British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005

Transcription

1 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, Reference: Application, pp. 1 9 and 1-22 British Columbia Hydro and Power Authority Transmission Service Rate Application Page Section 4.2 on page 1-22 provides "Design Principles" in relation to BC Hydro's proposal for the Time of Use Rate. Are there corresponding design principles for the Stepped Rate proposal in addition to those set out in recommendations #8 to #15 as set out in Heritage Special Direction No.2? If so, what are they? RESPONSE: In addition to the BCUC recommendations that the Stepped Rate be a mandatory tariff and that it should be revenue (bill) neutral at historical consumption levels, BC Hydro believes the Stepped Rate proposal generally satisfies Bonbright s rate design principles, including fairness, efficiency, and simplicity. Due to the potential administrative complexity and cost shifting between customers in the establishment of CBLs, particular emphasis was placed on simplicity of administration and ease of understanding. B-3

2 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 2.0 Reference: Application, p. 1-2 BCUC Recommendation #8, and p. 1-11, Section 3.5 Page 1 BC Hydro proposes to use an "Annual CBL Model", primarily to ensure annual revenue neutrality for each customer. This approach is intended to accommodate cases in which the customer's monthly load pattern varies from historical monthly load pattern, but overall annual consumption is unchanged. The example provided in Figure 1 illustrates that the cost of monthly consumption that exceeds the CBL by more than 10% would not equal the savings associated with a symmetrical reduction in monthly consumption relative to the CBL Please file the presentation materials from the November 25, 2004 workshop on Stepped and Time of Use Rates. RESPONSE: Please see attached.

3 BC Hydro Stepped Rates & Time Of Use Proposal Summary November 25, 2004 Sutton Place, Vancouver for discussion only 1

4 Agenda 8:30-9:00 Registration & Coffee 9:00-9:05 Introduction & Welcome 9:05-10:15 Stepped Rate Proposal Scope Stepped Rate Design Retail Access 10:15-10:30 Break 10:30-11:45 Stepped Rate Proposal (cont( cont) Time Of Use Rate Design Standby & Maintenance Rates Exempt Rate Customers Implementation 11:45-12:00 Summary And Q&A 12:00-1:00 Buffet Lunch for discussion only 2

5 Welcome Bev Van Ruyven BC Hydro for discussion only 3

6 Scope Of BC Hydro Stepped Rate Proposal The filing in January 2005 will include: Stepped Rate Time-Of-Use Rate Option Standby & Maintenance Rates Retail Access for discussion only 4

7 Background On Filing Stepped rates, time-of-use (TOU) rates and retail access originated from the government s Energy Plan in late Standby rate (RS1880) for RS1821 customers will be revised to be consistent with pricing under Energy Plan Special direction - existing RS1821 customers will be put on stepped rate or TOU rate (except for UBC, Aquila, New Westminster) for discussion only 5

8 Background On Filing In preparation for the Stepped Rate filing proposal, BC Hydro has engaged customers by: conducting Stepped Rate workshops in Vancouver and Prince George. face-to-face presentations at all RS 1821 customers. meetings with the JIESC. The proposed design and filing is the result of this dialogue and the many suggestions made by customers. for discussion only 6

9 Stepped Rate Proposal Richard Stout BC Hydro for discussion only 7

10 Objective Of Session Provide information on BC Hydro proposal basis of draft proposal to be submitted to BCUC for approval Customers will have opportunity in the stepped rate hearing to provide their input for discussion only 8

11 Stepped Rate Design Richard Stout BC Hydro for discussion only 9

12 Revenue Neutrality If you don t do anything different your bill will stay the same... for discussion only 10

13 Stepped Rate Implications If you conserve, it will save you more than before. for discussion only 11

14 Stepped Rate Implications If you consume more, it will cost you more than before... for discussion only 12

15 Summary That took 2 years. The next 2 hours will cover some details... for discussion only 13

16 Stepped Rate BCUC Recommendations for discussion only 14

17 BCUC Recommendations BCUC recommendations #8-15, required by Heritage Special Direction No. HC2 Mandatory (with TOU option) Revenue (bill) neutral i.e. same customer bill for same consumption pattern Margin neutral i.e. changes in consumption produce changes in revenue that balance changes in costs Costs not to be transferred to other rate classes for discussion only 15

18 BCUC Recommendations (contd( contd.) Tier 2 to reflect long-run opportunity cost of new supply starting at 90% of base load Tier 1 based on residual to maintain revenue (bill) neutrality Base load based on historical consumption adjusted for anomalies (conceptually a forecast of consumption absent stepped rate) Pro-rata adjustments of all base loads to avoid inter-class transfers for discussion only 16

19 BCUC Recommendations (contd( contd.) Annual review/adjustments of base loads BCUC to resolve disputes Maintain customer flexibility to manage affairs Limit administrative burden on customers, utility and regulator for discussion only 17

20 BC Hydro Stepped Rate Proposal for discussion only 18

21 Stepped Rate - Basic Design Energy Rate $/MWh Tier 2 Price, P 2 = $54/MWh Load greater than 100% of CBL is charged $54/MWh Tier 1 Price, P 1 = $25/MWh 90% of CBL Load Note: Prices are for Illustration 100% of CBL Load Energy Consumption as % of CBL for discussion only 19

22 Stepped Rate & Bill Neutrality Energy Rate $/MWh P 2 = $54/MWh 1821 price = $28/MWh P 1 = $25/MWh Area A Difference between 1821 price and Tier 1 price x 90% CBL Bill neutrality A=B Area B Difference between 1821 price and Tier 2 price x 10% CBL 1821 bill =100% Reference Load x $28 90% 100% Energy Consumption as % of CBL Note: Prices are for Illustration for discussion only 20

23 BC Hydro Proposal Annual Stepped Rate Energy Rate $/MWh P 2 =$54/MWh P 1 =$25/MWh Energy is billed at Tier 1 price as long as cumulative energy consumption for the year is less than 90% of the annual CBL. Energy is billed at the Tier 2 price when cumulative energy consumption for the year is greater than 90% of the annual CBL. Note: : Prices are for Illustration Jan Month Jun for discussion only 21 90% 100% Dec The date for Tier 2 pricing is customer specific and depends when the cumulative load exceeds 90% of the annual CBL. Energy Consumption as % of Annual CBL

24 Annual Stepped Rate Bill Example Case 1: No Consumption Change Month Annual CBLAnnual CBLActual Cumulative Cumulative/ Load Load Annual Step 1821 GWh at 1821 GWh GWh Actual GWh under T1 under T2 Rate Energy Energy ($M) % Price Price Bill ($M) Bill ($M) Jan % $2.50 $2.79 Feb % $2.50 $2.79 Mar % $2.50 $2.79 Apr % $2.50 $2.79 May % $2.50 $2.79 Jun % $2.50 $2.79 Jul % $2.50 $2.79 Aug % $2.50 $2.79 Sep % $2.50 $2.79 Oct % $2.50 $2.79 Nov % $3.08 $2.79 Dec % $5.40 $2.79 Total 1200 $ $33.44 $33.44 Energy charges used: Tier 1 Price $25/MWh Tier 2 Price $54/MWh 1821 Energy $28/MWh Charge Load Priced at Tier 1 = 90% of annual CBL = 1080 GWh Note: The bill analysis examples include energy charges only. for discussion only 22 Load Priced at Tier 2 = 10% of annual CBL = 120 GWh

25 Annual Stepped Rate Bill Example Case 2: 10% Conservation Month Annual CBLAnnual CBLActual Cumulative Cumulative/ Load Load Annual Step 1821 GWh at 1821 GWh GWh Actual GWh under T1 under T2 Rate Energy Energy ($M) % Price Price Bill ($M) Bill ($M) Jan % 90 0 $2.25 $2.51 Feb % 90 0 $2.25 $2.51 Mar % 90 0 $2.25 $2.51 Apr % 90 0 $2.25 $2.51 May % 90 0 $2.25 $2.51 Jun % 90 0 $2.25 $2.51 Jul % 90 0 $2.25 $2.51 Aug % 90 0 $2.25 $2.51 Sep % 90 0 $2.25 $2.51 Oct % 90 0 $2.25 $2.51 Nov % 90 0 $2.25 $2.51 Dec % 90 0 $2.25 $2.51 Total 1200 $ $26.96 $30.10 Energy charges used: Tier 1 Price $25/MWh Tier 2 Price $54/MWh 1821 Energy $28/MWh Charge Load Priced at Tier 1 = 90% of annual CBL = 1080 GWh for discussion only 23

26 Annual Stepped Rate Bill Example Case 3: 10% Growth Month Annual CBLAnnual CBLActual CumulativeCumulative/ Load Load Annual Step 1821 GWh at 1821 GWh GWh Actual GWh under T1 under T2 Rate Energy Energy ($M) % Price Price Bill ($M) Bill ($M) Jan % $2.75 $3.07 Feb % $2.75 $3.07 Mar % $2.75 $3.07 Apr % $2.75 $3.07 May % $2.75 $3.07 Jun % $2.75 $3.07 Jul % $2.75 $3.07 Aug % $2.75 $3.07 Sep % $2.75 $3.07 Oct % $3.33 $3.07 Nov % $5.94 $3.07 Dec % $5.94 $3.07 Total 1200 $ $39.92 $36.79 Energy charges used: Tier 1 Price $25/MWh Tier 2 Price $54/MWh 1821 Energy $28/MWh Charge Load Priced at Tier 1 = 90% of annual CBL = 1080 GWh for discussion only 24 Load Priced at Tier 2 = 10% of CBL + load growth = 240GWh

27 Monthly vs.. Annual Stepped Rate Bill Example Month CBL Actual GWh Monthly Step CBL energy Cumulative Annual Step GWh Rate Bill charged at Actual GWh Rate Bill ($M) 1821 ($M) ($M) Jan $2.00 $ $2.00 Feb $3.87 $ $3.00 Mar $2.00 $ $2.00 Apr $3.87 $ $3.00 May $2.00 $ $2.00 Jun $3.87 $ $3.00 Jul $2.00 $ $2.00 Aug $3.87 $ $3.00 Sep $2.00 $ $2.00 Oct $3.87 $2.79 1,000 $3.00 Nov $2.00 $2.79 1,080 $2.00 Dec $3.87 $2.79 1,200 $6.48 Total $35.18 $33.44 $33.44 Annual CBL= 1200GWh Note 90% of annual CBL reached in November (1080GWh/ 1200GWh = 90%) Energy charges used: Tier 1 Price $25/MWh Tier 2 Price $54/MWh 1821 Energy $28/MWh Charge Assume monthly change in load, but no change in annual load from CBL load for discussion only 25 Monthly stepped rate is not bill neutral, annual stepped rate is bill neutral, compared to CBL charged at 1821.

