction and is relatively small in comparison to the Alberta-BC intertie. Access via this path to a U.S. market comparable to Mid-Columbia is much more distant.

- 10 -

CALGARY:610049.1

BCH-AESO-6

Reference: AESO Evidence, A.7, p.3

Preamble:

Request: What evidence does the AESO have that BC Hydro is a market participant in the Mid-C or Alberta markets?

Response: In drafting its Evidence the AESO was generally aware that BC Hydro and Powerex are affiliates, more specifically that Powerex is a wholly owned subsidiary of BC Hydro. Powerex, in its comments to FERC as included in AESO-BCTC-04 Attachment A, states “Powerex also markets hydropower energy acquired from its parent …” and as reported in BC Hydro’s 2004 Annual Report on pages 69 to 71, the 2 entities have a Transfer Pricing Agreement.

Information Responses BCTC BCUC 1 14 and 23 provide information on the significant transmission purchases by BC Hydro to access the Alberta and Mid-C markets. It is common knowledge that Powerex is very active in both markets. The BC Energy Plan, included in the BCTC OATT Application (Appendix F), also references revenues BC Hydro earns by importing and exporting electricity (page 14), and the ongoing opportunities for trade (page 22).

- 11 -

CALGARY:610049.1

BCH-AESO-7

Reference: AESO Evidence, A.12(a), p.5 & A.35, p.17

Preamble: The AESO states that other jurisdictions have multiple Network Customers and that BPA has approximately 100 Network Customers.

Request: 7.1 What is the number and relative size (in terms of load ratio share) of Network Integration Transmission Service customers in each of the following Pacific Northwest control areas: Idaho Power Corp., Pacificorp, Avista Corp., Puget Sound Energy, NorthWestern Energy (Montana), Sierra Pacific Power, Nevada Power, and Portland General Electric?

7.2 Please clarify if the reference to “approximately 100 Network Customers” for BPA refers to customers with a Network Integration Transmission Service (NITS) contract under Part III of BPA’s OATT or whether it refers to customers taking service - whether NITS, PTP, FPT, IR, NCD, etc - on what BPA refers to as the “Integrated Network Segment” of its transmission grid.

Response: 7.1 Please refer to the AESO’s Response to BCTC-AESO-2.3.

7.2 The count of Network Customers was obtained from BPA’s OASIS node for BPA Transmission customers’ records meeting the following OASIS data field requirement:

SERVICE_INCREMENT TS_CLASS TS_TYPE YEARLY FIRM NETWORK

- 12 -

CALGARY:610049.1

BCH-AESO-8

Reference: AESO Evidence, A.17, A.18, pp.7-8, & Appendix B

Preamble: The AESO defines “Parking” as where the Network Customer reserves PTP service using the Network Load POD to purchase energy which it intends to sell but where no buyer at the time of reservation has been identified.

Request: 8.1 Did the AESO take into account the reservation and schedule for the Kanelk Load in its analysis? If not, how would the analysis change if this reservation and schedule were removed?

8.2 What evidence does the AESO have that BC Hydro intended to sell the energy it imported at the time it made the decision to import?

8.3 Please provide Appendix B to the AESO’s evidence in Excel (.xls) format.

Response: 8.1 Yes, Kanelk flows were accounted for in the analysis. Please refer to cell AI6 where the formula accounts for the date that the Kanelk system was moved into the BC control area (February 26, 20031). The formula excludes from the “Hub and Park” count all hours where the flow was 40MW or less until February 27, 2003 12:00:00 AM (excel date value 37679).

8.2 In the AESO’s Evidence at A.18, the analysis and conclusions merely state and summarize the data in respect of what physically occurred. No suggestion was made as to the intention of BC Hydro with respect to purchases and sales, only that a simultaneous import and export would be a strong indication of “hubbing and parking”.

8.3 Appendix B - BCTC Transmission and Energy.xls was sent as a zip file attachment to the AESO’s Evidence the registered intervenor’s list on Friday, December 17, 2004 at 4:15 PM MST.

The list included alice.ferreira@bchydro.com, however the AESO will resend the file to alice.ferreira@bchydro.com.

- 13 -

CALGARY:610049.1

BCH-AESO-9

Reference: AESO Evidence, A.17 pp.7-8

Preamble: The AESO defines “hubbing” as involving purchasing energy from multiple sellers and selling to multiple buyers.

Request: 9.1 Please confirm that any market participant can submit multiple e-tags, with various supply sources, when importing energy into the Alberta Power Pool?

9.2 Please confirm that any market participant can submit multiple e-tags, with various energy sinks, for export schedules from the Alberta Power Pool?

Response: 9.1 Confirmed. Alberta does not utilize a path-based system of Point-to-Point rights. All parties, including BC Hydro’s marketing subsidiary Powerex, may submit multiple e-tags from various supply sources when importing to Alberta and may submit multiple e-tags to various load sinks when exporting from Alberta.

9.2 Please refer to the AESO’s Response to BCH-AESO-9.1

- 14 -

CALGARY:610049.1

BCH-AESO-10

Reference: AESO Evidence Generally

Preamble:

Request: Please provide a copy of the Alberta Market Surveillance Administrator’s January 10, 2005 report entitled “A Review of Imports, Exports, and Economic Use of the BC Interconnection.”

Response: Alberta’s Market Surveillance Administrator (MSA) is an organization which is separate and independent from the AESO. The referenced report is available at the MSA’s website www.albertamsa.ca.

The report summarizes the MSA’s consideration of energy import and export activities on the BC interconnection. The matters which the AESO has presented in its evidence, namely, the Free Option, hubbing and parking, and Network Economy are matters which concern the underlying transmission rights which allow import and exports to occur into and out of the Alberta market. These were not the subject-matter of this Report.

- 15 -

CALGARY:610049.1

BCH-AESO-11

Reference: AESO Evidence Generally

Preamble:

Request: 11.1 Does the AESO reserve transmission for market participants to wheel through from BC to Saskatchewan or vice versa?

11.2 What would the transmission cost be under the current AESO tariff, including losses, IS and ES, to wheel from BC to Saskatchewan when the pool price is $100?

Response: 11.1 No. The AESO does not reserve transmission on behalf of market participants. The AESO Tariff does allow market participants to wheel from Saskatchewan to British Columbia and vice versa.

11.2 The total transmission cost, based on the AESO 2005 Interim Tariff Schedules IS and ES and would be $21.04/MWh during On Peak hours and $34.14/MWh during Off Peak hours based on the applicable transmission loss factors noted below.

BCH Import Sask* Export On peak -1.3% 17.1% Off peak -6.7% 35.6%

* Includes losses at the converter station

- 16 -

CALGARY:610049.1

BCH-AESO-12 Reference: AESO Evidence, A.31, p.15

Preamble: The AESO refers to a Table 4 at line 338 of the evidence but Table 4 is not included in the evidence.

Request: 12.1 Please provide the referenced Table 4.

12.2 Please provide the details of the AESO’s review of OASIS data that is referred to at line 341 of the evidence.

Response: 12.1 The reference to Table 4 in the second paragraph should read Table 3.

12.2 Spreadsheet BCTC-AESO-1-12.2 Attachment.xls has been attached. AESO notes slight variations in the results versus values noted by BCTC in response to AESO-BCTC-3-1.1b. The AESO cannot verify the differences without comparing the underlying OASIS data used by BCTC to that used by the AESO. Original OASIS data used by the AESO has been provided in the excel spreadsheet.

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