28 Annual Stepped Rate Impacts Customer Impacts: - reduces bill volatility problem under monthly CBL. Hence, will be preferred by customers that cannot control monthly production - provides customer flexibility when scheduling maintenance BC Hydro Impacts: - maintains design parameters of BCUC recommendations, but simpler to administer - cash flow implication is small for discussion only 26

29 Proposed Tier 2 Price The weighted average price from the last province-wide energy Call for Tender (CFT). This price is currently $54/MWh MWh. price is forward-looking transparent aggregate price based on actual contracts not subject to exchange rate and other changes Tier 2 price will be fixed for a 3 year period. updates based on the weighted average price from the latest province-wide energy CFT for discussion only 27

30 Proposed CBL Use 1 year of historical data base CBL on last 12 billing months prior to the BCUC decision on this application no pro-rating required and no cost reallocation administratively simple - one annual kwh number less contentious Fixed CBL with +/- 10% dead-band consistent with 90/10 split reduces administrative burden allows customer to manage normal load volatility for discussion only 28

31 CBL Adjustments Pre-Implementation Adjustments will be made for events that impact the period used to determine the CBL: For Power Smart Funded Projects implemented in the CBL data period, CBL is adjusted to be net of the annual project savings As previously detailed, customers can buy back eligible Power Smart funded projects prior to the rate implementation (BCUC approval required) Significant capital investments which result in > 10% load change (which is not already recognized in CBL) An adjustment to remove the impact of any Force Majeure event For any self-funded efficiency project implemented after January 1, 2003 (upon verification) for discussion only 29

32 CBL Adjustments Post-Implementation Annual review of all CBLs will occur CBL will be reset at review if the annual consumption changes outside +/-10% dead-band CBL reset to most recent year consumption If at review annual consumption outside +/- 10% results from self funded energy efficiency, customer-based generation, or force- majeure events then CBL would not be adjusted customer must notify BC Hydro Adjustments which will occur at time of event For Power Smart funded projects, CBL will be adjusted at project implementation and at M&V Adjustments will be made for significant capital investments which result in >10% load change upon verification for discussion only 30

33 Proposed CBL For New Customer Bill new customer with blended 90% Tier 1 price and 10% Tier 2 price for actual monthly energy consumption for a 1-year period to establish CBL. After one-year, new customer is placed on stepped rate or has the option of subscribing to time-of-use rate Billing treatment of significant new load from existing customers similar to billing treatment of load from new customers for discussion only 31

34 Proposed Demand Charge RS1821 Demand Charge Highest kv.a demand in the Billing period or ratchet, whichever is highest Stepped Rated Demand Charge Same as existing RS1821 demand charge Maintains incentive to invest in load-factor improvement for discussion only 32

35 Aggregation BCUC recommendation #11, That load aggregation within multiplant ownership be allowed so long as it is restricted to operating units. BC Hydro Proposal Allow aggregation of individual CBLs across multiple operating facilities into a single CBL for energy only Demand charges still applied on individual plant basis A single bill will be sent to customer s designated address for discussion only 33

36 Retail Access Richard Stout BC Hydro for discussion only 34

37 Retail Access Design Principles Consistency of design with the Energy Plan & discussions in last June s HC / SR hearing Minimize inter- and intra-class cost shifting Simplicity in design / implementation / administration for discussion only 35

38 Retail Access Under Stepped Rate BC Hydro proposes that IPP to deliver energy to the retail access customer via BC Hydro s Network Integration Transmission Service (NITS) contract for discussion only 36

39 Retail Access Under NITS IPP / power marketer arranges for delivery of energy to BC Hydro s grid (or a physical connection of its generator to the grid) BC Hydro treats IPP s output as a network resource BC Hydro will impose an imbalance charge based on BCTC s OATT imbalance charge on the IPP for deviations from its planned output schedule BC Hydro bills the customer based on its net take (metered consumption less IPP schedule for energy with loss adjustments; metered half-hour peak for demand) per Stepped Rate tariff for discussion only 37

40 Billing For The Retail Access Customer Under NITS kwh Stepped Rate demand (kva) Energy Billed by BC Hydro Scheduled output from Third Party Retail Supplier time for discussion only 38

41 Imbalance Charge For Third Party Retail Supplier kwh credit for over supply actual output charge for under supply Scheduled output time for discussion only 39

42 Shape Of IPP Output Scheduled output from the IPP should be a flat year-round block otherwise, the IPP can arbitrage between wholesale market prices and the fixed Tier 2 rate of Stepped Rate (i.e., sell to retail access customer during low-priced times and to the market during high-priced times) for discussion only 40

43 Exit & Entry Rules Customers electing retail access must stay for a minimum of 3 years with a one-year s notice to return Charge for early return retail access energy scheduled for the balance of the term will be priced at the higher of the short- term market price or Tier 2 for discussion only 41

44 Break for discussion only 42

45 Time Of Use Rate Design Gifford Jung BC Hydro for discussion only 43

46 Time-Of-Use Rates BCUC recommendation #13 That time-of- use rates should be implemented at the same time as stepped rates. Provide more rate choice, with mutual benefit to customer and BC Hydro for discussion only 44

47 Time-Of-Use Rate Design Principles The TOU rate is optional. The TOU rate should provide mutual benefits to BC Hydro and customers. The TOU rate should be integrated with stepped rate and other rate offerings so that customer choice between the offerings does not result in cost shifting to other customers and customer classes. for discussion only 45

48 Product Structure Two Part Rate Design Fixed demand and energy charge based on monthly CBL +/- TOU prices for changes in consumption compared to CBL TOU Monthly CBL CBL Demand On-Peak Energy On-Peak Period: Monday - Saturday, 6:00 am - 10:00 pm Off-Peak Energy Off-Peak Period: Monday - Saturday 10:00 pm - 6:00 am and all day Sunday and BC statutory holidays for discussion only 46

49 Product Structure (contd( contd.) Firm Delivery Firm transmission up to Maximum kva Demand To Contract Demand when transmission available TOU Pricing One Year Term with market-reflective On-Peak and Off-Peak prices Three Pricing Seasons Winter (November to February) Spring (May & June) Remainder of Year for discussion only 47

50 TOU Energy Charge Calculation Fixed Charge TOU Charge TOU Credit MWh Above baseline load, consumption is charged at the TOU price. Below your baseline load, you are credited at TOU price. Customer Baseline Load Actual Use Off-Peak On-Peak Hours Off-Peak 6 a.m. 10 p.m. Hour for discussion only 48

51 What Customers Will Benefit From TOU? Shifters primary target for program shift load from peak periods to off-peak periods Growers grow load in the off-peak periods Conservers reduce load in the peak periods for discussion only 49

52 Increase load in off-peak, charge at off-peak price Benefit Of Load Shifting Reduce load in on-peak, credit at on-peak price MWh Customer Baseline Load + Off-Peak On-Peak Hours Off-Peak 6 a.m. 10 p.m Fixed TOU Charge for discussion only Charge 50 TOU Credit Hour

53 TOU Pricing Methodology TOU price is based on BC Hydro s market opportunity cost Market Prices Use 1 year Mid-C forward prices closest trading hub to BC border for discussion only 51

54 Sample Mid-C Forward Prices August 23, 2004 ($CAD/MWh MWh) HLH LLH Flat Jan $76.38 $65.66 $71.42 Feb $72.36 $61.31 $67.62 Mar $64.66 $58.63 $62.12 Apr $58.29 $46.23 $53.21 May $45.23 $37.52 $41.83 Jun $43.89 $36.18 $40.45 Jul $64.32 $53.60 $59.59 Aug $74.71 $62.31 $69.51 Sep $61.31 $51.59 $56.78 Oct $61.64 $53.60 $58.26 Nov $67.00 $58.96 $63.25 Dec $74.04 $65.66 $70.34 for discussion only 52

55 Adjustments For BC Price BC price reflects market opportunity cost Transmission constraints occur in non-winter months Reflects BC Hydro operating conditions and storage capability Shaped Tier 2 price is a long-term proxy for the short-term value of storage for discussion only 53

56 Shaped Tier 2 Price Mid-C Shape Mid-C Shaped Tier 2 ($54/MWh) Price HLH LLH HLH LLH January 117% 98% February 108% 105% March 106% 103% April 103% 85% May 98% 67% June 98% 68% July 105% 82% August 107% 90% September 106% 98% October 105% 98% November 112% 104% December 116% 93% Average % 91.80% * Note: Rounding error causes a slight difference in the derived annual average flat price from $54 in this example. for discussion only 54

57 Winter Pricing Winter = November, December, January, February BC Hydro system is winter peaking Load shifting in winter provides BC Hydro with load management benefits Winter TOU price structure is derived directly from Mid-C one year forward prices for discussion only 55

58 Spring Pricing Spring = May and June Pricing reflects operating/storage conditions. Importing low cost energy for future use or sale. BC Hydro operates under constraints during this period. Spring TOU price reflects operating conditions and transmission constraints for discussion only 56

59 Remainder Of Year Remainder of Year = March, April, July-Oct. Pricing reflects operating/storage conditions. BC Hydro may be buying or selling depending on market and water conditions. Transmission constraints occur during this period. Remainder of Year TOU price reflects operating conditions and transmission constraints for discussion only 57

60 Sample TOU Prices Pricing plan from November to February Winter Credit/Charge Pricing plan for May and June Spring - Credit Price Sample TOU prices based on Mid-C forward prices (August 23, 2004) Illustration reflects 24 hour pricing, Monday to Saturday. All hours on Sundays and Statutory Holidays are considered offpeak. Spring - Charge Price This is your pricing for the rest of the year Remainder of Year Credit Price Remainder of Year -Charge Price for discussion only

61 CBL For TOU Rate Demand charge based on fixed CBL demand preserves incentive to load shift CBL based on 1-year volume and shape CBL energy amount defined for On-Peak and Off- Peak periods for each month CBL demand based on average of last 12 months demand CBL adjustment process is the same as for stepped rate. Volume adjustments only for discussion only 59

62 Other Terms And Conditions Volume Restrictions: for consistency with stepped rate, a 10% volume restriction would be placed for load reduction in the non-winter months Exit and entry Annual election period No switching within contract period for discussion only 60

63 Customer Time-Of-Use Bill Winter Month Example Assume: CBL demand per month = 10 MV.A at 100% load factor and 100% power factor Consumption per month = 10MW*720 hours = 7,200,000kWh 1821 Rates = $4.730/kV.A and $ /kWh Monthly fixed charge = ($4.730 * 10,000 kv.a) + ($ * 7,200,000kWh) = $247,964 Customer Monthly Peak Off-peak Peak Off-peak Peak Off-Peak Net Total Response fixed period kwh period kwh rate rate period period monthly monthly charge change change $/kwh $/kwh $ impact $ impact bill impact Bill No change $247, $0 $0 $0 $247,964 Load-shift $247, , , $29,952 $26,208 -$3,744 $244,220 Conservation $247, , $29,952 $0 -$29,952 $218,012 for discussion only 61

64 Standby / Maintenance Rates Richard Stout BC Hydro for discussion only 62

65 Standby Design Principles (1) Consistency of design with the Energy Plan (2) Minimize inter- and intra-class cost shifting (3) Simplicity in design / implementation / administration for discussion only 63

66 Elimination Of RS1880 Energy Plan Policy Action #21: incremental consumption should be priced at cost of new supply. creation of Standby Rate and Maintenance Rate to replace energy due to on-site generation outages for discussion only 64

67 Standby Rate Requires metering of generator as evidence of outage energy supplied on an as available basis No demand charge Energy charge to be based on the Tier 2 rate reflects BC Hydro s acquisition cost of new supply, per Energy Plan applies to all energy above the deemed Stepped Rate demand level on a half-hour basis within the period of use for discussion only 65

68 Standby Energy Determination kwh Standby Energy Stepped Rate demand (kva) Standby period of use time for discussion only 66

69 Maintenance Rate Prescheduled with BC Hydro during lengthy maintenance period of on-site generation Requires metering of generator as evidence of outage energy supplied on an as available basis No demand charge Energy charge to be based on the Mid-C Daily Indices for discussion only 67

70 Exempt Rate Customers Richard Stout BC Hydro for discussion only 68

71 Customers Exempted From Stepped Rate There are three customers exempted from Stepped Rate, as directed by the Government in Special Direction HC2 the proposed structure will have a demand charge and a blended energy charge of 90% at Tier 1 and 10% at Tier 2 based on actual monthly consumption for discussion only 69

72 Implementation Richard Stout BC Hydro for discussion only 70

73 Stepped Rates Implementation Assume BCUC decision in mid-2005 Proposed subscription period (once a year): Customer informs BC Hydro whether it wants to be on stepped rate or TOU rate by January 1, 2006 Customer is on chosen rate on February 1st of each year for discussion only 71

74 Summary / Q&A Summary Scope Stepped Rate Design Retail Access Time of Use Rate Design Standby Rate (1880) Exempt Rate Customers Implementation Questions for discussion only 72

75 Closing Web link for information (Q&A s will be posted): bchydro.com/stepped Load Data: 2004 data is available on request full 2004 data will be sent out on early 2005 Contacts: Contact Key Account Manager BCH Regulatory Group for discussion only 73

76 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 2.0 Reference: Application, p. 1-2 BCUC Recommendation #8, and p. 1-11, Section 3.5 Page 1 BC Hydro proposes to use an "Annual CBL Model", primarily to ensure annual revenue neutrality for each customer. This approach is intended to accommodate cases in which the customer's monthly load pattern varies from historical monthly load pattern, but overall annual consumption is unchanged. The example provided in Figure 1 illustrates that the cost of monthly consumption that exceeds the CBL by more than 10% would not equal the savings associated with a symmetrical reduction in monthly consumption relative to the CBL Please confirm that as demonstrated in Slide 25 from the November 25, 2004 workshop, consumption with monthly deviations of +/- 20% is revenue neutral relative to RS 1821 under an annual CBL model and is not revenue neutral under a monthly CBL model. RESPONSE: Confirmed.

77 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 2.0 Reference: Application, p. 1-2 BCUC Recommendation #8, and p. 1-11, Section 3.5 Page 1 BC Hydro proposes to use an "Annual CBL Model", primarily to ensure annual revenue neutrality for each customer. This approach is intended to accommodate cases in which the customer's monthly load pattern varies from historical monthly load pattern, but overall annual consumption is unchanged. The example provided in Figure 1 illustrates that the cost of monthly consumption that exceeds the CBL by more than 10% would not equal the savings associated with a symmetrical reduction in monthly consumption relative to the CBL Please confirm that, as demonstrated by slides 23 and 24, under BC Hydro's "Annual CBL Model", if the customer's annual consumption varies by +/- 10% or less relative to the CBL, the annual cost of increased consumption is equal to the annual saving that would occur as a result of the same magnitude in reduction in annual consumption. RESPONSE: Confirmed.

78 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 2.0 Reference: Application, p. 1-2 BCUC Recommendation #8, and p. 1-11, Section 3.5 Page 1 BC Hydro proposes to use an "Annual CBL Model", primarily to ensure annual revenue neutrality for each customer. This approach is intended to accommodate cases in which the customer's monthly load pattern varies from historical monthly load pattern, but overall annual consumption is unchanged. The example provided in Figure 1 illustrates that the cost of monthly consumption that exceeds the CBL by more than 10% would not equal the savings associated with a symmetrical reduction in monthly consumption relative to the CBL Please confirm that, under BC Hydro's "Annual CBL Model", if the customer's annual consumption varies by more than 10% relative to the CBL, the annual cost of such increased consumption is not equal to the annual saving that would occur as a result of the same magnitude in reduction in annual consumption. RESPONSE: Confirmed.

79 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 2.0 Reference: Application, p. 1-2 BCUC Recommendation #8, and p. 1-11, Section 3.5 BC Hydro proposes to use an "Annual CBL Model," primarily to ensure annual revenue neutrality for each customer. This approach is intended to accommodate cases in which the customer's monthly load pattern varies from historical monthly load pattern, but overall annual consumption is unchanged. The example provided in Figure 1 illustrates that the cost of monthly consumption that exceeds the CBL by more than 10% would not equal the savings associated with a symmetrical reduction in monthly consumption relative to the CBL. Page Is this the outcome intended by BC Hydro? Why or why not? RESPONSE: Monthly variations of individual consumption levels in excess of 10% lead to charges that are not revenue and bill neutral if tiered pricing is calculated and if bills are rendered on a monthly basis. This is a consequence of the asymmetry of the two tiered rate design. The outcome intended by BC Hydro is the preservation of revenue and bill neutrality as recommended by the BCUC. This is better achieved through the application of tiered pricing on an annual rather than a monthly basis.

80 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 2.0 Reference: Application, p. 1-2 BCUC Recommendation #8, and p. 1-11, Section 3.5 BC Hydro proposes to use an "Annual CBL Model," primarily to ensure annual revenue neutrality for each customer. This approach is intended to accommodate cases in which the customer's monthly load pattern varies from historical monthly load pattern, but overall annual consumption is unchanged. The example provided in Figure 1 illustrates that the cost of monthly consumption that exceeds the CBL by more than 10% would not equal the savings associated with a symmetrical reduction in monthly consumption relative to the CBL. Page If the asymmetrical price outcome for symmetrical deviations outside the 10% band is not considered fair on a monthly basis, why is it considered fair on an annual basis? RESPONSE: The asymmetrical price outcome is less likely to occur on a year to year basis as the year to year change in electricity consumption for most customers is less volatile than the month to month change in electricity consumption. An illustrative example would be a shipping terminal where the annual number of vessels handled is stable, but where the number of vessels handled month to month varies significantly and is determined by seasonal, competitive or other factors. Annual treatment also provides flexibility to perform maintenance that would create CBL difficulties if treated on a monthly basis.

81 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 3.0 Reference: Application, p. 1-4 BCUC Recommendation #12, and p. 1-18, Tab 2 Page 1 BC Hydro proposes that all customer CBLs be subject to approval by the Commission Would BC Hydro consider that Commission approval of the CBLs was effectively obtained if the Customer Baseline Load Determination Guidelines as filed under Tab 2 of the application formed part of the approved Transmission Service Rate, and BC Hydro was obligated to implement it (similar to its obligation to apply an approved rate)? If not, why not? RESPONSE: BC Hydro does not believe that Commission approval of the Customer Baseline Load (CBL) Guidelines alone would bring BC Hydro into compliance with the Utilities Commission Act (UCA). Section 61(1) of the UCA requires public utilities to file all schedules of rates with the Commission. Section 61(3) makes rate schedules unenforceable unless they have been filed in accordance with the UCA. Individual customer CBLs are an essential part of each customer s rate schedule, without which no stepped rate or TOU bill can be calculated. Thus all CBLs must at least be filed under section 61(1). BC Hydro notes that section 61(1) of the UCA does not expressly require the Commission to approve a rate, while section 61(2) of the UCA requires the Commission's approval to amend a rate. The implication is that no Commission approval is required for new rates filed with the Commission for the first time under section 61(1), and that Commission approval is only required when a rate is amended. However, the practice in British Columbia has been to both file rates and to concurrently seek approval of those rates, even where the rates are new and not simply being amended. Moreover, BC Hydro doubts that there would be any appreciable advantages to be gained from filing without obtaining Commission approval, as in undisputed cases the Commission's consideration of customer CBLs ought to be quite efficient. Where BC Hydro and a customer disagree on a CBL the Commission will have to resolve the issue in either case.

82 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 3.0 Reference: Application, p. 1-4 BCUC Recommendation #12, and p. 1-18, Tab 2 Page 1 BC Hydro proposes that all customer CBLs be subject to approval by the Commission In BC Hydro's opinion, would the above approach, coupled with direct Commission involvement (after the approval of the tariff in general) only in circumstances where there is a dispute between BC Hydro and the customer respecting the CBL, be an efficient way to implement the Stepped Rates, and reasonably conform with the intent behind the BCUC Recommendation #12 and the Government Response? RESPONSE: Please see BC Hydro s response to BCUC IR #

83 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, Reference: Application, p Tier 2 Rate British Columbia Hydro and Power Authority Transmission Service Rate Application Page 1 BC Hydro proposes to use the weighted average price of energy from the last province-wide Call for Tender (CFT) for the Tier 2 rate and notes that the weighted average price of the last province-wide CFT for energy is approximately 5.40 cents/kwh ($53.87/MWh) For the record, please provide a copy of the Information Response reference in footnote 9 on page 1-9 of the Application. RESPONSE: Please see the attached BC Hydro April 2, 2004 response to SIERRA IR # , BC Hydro 2004/05 and 2005/06 Revenue Requirements Application.

84 The Sierra Club Supplemental Information Request No Dated: 19 March 2004 BC Hydro Response issued 2 April 2004 British Columbia Hydro & Power Authority Revenue Requirements Application 2004/05 and 2005/ Reference: Power Smart 10-Year Plan in Appendix I, page 7, Cost of new electricity supply, RESPONSE: Please provide the stream of annual unit costs that were used as a proxy for the long-run cost of new electricity supply. Please provide all studies, documents and work papers that were used in developing this proxy for the long-run cost of new electricity supply. The stream of annual per-unit energy costs is provided in nominal $ in the table below. $/MWh Nominal F F F F F F F F F F F F F F F F F F F F F F The detailed worksheets used to provide the above proxy for the longrun marginal cost of energy are not provided because they portray the confidential bids from the 2003 Green Call respondents. Page 1

85 The Sierra Club Supplemental Information Request No Dated: 19 March 2004 BC Hydro Response issued 2 April 2004 British Columbia Hydro & Power Authority Revenue Requirements Application 2004/05 and 2005/06 Page 2 How does this proxy compare with the cost that would have resulted from the traditional methodology described in this section. Please provide your most recent estimate of the long-run cost of new electricity supply based upon the traditional methodology described in this section. RESPONSE This proxy is comparable with the traditional methodology. Please see BC Hydro s response to SIERRA IR #1.25.0, for the estimate of the long-run cost of new electricity supply, as filed in BC Hydro s Revenue Requirements Application in December, Please see BC Hydro s response to JIESC IR # for the most recent estimate of long-run cost of new electricity supply, as filed in the February, 2004 Evidentiary Update (Chapter 2A).

86 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, Reference: Application, p Tier 2 Rate British Columbia Hydro and Power Authority Transmission Service Rate Application Page 1 BC Hydro proposes to use the weighted average price of energy from the last province-wide Call for Tender (CFT) for the Tier 2 rate and notes that the weighted average price of the last province-wide CFT for energy is approximately 5.40 cents/kwh ($53.87/MWh) Please provide a copy of the last revision of Schedule A-9-A of Chapter 2A of the BC Hydro 2004/05 and 2005/06 Revenue Requirements Application. RESPONSE: The following table shows the last revision of Schedule A-9-A of Chapter 2A of the BC Hydro 2004/05 and 2005/06 Revenue Requirements Application. It was filed as part of BC Hydro s response to BCUC Order G on November 15, 2004 and was renamed Schedule A-9 (November 2004).

87 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application Page 2 1 Domestic Cost Of Energy Schedule A-9 (November 2004) 2 3 For the Years Ended March 31 ($ millions) 4 5 A B C D 6 F2003 F2004 F2005 F Actual Actual Forecast Forecast 8 Domestic cost of energy : 9 Water rentals $258 $246 $255 $ Independent Power Producers and 11 long-term purchase commitments Market electricity purchases Net Purchases from Powerex (Note 1) Natural gas for thermal generation (Note 2) Domestic cost of energy - Non-integrated Areas Domestic transmission Gas transportation Cost of market (Note 3) Other Total Domestic cost of energy $708 $995 $903 $ F2003 F2004 F2005 F Actual Actual Forecast Forecast 24 Domestic energy: 25 GW h's 26 Water rentals 47,665 44,540 44,980 46, Independent Power Producers and 28 long-term purchase commitments 4,950 6,133 6,540 6, Market electricity purchases 896 5,349 4,266 2, Net Purchases from Powerex (Note 1) - 31 Thermal generation Non-integrated Areas Exchange net (1,605) (1,218) ,253 55,199 56,283 56, Less: Line loss and system use (4,689) (5,000) (5,447) (5,483) 36 Net sales to Powerex (48) (1,550) (1,200) 37 Domestic sales volumes 48,677 50,151 49,286 49, $/MW h 40 Water rentals $ 5.4 $ 5.5 $ 5.7 $ Independent Power Producers and 42 long-term purchase commitments Market electricity purchases Net Purchases from Powerex #DIV/0! 45 Natural gas for thermal generation Domestic cost of energy - Non-integrated Areas Total weighted average cost (Note 4) $ 14.5 $ 19.8 $ 18.3 $ Notes: In F2004, Powerex drew down the trade account by 48 GWh, which is made up of 1,693 GWh 52 out of the trade account and 1,645 GWh into the trade account. The value of the energy going into the trade 53 account is more expensive than the current average cost of the trade account. This difference results in a net 54 cost to domestic cost of energy of $30 million. (i.e., The revenues BC Hydro would record from Powerex when 55 the trade account is drawn down is less than the cost BC Hydro records from Powerex when the trade account 56 is increased.) This does not have an impact on the Heritage Contract This includes fixed transportation costs of approximately $10 million related to the Bypass Transportation 58 Agreement between Terasen and BC Hydro Domestic cost of energy transmission which includes congestion management cost Calculated as total cost divided by sales volumes. Shaded amounts indicate changes to the test years from the Revised Evidentiary Update.

88 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, Reference: Application, p Tier 2 Rate British Columbia Hydro and Power Authority Transmission Service Rate Application Page 1 BC Hydro proposes to use the weighted average price of energy from the last province-wide Call for Tender (CFT) for the Tier 2 rate and notes that the weighted average price of the last province-wide CFT for energy is approximately 5.40 cents/kwh ($53.87/MWh) The April 2, 2004 Revision of Schedule A-9-A of the Revenue Requirement Application shows the cost of purchases from Independent Power Producers and long-term purchase commitments as follows ($/MWh): F2003 F2004 F2005 F2006 $ $ $ $ The cost of purchases from Independent Power Producers and long-term purchase commitments appears higher than the proxy for the long-run cost of new electricity supply provided in the footnoted Information Response on page 1-9 of the Transmission Service Rate Application and proposed by the BC Hydro as the Tier 2 Rate. Please explain the basis for the difference in the two sets of costs, and why BC Hydro believes that the proxy for the long-run marginal cost of energy provided in Information Response to Sierra Club Information Request is more appropriate than costs developed on the same basis as Schedule A-9-A of the Revenue Requirement Application. RESPONSE: Schedules A-9 and A-9-A of the BC Hydro 2004/05 and 2005/06 Revenue Requirements Application show the cost of purchases from Independent Power Producers and long-term purchase commitments. These costs include expected energy supply costs arising from third-party energy purchase agreements. These agreements may date back several years, with the earliest being the result of Request for Proposals (RFPs) that were made in 1988 and Section 3, Chapter 4, p. 4-9, of the BC Hydro Revenue Requirements 2004/05 and 2005/06 Application discusses the historical energy purchase agreements in more detail. The cost provided in BC Hydro April 2, 2004 response to SIERRA IR # , from the BC Hydro 2004/05 and 2005/06 Revenue Requirement Application, corresponds to the weighted average price of the last province wide Call For Tender (CFT), which was the 2002/03 Green Call.

89 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application Page 2 BCUC Recommendation #8 states that the Tier 2 rate should reflect the long-term opportunity cost of new supply. The weighted average price of the last province wide CFT best reflects the long-term opportunity cost of new supply since it excludes energy supply costs of existing historical supply agreements, which reflect prices and conditions that prevailed at the time of their signing. BC Hydro proposes to update the Tier 2 price based on the results of the next province-wide CFT, in order that the Tier 2 rate continues to reflect the cost of new supply.

90 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 5.0 Reference: Application, Part 1, p. 1-9, Tier 2 Rate Page 1 BC Hydro proposes to use 5.4 cents, which is the weighted average price of energy from the last province-wide CFT, as BC Hydro's actual cost of acquiring energy for the longer term What is the expected energy output in GWh/year to be generated in F2007 from the 2002/03 Green Call? RESPONSE: The expected energy output in GWh/year to be generated in F2007 from the 2002/03 Green Call is GWh.

91 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 5.0 Reference: Application, Part 1, p. 1-9, Tier 2 Rate Page 1 BC Hydro proposes to use 5.4 cents, which is the weighted average price of energy from the last province-wide CFT, as BC Hydro's actual cost of acquiring energy for the longer term Please comment on the expected annual energy demand at Tier 2. RESPONSE: As a reference point, 10% of the non-exempted transmission service customers total annual energy consumption for F2005 was 1575 GWh. Hence, if F2005 consumption was hypothetically used as the CBL, 1575 GWh would be at the Tier 2 rate.

92 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 6.0 Reference: Application, Part 1, p. 1-10, Tier 1 Rate Page 1 The Filing states that the principle of revenue neutrality requires that a CBL be determined for each customer. The CBL is based on historical consumption data What is the current (e.g., 2004/05) total sales under RS 1821 or sales to customers taking service at 60,000 volts or higher? RESPONSE: Total actual sales to customers taking service under RS 1821, RS 1852, RS 1854 and RS 3808 in F2005 were 17,154 GWh as shown in the following table. Table 1 Total Transmission Service Sales (GWh) Non-Exempt Exempt Transmission Transmission Service Service Customers Customers Total Transmission Service Customers Percentage Difference between Calendar and Fiscal Year Total Sales Calendar ,665 1,291 15,956 F ,168 1,285 15, % Calendar ,371 1,313 15,684 F ,789 1,297 16, % Calendar ,109 1,359 16,468 F ,199 1,439 16, % Calendar ,746 1,432 17,178 F ,747 1,407 17, % Note: Both calendar year and fiscal year sales data are reported. The last column shows the percentage difference between the calendar year and fiscal year total transmission service customer sales. For example, 3.25% shows the percentage difference between the calendar year 2001 and fiscal year 2002 total sales.

93 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 6.0 Reference: Application, Part 1, p. 1-10, Tier 1 Rate Page 1 The Filing states that the principle of revenue neutrality requires that a CBL be determined for each customer. The CBL is based on historical consumption data If possible, please divide the sales volume provided above into industrial sales and commercial sales using the definitions as employed in BC Hydro's annual Electric Load Forecast report. RESPONSE: Using the definitions as employed in BC Hydro s annual Electric Load Forecast, in F2005 actual commercial sales were GWh and industrial sales were 16,501.4 GWh. The split between commercial and industrial classification is based generally on the Standard Industrial Classification (SIC) code: Industrial : Commercial:

94 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 6.0 Reference: Application, Part 1, p. 1-10, Tier 1 Rate Page 1 The Filing states that the principle of revenue neutrality requires that a CBL be determined for each customer. The CBL is based on historical consumption data Please confirm that the CBL determined for each customer, when aggregated, should closely approximate the actual historical aggregated sales to transmission voltage customers that are recorded in the 2004 Electric Load Forecast (after making adjustments for calendar year and fiscal year). If it cannot be confirmed, please explain why not. RESPONSE: Confirmed.

95 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 7.0 Reference: Application, p Stepped Rate Model Page 1 The Application discusses the proposal for an annual stepped rate model rather than a monthly stepped rate model as proposed by BC Hydro during the Heritage Contract Inquiry. It suggests that the change to an annual stepped rate model arose out of discussions with customers, especially those who have little control over their monthly production schedules During the discussions with customers, what level of support did the change to an annual stepped rate model have? RESPONSE: Customers that have significant month to month variations in monthly production and electricity consumption supported the annual stepped rate model. Some customers had concerns that the increased flexibility of the annual stepped rate model would lead to reduced annual consumption as a result of extended maintenance activities. However, other customers were supportive of the increased operating flexibility since it addressed concerns that they had in scheduling maintenance under the monthly stepped rate model. On balance, customer feedback indicated that there was significant support for the annual stepped rate model.

96 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 8.0 Reference: Application, pp and Customer Baseline Load Page 1 The Application states that a potential disadvantage of the annual CBL model is that it has a non-uniform cash-flow impact on the customer but that the cash flow impact on BC Hydro is estimated to be small. BC Hydro then provides an example of the back-end loading impact on financing costs Please show the calculation of the cash flow impact on financing costs using the example in the Application. RESPONSE: The calculation is shown below and is also provided on the attached CD-ROM. Assumed Interest Rate 6.50% January February March April May June Energy Billing under RS1821 $36,000,000 $36,000,000 $36,000,000 $36,000,000 $36,000,000 $36,000,000 Energy Billing under Stepped Rate $32,500,000 $32,500,000 $32,500,000 $32,500,000 $32,500,000 $32,500,000 Difference ($3,500,000) ($3,500,000) ($3,500,000) ($3,500,000) ($3,500,000) ($3,500,000) Interest Impact $19,322 $34,904 $57,966 $74,795 $96,610 $112,192 July August September October November December Total Energy Billing under RS1821 $36,000,000 $36,000,000 $36,000,000 $36,000,000 $36,000,000 $36,000,000 $432,000,000 Energy Billing under Stepped Rate $32,500,000 $32,500,000 $32,500,000 $32,500,000 $41,000,000 $66,000,000 $432,000,000 Difference ($3,500,000) ($3,500,000) ($3,500,000) ($3,500,000) $5,000,000 $30,000,000 Interest Impact $135,253 $154,575 $168,288 $193,219 $160,274 $0 $1,207,397

97 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 8.0 Reference: Application, pp and Customer Baseline Load Page 1 The Application states that a potential disadvantage of the annual CBL model is that it has a non-uniform cash-flow impact on the customer but that the cash flow impact on BC Hydro is estimated to be small. BC Hydro then provides an example of the back-end loading impact on financing costs Has BC Hydro estimated the cash flow impact on financing costs for all Stepped Rate Customers? If so, Please show the amount and the calculation of the annual financing cost change as a result of adopting an annual rather than a monthly CBL model. RESPONSE: No, BC Hydro has not estimated the cash flow impact on financing costs for all Stepped Rate Customers from the customer's perspective.

98 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 8.0 Reference: Application, pp and Customer Baseline Load Page 1 The Application states that a potential disadvantage of the annual CBL model is that it has a non-uniform cash-flow impact on the customer but that the cash flow impact on BC Hydro is estimated to be small. BC Hydro then provides an example of the back-end loading impact on financing costs Assuming there is an increase in BC Hydro's financing costs resulting from an annual CBL model, to which customer class or classes would BC Hydro propose to allocate the increase? Please explain the rationale for the proposed allocation. RESPONSE: Given the relatively small financing impact, as shown in BC Hydro s response to BCUC IR # 1.8.1, BC Hydro does not intend to directly assign these costs to any particular customer class, although this issue could be revisited at the next general tariff application hearing.

99 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 9.0 Reference: Application, Part 1, p. 1-14, CBL for Existing Customers Page The Application states that BC Hydro is proposing the use of a CBL based on the most recent calendar year, rather than based on the average of the last three years. Given that the majority of customers taking service under RS 1821 are industrial customers in sectors such as metal mining, coal, wood, paper, chemical, et. (X-reference: 2004 Electric Load Forecast, Table 10.4) that are subject to external market forces and the market cycles, would a three year average be more representative of a business cycle than one year and therefore require fewer adjustments than the most recent calendar year? RESPONSE: A CBL based on the 3-year average of electricity consumption data would require many more adjustments and anomaly concerns than a CBL based on a single year, since each of the three years would have to be reviewed and adjusted for missing data, force majeure events, equipment addition and DSM investments. In addition, it is more likely pro-rating will be required with a 3-year CBL for the sum of the CBLs to match the consumption forecast for the class. A 3-year average of annual electricity consumption may or may not be more representative of normal consumption than consumption for any specific year given the business cycle. Annual electricity consumption from a single year may be more representative depending on where that year falls in the business cycle. Overcoming the significant difficulty of applying a 3-year average that addresses the economic cycle and anomaly concerns of customers, while minimizing the cost shifting between customers, is the biggest challenge in the design of a practical CBL procedure. BC Hydro's proposal to use a 1-year CBL addresses most of these concerns and allows for significant administrative simplification for customers, BCUC and BC Hydro.

100 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 10.0 Reference: Application, pp and Customer Baseline Load BC Hydro is proposing the use of a CBL based on the most recent calendar year. Page Please provide a copy of BC Hydro s June 27, 2003 Further Proposal Regarding Stepped Rates and Access Principles as submitted to the Inquiry into a Heritage Contract, Stepped Rate and Access Principles. RESPONSE: Please see attached.

101 BChydro m ui R.A. (Ray) Aldeguer Senior Vice-president Corporate Resources & General Counsel T H E POWER I S Y O U R S June 27,2003 Mr. Robert J. Pellatt Commission Secretary British Columbia Utilities Commission PO Box Howe Street Vancouver, BC V6Z 2N3 Dear Mr. Pellatt Re: British Columbia Hydro and Power Authority ( BC Hydro ) Section 5 Inquiry In response to Order No. G issued June 6, 2003, and further to BC Hydro s 30 April 2003 Heritage Contract, Stepped Rates and Access Principles proposal, we enclose 20 copies of a Further Proposal by the British Columbia Hydro and Power Authority Regarding Stepped Rates and Access Principles. Yours very truly, Ray Aldegue( 1 Senior Vice-Piesident Corporate Resources & General Counsel Copy to: Registered Intervenors British Columbia Hydro and Power Authority, 333 Dunsmuir Street, 18th Floor, Vancouver, B.C. V6B 5R3 Telephone Fax DW %

102 A FURTHER PROPOSAL BY THE BRITISH COLUMBIA HYDRO AND POWER AUTHORITY REGARDING STEPPED RATES AND ACCESS PRINCIPLES JUNE 27, BACKGROUND BC Hydro s April 30, 2003 proposal (the Proposal ) in response to the Terms of Reference* and Commission Order No. G included information on stepped rates and three basic principles for acceptable stepped rate designs: (1) the stepped rate should be a mandatory tariff; (2) the stepped rate should be revenue or bill neutral at historical consumption levels; and (3) the stepped rate should be margin neutral at all consumption levels3 Designs that adhere to these principles do not shift historical costs among customers, ensuring that no individual customers are made worse off by the actions of another existing customer. Beyond the basic principles, however, BC Hydro concluded that it was premature to design the stepped rate without further consultations because many aspects of the stepped rate design depend on customer preferences and a ranking of the relative importance of the stepped rate objectives, including the objectives in the Energy Plan. BC Hydro proposed a consultative process with stakeholders and Commission staff to discuss the elements of stepped rate design. In response to BC Hydro s request for further consultations with stakeholders, the Commission wrote to BC Hydro on May 22, 2003 directing that Commission staff were to convene meetings to consider alternative new rate structures that may achieve the objectives of the Energy Plan. A Proposal by the British Columbia Hydro and Power Authority Regarding a Heritage Contract, Stepped Rates and Access Principles (April 30, 2003). * Order in Council No (March 25, 2003). A FURTHER PROPOSAL BY THE BC HYDRO AND POWER AUTHORITY REGARDING STEPPED RATES AND ACCESS PRINCIPLES - JUNE 27, 2003 I

103 2 Participants interested in the stepped rate issue met on May 27, June 3, June 4 and June 13, Participants agreed that the meetings were intended to facilitate full and frank discussion, would be on a without prejudice basis, and would not be used to attribute positions to specific parties. Participants at the meetings candidly discussed the technical aspects of stepped rate design with the assistance of Commission staff. A summary of the discussions was prepared by Commission staff and distributed to participants. The discussions and the Commission staff summary provided BC Hydro with a greater understanding of the interests of stakeholders, and BC Hydro is now able to further elaborate its proposal with respect to stepped rates. Generally, BC Hydro believes a consensus exists that the first and third principles listed above are important and form an essential part of the rate design for the stepped rate. The second principle is also acknowledged to be important by most or perhaps all of the stakeholders, although some may be prepared to compromise it to serve other objectives that they consider more important. For its part, BC Hydro believes that all three principles can and should be served by the stepped rate design. Chapter 4 of the Proposal elaborated some of the means by which these principles might best be served through specific elements of rate design under three headings: access principles; customer baseline; and a shopping credit vs. two-part rate approach. 1.1 Access Principles BC Hydro continues to believe that access principles cannot be finally determined until the full rate design is identified. During the consultative process it became apparent that most or perhaps all stakeholders agreed that the stepped rate should be introduced cautiously. BC Hydro agrees and believes that a phased implementation of the stepped rate would accomplish this goal. BC Hydro proposes that the initial implementation of the stepped rate not include retail access, which could be added later, as explained below. This phased approach can provide immediate benefits to customers and valuable experience prior to implementation of retail access. 3 Proposal, Volume 2, Chapter 2, Pages 3-4. A FURTHER PROPOSAL BY THE BC HYDRO AND POWER AUTHORITY REGARDING STEPPED RATES AND ACCESS PRINCIPLES - JUNE 27,2003 I

104 3 1.2 Customer Baseline (CBL) The consultations have confirmed BC Hydro's view that CBLs should be developed for each industrial customer that reflect average economic conditions on an industry-by-industry or facility-by-facility basis. Indeed, BC Hydro believes that a strong consensus exists for the general approach that CBLs should be derived using the methodology employed in rate schedule 1848 be continued with some specific adaptations to suit the stepped rate proposal. BC Hydro believes that CBLs should be derived for demand and energy. These issues are discussed more fully below. I.3 Shopping Credit vs. Two-Part Rate In the Proposal, BC Hydro identified a number of attributes of the shopping credit approach that it believed made it preferable to a two-stepped rate. The consultations have made it apparent that there is little support for the shopping credit approach among stakeholders. While BC Hydro believes the shopping credit approach has considerable merit, if stakeholders' concerns would inhibit response to the price signals the shopping credit was intended to send, the rate would not have the desired effect. Moreover, a shopping credit is not an aspect of the design that is necessary to adhere to the three basic principles set out above. Accordingly, BC Hydro believes the Commission should recommend the use of a two-stepped rate, as elaborated below. There may be reason to revisit the merits of the shopping credit when retail access is introduced. 2. STEPPED RATE DESIGN PARAMETERS During the consultative process it became apparent that most or perhaps all of the stakeholders believe that rates should be cost based. The stepped rate design BC Hydro proposes is consistent with that preference, since the rate collects the stepped rate class revenue requirement, which is cost based. BC Hydro believes that the rate design should, as a whole, collect the appropriate revenue requirement at each customer's CBL. In general, BC Hydro also wishes to respect the preference of some customers that each component of the stepped rate should be cost based, but BC Hydro is prepared to compromise that preference, if necessary, to serve the three principles that are the bedrock of the Proposal. A FURTHER PROPOSAL BY THE BC HYDRO AND POWER AUTHORITY REGARDING STEPPED RATES AND ACCESS PRINCIPLES - JUNE 27, 2003 I

105 4 There are three rate design parameters about which choices can be made: the Tier 2 rate, the Tier 1 rate, and amount of energy billed at each rate; that is, the Tier 1TTier 2 split. However, in order to meet the requirement that the rate be revenue or bill neutral, the choice of any two of these parameters will mean that the third is simply a mathematical derivation of the first two. BC Hydro suggests that the two most important parameters about which policy choices should be made are the determination of the Tier 2 rate and the quantity of energy that will be priced at that rate. 2.1 Tier 2 Rate The Energy Plan calls for a stepped rate in which the "last block of energy consumed should reflect the cost of new upp ply".^ Because the cost of new supply is likely to be substantially higher than the cost of BC Hydro's existing resources, the stepped rate design will provide customers with a much larger incentive to invest in conservation, load management or customer-based generation than the existing rate structure does. If the Tier 2 rate is not designed carefully, these customer decisions could lead to cost shifting among stepped rate customers, between the stepped rate and other rate classes, or between ratepayers and the shareholder. For this reason, BC Hydro believes that the most important rate design parameter is the choice of an appropriate methodology for determining the Tier 2 rate. The Tier 2 rate must be no lower than the cost of new supply faced by BC Hydro so as to promote a level playing field between supply from BC Hydro, IPPs, customer based generation, and conservation. However, the Tier 2 rate must also be no higher than the cost of new supply to BC Hydro so as to avoid providing an artificial incentive for customers to reduce purchases from BC Hydro, leading to lost margin and ultimately higher rates. BC Hydro strongly believes that the appropriate indicator of the cost of new supply for determining the Tier 2 rate is the expected cost of purchasing electric energy on behalf of stepped rate customers for a one-year period. Any other indicator is likely to either over- or under-estimate BC Hydro's actual cost of acquiring new supply for that time period. BC Hydro Energy Plan, Policy Action #21, Page 33. A FURTHER PROPOSAL BY THE BC HYDRO AND POWER AUTHORITY REGARDING STEPPED RATES AND ACCESS PRINCIPLES - JUNE 27,2003 I

106 5 also believes that it is prudent to revisit the determination of the Tier 2 rate after the first year of implementation because of the risk of unforeseen consequences stemming from the introduction of a new rate design. These beliefs rule out a number of alternative approaches for determining the Tier 2 rate. An approach based on the long-run incremental cost of constructing a new combined cycle power plant, for example, may be an appropriate indicator of the cost of new supply over a longer time frame, but would not be appropriate for supply with the term of a single year. Similarly, an approach based on the cost of operating the Burrard Thermal Plant would be appropriate during hours in which Burrard is BC Hydro s marginal resource, but would not be appropriate for other time periods. Furthermore, such an approach would require an estimate of the expected cost of purchasing natural gas for a one-year period. An accurate indicator of BC Hydro s cost of new supply must take into consideration supply and demand conditions in regional electricity markets over the appropriate time period. One method for determining the cost of new supply is to use price quotes for standard forward products. There are market-traded products for calendar year around the clock energy delivered to Mid-C for which quotes can be obtained from brokers or from energy exchanges. For example, Powerex deals with a number of brokers - Prebon, Natsource, Tradition Financial -who could be asked to provide quotes for a one year Mid-C product during a given period of time. These quotes could be averaged or used in concert with a Commission approved procedure to form the basis of a Tier 2 rate. Alternatively, Powerex trades and monitors trading activity on the Intercontinental Exchange. Powerex could monitor trade activity in the one year Mid-C product over a given time period and use that as the basis for determining a Tier 2 rate. Should the BCUC recommend, and the government adopt, the principle of using a one year forward price, Powerex and BC Hydro would further investigate any copyright, financial or other issue that may impact the use of such information in determining the Tier 2 rate. BC Hydro believes it can develop a procedure, subject to Commission approval, that will produce an objective rate for these purposes. 2.2 Tier 2 Quantity and Tier I Rate A FURTHER PROPOSAL BY THE BC HYDRO AND POWER AUTHORITY REGARDING STEPPED RATES AND ACCESS PRINCIPLES - JUNE 27,2003 I

107 ~ ~~ 6 Once the Tier 2 rate is determined, one additional design choice is available if bill neutrality is to be ensured: either setting a Tier 1 rate or defining a Tier I/Tier 2 split. The choice of either of these parameters will dictate the other. Many stakeholders prefer that the Tier 1 rate be based on the historical cost of some of BC Hydro's resources, e.g., the cost of heritage electricity. However, if the Tier 1 rate is set at the average cost of all the heritage resources, the Tier 1 rate will not be much lower than the current 1821 rate, and the Tier 1/Tier 2 split will be a very high percentage of CBL. Assuming, for illustrative purposes, a Tier 2 rate of $GO/MWh, an average heritage electricity cost of $25.30/MWh5 for Tier 1 would result in a Tier 1 cut-off of approximately 98% of CBL, with only about 2% of CBL at the Tier 2 rate. While this outcome may be acceptable to some stakeholders, BC Hydro believes that the Commission should advise government that the very limited amount of power being sold at Tier 2 under that design (2% of CBL) would not provide a significantly increased incentive for customers to invest in energy efficiency measures or in alternative supply, compared to the existing 1821 rate. Thus, the approach might not meet the policy objectives the government hoped to serve through this initiative. Some stakeholders proposed using the average cost of BC Hydro's low-cost hydro resources as the basis for setting Tier 1. Adopting this approach would set the Tier 1 rate at approximately $1 9/MWh. Assuming again a Tier 2 rate of $GO/MWh, the Tier 1 cut-off resulting from this selection would be approximately 83% of CBL, with about 17% of CBL at the Tier 2 rate. BC Hydro is not opposed in principle to stakeholder preferences for a Tier 1 rate based on the cost of heritage resources, however, BC Hydro believes that it may be more prudent to explicitly select a desired Tier 2 quantity that limits the potential amount of cost shifting. The Tier 1 rate itself has little consequence for customers whose energy consumption continues to be near their CBL, because these customers' total energy bills, including the Tier 1 and Tier 2 portions, will remain very close to their historical bills. Customers who plan to substantially reduce their consumption under the stepped rate design, by contrast, would benefit from the selection of a 5 The average cost of supplying the Heritage Electricity over the life of the Heritage Contract was estimated by BC Hydro to be $25.30/MWh in Volume 1, Page 9 of the Proposal. A FURTHER PROPOSAL BY THE BC HYDRO AND POWER AUTHORITY REGARDING STEPPED RATES AND ACCESS PRINCIPLES - JUNE 27,2003 I

108 7 low Tier 1 rate and large Tier 2 quantity. However, this choice has the potential to shift costs on to other customers, as customer load reduction increases the risk of lost margin to BC Hydro, particularly if the Tier 2 rate is not set appropriately. In order to minimize the risk of cost shifts resulting from the stepped rate, while still providing a significantly increased incentive for customers to invest in energy efficiency measures or in alternate supply compared to the existing 1821 rate, BC Hydro advocates an initial limit of 10% of CBL priced at Tier 2. BC Hydro believes this quantity is consistent with stakeholders general preference with respect to Tier 2 quantity and strikes the correct balance between volume risk for BC Hydro and customer opportunity. In particular, BC Hydro believes that pricing substantially higher quantities of energy at Tier 2 results in unacceptable risk of cost shifting to other customers during this early stage of the stepped rate design. Accepting the revenue and bill neutrality principle, setting the Tier I/Tier 2 cut-off at 90% of CBL means that the Tier 1 rate will be derived residually from the Tier 2 rate and the 90/10 cut-off point between the two tier rates. BC Hydro understands customers preference to have a cost basis for the rates that are used in the stepped rate design. BC Hydro believes that the stepped rate class revenue requirement forms such a basis. The stepped rate will collect the appropriate revenue requirement at each customer s CBL regardless of the method for determining the Tier 1 and Tier 2 rates. Thus, the stepped rate as a whole is a cost-based rate, even though the Tier 1 rate, under BC Hydro s proposal, is derived residually. 2.3 Derivation of CBL Stakeholders seem to agree that it is necessary to calculate CBLs to implement the stepped rate. Most stakeholders seem to agree that the current means of deriving CBLs under rate schedule 1848 has been successful and could be employed to derive CBLs for all stepped rate customers. Thus, in general, CBLs should be based on an average of the last three years of consumption for both demand and energy, but allowances should be made for anomalies in the production cycle of the customer. The sum of the individual CBLs should be compared to the existing total consumption of the 1821 customers, and the overall allocation under the CBLs normalized to the existing total consumption. The Commission should approve all CBLs. A FURTHER PROPOSAL BY THE BC HYDRO AND POWER AUTHORITY REGARDING STEPPED RATES AND ACCESS PRINCIPLES - JUNE 27,2003 I

109 CBLs should be fixed for an indefinite period so long as the customer continues to consume within a *IO% 8 deadband around CBL; that is, between 90% and 110% of CBL. Within the deadband, the customer s energy consumption could vary without triggering a review of whether an adjustment to the CBL would be required. If the customer reduces its consumption below 90% of CBL, there would be a review to determine whether the decline in consumption is related to the Energy Plan objectives (for example, conservation, customer based generation or supply from IPPs). The CBL would be reduced to the extent the decline in consumption is not related to those objectives. If a customer increases consumption above 1 10% of the CBL, there would be a review to determine whether the increase is related to an increase in productive capacity. The CBL would be increased to the extent the increase in consumption is related to an increase in productive capacity. Such an adjustment would treat load growth at existing facilities and new load equitably. Adjustments could be made for customers with unique circumstances, e.g. customer with a low monthly load factor. The Commission would approve, and resolve disputes about, CBL adjustments. The *I 0% deadband would provide customers some flexibility to manage normal load variation, while not discouraging new production. A deadband of *5% could be used, but it may not provide adequate breadth for customers to accommodate normal load volatility, and would likely increase administrative costs related to CBL management for both BC Hydro and the customer. Some stakeholders have indicated they want existing Power Smart and Customer Based Generation (CBG) programs to continue and be expanded. However, others said that continued use of those programs could further reduce the opportunities available for lpps by reducing overall Tier 2 consumption. To the extent Power Smart and CBG are used with the stepped rate, there should be no double counting of benefits. Any Power Smart or CBG investments supported through a financial contribution by BC Hydro, including those made prior to the implementation of the stepped rate, should result in a CBL reduction to ensure that the customer would not be receiving the benefits of a utility investment in addition to reduced consumption of Tier 2 energy. Again, disputes can be resolved by the Commission. A FURTHER PROPOSAL BY THE BC HYDRO AND POWER AUTHORITY REGARDING STEPPED RATES AND ACCESS PRINCIPLES - JUNE 27,2003 I

110 ~ 9 Some customers have expressed the desire to "aggregate" their loads at multiple locations, such that a single CBL would be established for the combined loads. For example, if a customer owned three facilities each with a "normal" consumption of 100 GWh, the customer's CBL would be 300 GWh. The customer could then reduce load at one facility by 30 GWh and avoid a bill for Tier 2 energy at any of the facilities. The main argument put forward during the consultative meetings supporting load aggregation was that this approach would allow customers expanded opportunities to invest in DSM or customer based generation. BC Hydro believes any DSM or customer based generation opportunities that could not be accommodated within the 10% Tier 2 step at each facility could be realized through Power Smart and CBG programs leaving load aggregation to be primarily of benefit to customers that wish to reduce production. BC Hydro believes that a CBL should be established initially for each customer account and that customers with multiple accounts should not be allowed to aggregate their CBLs, which would in effect transfer Tier 1 energy from one account to another. Load aggregation would increase the risks associated with introduction of the stepped rate design. Customers with load aggregation potential would have a greater opportunity than customers with only one facility to reduce their consumption to avoid the Tier 2 rate. Thus, BC Hydro believes that load aggregation is not in the public interest and should not be allowed. 2.4 Lost Revenue Deferral Account Many stakeholders expressed a concern that whatever Tier 2 rate was chosen, the volatility of electricity markets means that there is likely to be a significant risk of over- or under-collection at the Tier 2 level. Accordingly, there was significant sentiment supporting after-the-fact adjustment based on the actual cost of acquiring new supply over that period. Some customers suggested a deferral account to deal with this concern. In particular, it was suggested that BC Hydro's actual cost of acquiring new supply be determined after the fact and compared to the Tier 2 rate established in advance. Any difference could then be credited or debited to individual industrial customers. A FURTHER PROPOSAL BY THE 6C HYDRO AND POWER AUTHORITY REGARDING STEPPED RATES AND ACCESS PRINCIPLES - JUNE 27,2003 I

111 10 BC Hydro is not persuaded at this time that a deferral account is necessary to manage the risk around Tier 2 rates. In particular, BC Hydro notes that this risk is of a kind borne by the utility today, and is aggravated in the stepped rate context only to the extent that the improved price signal of the second step (relative to the existing embedded cost price signal) causes more price responsive behaviour from customers. However, given the 10% volume restriction contained in BC Hydro s proposal, and considering BC Hydro s proposed use of a one-year market proxy for the second Tier rate, BC Hydro believes that, initially at least, there is no requirement for a deferral account. BC Hydro will monitor the financial exposure created by the rate, and may seek future deferral mechanisms should events show that the new rate structure has materially changed BC Hydro s risk position. Moreover, BC Hydro expects that it would share this information with the Commission as part of any ongoing reviews of the new rate. 3. RETAIL ACCESS The supply characteristics of independent power producers and customer-based generation will mean that customers may wish access to some, but not all, of the traditionally bundled energy products supplied by BC Hydro. BC Hydro believes that derivation of distinct rates for ancillary services and more robust Terms and Conditions to avoid arbitrage between supply from BC Hydro and other sources will need to be developed before retail access is permitted. In particular, the price at which various ancillary services will be charged by the British Columbia Transmission Corporation ( BCTC ) and the basis under which BC Hydro will supply IOS services to BCTC may need to be determined before customers can make full use of the stepped rate through retail access. For these reasons, BC Hydro recommends that the government and the Commission not employ the provisions in the Wholesale Transmission Service tariff ( WTS ) that permit retail access until BCTC has established suitable rate schedules to complement that development. Under the schedule that arises from the Energy Plan, BC Hydro would expect that direct retail access to lpps and marketers might be possible by mid ACCESS PRINCIPLES BC Hydro continues to believe that it would be premature to design access principles until the final details of the rate design are known. In particular, the question of whether direct retail access is to be initially allowed when the stepped rate is implemented will have a large bearing A FURTHER PROPOSAL BY THE BC HYDRO AND POWER AUTHORITY AND ACCESS PRINCIPLES - JUNE 27,2003 REGARDING STEPPED RATES I

112 ~ 11 on the need for comprehensive access principles to prevent rate arbitrage. Nevertheless, certain aspects of the access principles that complement the stepped rate have become clearer through the consultation process. 4.1 Standby Rates Customers who respond to the Tier 2 rate by investing in behind-the-meter generation may still wish to rely on the BC Hydro system for standby power (when their own generation is not available). Consideration needs to be given to the basis on which this would occur. BC Hydro believes that so long as the Tier 2 rate is properly set, there is no need for an additional standby rate for any new behind-the-meter generation. The CBL demand should be used for billing purposes. Currently, standby is provided under schedule BC Hydro proposes that this rate be retained for existing generation; however, the rate will require some modification to make it appropriate for the stepped rate when 1821 no longer exists. 4.2 Energy Imbalance Energy imbalance charges become an issue when lpps sell directly to retail customers or customer-based generation is introduced at a customer's facility. Determination of these charges will eventually be the responsibility of BCTC. In the absence of direct retail access under the stepped rate, development of an energy imbalance rate can await BCTC establishing its own rates. If direct retail access is allowed, BC Hydro would need to establish an energy imbalance service for the initial period before these charges are developed by BCTC. 4.3 Duration of Electricity Service Agreement (ESA) Customers' commitment to take supply from BC Hydro ought to reflect the term and pricing used to determine the Tier 2 rate. Thus, customers should be required to renew their ESA annually. 5. CONCLUSION BC Hydro has concluded the stepped rate should, at least initially, have the following structure: A FURTHER PROPOSAL BY THE BC HYDRO AND POWER AUTHORITY REGARDING STEPPED RATES AND ACCESS PRINCIPLES - JUNE 27, 2003 I

113 12 0 the Tier 2 rate should reflect the cost of new supply to BC Hydro and should be based on a one year market price, 0 the amount of Tier 2 energy should be limited to 10% of the CBL to limit the volume risk, and the Tier 1 rate should simply be arithmetically derived from the Tier 2 rate and Tierlnier 2 split to ensure bill neutrality. BC Hydro believes that the effect of the proposals above will be to introduce stepped rates in a fair and manageable way. The three basic principles that BC Hydro originally set out will be served and stakeholders' preference for cost based rates will be reflected at the revenue requirement level, together with their preference that only 10% of CBL be exposed to the Tier 2 rate initially. For the reasons explained above, the desire of some stakeholders for a Tier 1 rate that reflects the costs of all or a portion of the Heritage resources is not met by this design. Instead, the Tier 1 rate would be derived so as to ensure revenue and bill neutrality. Considerably more detail must be developed before this rate design can be implemented. Accordingly, BC Hydro requests that the Commission recommend the government adopt the principles established above, and that the government direct the Commission to implement a stepped rate which reflects these principles as part of its decision with respect to BC Hydro's revenue requirement based on BC Hydro's application to be filed by March 31, In this way, a stepped rate without retail access could be in effect by late BC Hydro recommends that the government and the Commission not allow retail access until BCTC has established suitable rate schedules to complement that development. Under the schedule that arises from the Energy Plan, BC Hydro would expect that direct retail access to lpps and marketers might be possible by mid A FURTHER PROPOSAL BY THE BC HYDRO AND POWER AUTHORITY REGARDING STEPPED RATES AND ACCESS PRINCIPLES - JUNE 27,2003 I

114 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 10.0 Reference: Application, pp and Customer Baseline Load BC Hydro is proposing the use of a CBL based on the most recent calendar year. Page Please confirm that during the Heritage Contract Inquiry, BC Hydro proposed the use of a CBL based on an average of the last three years of consumption for both demand and energy, with allowances for anomalies in the production cycle of the customer. RESPONSE: Confirmed. At that time it appeared a reasonable proposal, but discussions with customers have since led BC Hydro to believe that a 3-year CBL would result in the considerable difficulties as outlined in BC Hydro's responses to BCUC IR # 1.9.0, # , # , and #

115 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 10.0 Reference: Application, pp and Customer Baseline Load BC Hydro is proposing the use of a CBL based on the most recent calendar year. Page Please confirm that Rate Schedule 1848 determines the CBL in general by averaging the customer s electricity use history for the last three years. RESPONSE: Confirmed. However, RS 1848 is an optional rate with a different rate structure. RS 1848 has had at most 32 participating accounts. The issues raised by the current Stepped Rate proposal suggests a different approach as outlined in BC Hydro s response to BCUC IR #

116 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 10.0 Reference: Application, pp and Customer Baseline Load BC Hydro is proposing the use of a CBL based on the most recent calendar year. Page Please describe the level of customer support expressed during BC Hydro s recent customer consultations for basing the CBL on the most recent calendar year. RESPONSE: Following lengthy discussions with customers on the 3-year CBL, it became apparent that customers were concerned over the level of transparency for adjustments spanning 3 years of data and that pro-rating the 3 year average consumption would lead to cost shifting between transmission service customers. As a result, BC Hydro proposed the simplified approach of basing the CBL on the most recent calendar year. Customers supported this approach since it is simpler for all parties, involves fewer adjustments and avoids pro-rating.

117 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 10.0 Reference: Application, pp and Customer Baseline Load BC Hydro is proposing the use of a CBL based on the most recent calendar year. Page BC Hydro states that basing the CBL on the most recent calendar year is transparent and would minimize the amount of work required since there is less data to adjust for the various approved CBL adjustments. Please confirm that the approved CBL adjustments contemplated in that statement are the adjustments set out on page RESPONSE: Confirmed.

118 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 10.0 Reference: Application, pp and Customer Baseline Load BC Hydro is proposing the use of a CBL based on the most recent calendar year. Page The Application states that pro-rating data to the most recent year of consumption to avoid any cost reallocation would not be required since the most recent data is used for the CBL. Please describe how cost reallocation could result from a CBL based on three years of data and how data could be pro-rated to avoid such reallocation. RESPONSE: The BCUC Recommendations (October 17, 2003) indicated that: "Each individual CBL of RS1821 customers should be adjusted pro rata, such that the sum of the individual CBLs equals the existing total consumption of RS1821 customers." (p. 60) Following the above noted approach, the annual CBLs based on the average of three years of data would be summed and the percentage difference from the most recent total annual consumption of RS 1821 customers would be calculated. The percentage difference would then be used to scale each individual CBL, such that the total difference in electricity consumption is allocated to each customer on a pro-rata basis based on its initial estimated CBL load. Cost reallocation will occur if the initial estimated CBL does not properly reflect the customer's normal operations, as any difference in total consumption is allocated on a pro-rata basis. Costs would be reallocated through the pro-rata allocation if the initial CBLs were not appropriately determined, particularly if some customers were able to increase their CBLs, while others could not. This provides an incentive for upward anomaly adjustment claims. The number of adjustment claims is greater when 3 years of historical data is used. Subsequent discussions with customers resulted in a general agreement that the 1-year CBL would be more predictable, would involve fewer adjustments, would be much easier to administer and also would avoid any pro-rating.

119 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 10.0 Reference: Application, pp and Customer Baseline Load BC Hydro is proposing the use of a CBL based on the most recent calendar year. Page The Application states that CBL determination should be less contentious than using multiple years to develop a CBL as fewer adjustments to metered data should be required. Are the adjustments to metered data referred to in the sentence above the same adjustments mentioned on page 1 15? RESPONSE: Yes.

120 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 10.0 Reference: Application, pp and Customer Baseline Load BC Hydro is proposing the use of a CBL based on the most recent calendar year. Page Please describe the opportunities for a customer to manipulate the CBL to its advantage when the CBL is based on (a) three years of data, and (b) one year of data. RESPONSE: In BC Hydro's view, the customers' opportunities to influence their CBLs are limited under any basis by the economics of their production and the demand for their products. Under a 1-year CBL, there is a somewhat greater opportunity for a customer to manipulate the CBL by increasing consumption to obtain a higher CBL than under the 3-year average CBL, since the gain in subsequent periods would be reduced by the averaging of the data over 3 years. There are also opportunities to manipulate the CBL through the allowable adjustments described on p of the Application (force majeure events, equipment additions, and DSM investments), which depend on information from the customer and which may require verification. There is a greatly increased opportunity for adjustments under the 3-year average CBL and an incentive to do this, as noted in the BC Hydro response to BCUC IR # This could lead to an increase in the amount of inappropriate adjustments, if BC Hydro is unable to verify all customer information. On balance, BC Hydro considers that a 1-year basis with fewer consequent adjustments presents fewer opportunities for CBL manipulation.

121 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 10.0 Reference: Application, pp and Customer Baseline Load BC Hydro is proposing the use of a CBL based on the most recent calendar year. Page Would a CBL based on three years of data be more stable than a CBL based on one year of data? Why or why not? RESPONSE: Over a longer term, there is no reason to believe that a 3-year CBL would be any more stable than a 1-year CBL when there is a CBL adjustment mechanism with a 10% deadband in place. The reason is that on an annual basis, customer consumption does not typically vary by more than 10%.

122 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, Reference: Application, p. 1 19, Section 3.8 British Columbia Hydro and Power Authority Transmission Service Rate Application BC Hydro proposes that the CBLs should be fixed as long as the customer continues to consume within a +/- 10% deadband around the CBL, and that the CBL be reset to the most recent billing year consumption when consumption is outside the deadband. Additionally, if the customer informs BC Hydro of a plant addition, the CBL may be adjusted upwards to reflect the new load at the time of the event. In cases where DSM investments are made, the CBL is maintained at the previous level so that the customers will benefit at the tier 2 rate. Page In the case of a plant addition, or if a customer s consumption slowly and steadily increases over time (say at 10% per year) why should the CBL be adjusted accordingly? Why should the additional energy not be priced at the second tier rate? RESPONSE: In the case of plant additions, as stated in the Heritage and Stepped Rate hearings, BC Hydro is of the view that adjustments to the CBL are appropriate to allow load growth at existing facilities to be treated equitably with new load that has the opportunity to share in the low cost of heritage assets.

123 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, Reference: Application, p. 1 19, Section 3.8 British Columbia Hydro and Power Authority Transmission Service Rate Application BC Hydro proposes that the CBLs should be fixed as long as the customer continues to consume within a +/- 10% deadband around the CBL, and that the CBL be reset to the most recent billing year consumption when consumption is outside the deadband. Additionally, if the customer informs BC Hydro of a plant addition, the CBL may be adjusted upwards to reflect the new load at the time of the event. In cases where DSM investments are made, the CBL is maintained at the previous level so that the customers will benefit at the tier 2 rate. Page Why is it considered fair that load reductions due to DSM are treated differently, in that they do not reduce the CBL in the same way plant additions increase the CBL? RESPONSE: The proposed treatment of load reductions due to DSM is consistent with the Energy Plan objective of encouraging conservation and efficiency. The CBL is not reduced for customer-funded DSM, so that the customer will continue to receive the benefits for DSM load reduction at the Tier 2 rate. This ensures that the customer continues to receive the price signal to conserve at the Tier 2 rate, so that the Energy Plan objective of encouraging conservation and efficiency is met.

124 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, Reference: Application, p. 1 19, Section 3.8 British Columbia Hydro and Power Authority Transmission Service Rate Application BC Hydro proposes that the CBLs should be fixed as long as the customer continues to consume within a +/- 10% deadband around the CBL, and that the CBL be reset to the most recent billing year consumption when consumption is outside the deadband. Additionally, if the customer informs BC Hydro of a plant addition, the CBL may be adjusted upwards to reflect the new load at the time of the event. In cases where DSM investments are made, the CBL is maintained at the previous level so that the customers will benefit at the tier 2 rate. Page If a customer s consumption slowly and steadily declines over time (say at 10% per year) why is it reasonable to adjust the CBL downwards, while in the case of a DSM related reduction it is not? RESPONSE: The Energy Plan cited conservation and efficiency as one of its objectives. Hence, encouraging load reduction through conservation and efficiency is consistent with the Energy Plan objectives. In the case of a decline in load unrelated to conservation measures and greater than 10% of the CBL, it is reasonable to adjust the CBL downwards so that the customer is not credited for simply reducing production.

125 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 12.0 Reference: Application, p CBL Aggregation Page The Application states on page 1 21 that each customer can decide whether to aggregate their CBLs for operating facilities and that energy will be aggregated only, as billing demand will still be determined on an individual facility basis. Please explain why aggregation is limited to energy only and why it is appropriate that billing demand be determined on an individual facility basis. RESPONSE: Heritage Special Direction No. HC2 directs the Commission to design rates for transmission rate customers under specific guidelines which do not include the aggregation of billing demands. Section 3(2b) states: (i) (ii) "Customers who own multiple plants under common ownership may engage in load aggregation for energy, if each plant is in operation, and meets the requirements to be a transmission rate customer that are set out in the authority's tariff, or is otherwise authorized by the commission to be treated as a transmission rate customer." [emphasis added]

126 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 13.0 Reference: Application, p Time of Use Rate On December 23, 1999, the Commission approved a Transmission Service TOU Pilot Program covering the period January 21, 2000 to March 31, BC Hydro filed a Final Evaluation Report for the Pilot Program on May 31, Page Please provide a copy of the May 31, 2001 Final Evaluation Report. RESPONSE: A copy of the report is attached.

127 G hydro L THE POWER IS YOURS Ray Aldeguer Senior Vice-President Legal, Regulatory Affairs and General Counsel Phone: (604) Fax: (604) Mr. Robert J. Pellatt Commission Secretary British Columbia Utilities Commission P.O. Box Howe Street Vancouver, BC V6Z 2N3 RECEIVED 31 May2001 Hearings and Regulatory Records COPIES KMc VBA FJ AHC AJB BVR CF CFF AL DMD JC MAW LM LT SMJ BWM Chew CA CBL NP LC TK 31 May 2001 Dear Mr. Pellatt: RE: British Columbia Hydro and Power Authority ( BC Hydro ) Transmission Service Time-of-Use ( TO, ) Rate Rate Schedule 1850 and Electric Tariff Supplement No. 52 As directed by British Columbia Utilities Commission (the Commission ) letter dated 24 December 1999 and Commission Order No. G that accompanied said letter, we enclose BC Hydro s Final Evaluation Report for the Transmission Service Time of Use Pilot Program. Please note that all dollar amounts that appear in the Evaluation Report are reported in Canadian funds. Yours very truly, Enclosure (1) General Counsel British Columbia Hydro and Power Authority, 333 Dunsmuir Street, Vancouver BC V6B 5R3 wwwbchydro.com

128 BRITISH COLUMBIA HYDRO AND POWER AUTHORITY Final Evaluation Report Transmission Service Time of Use Pilot Program Rate Schedule 1850 Submission to the British Columbia Utilities Commission May 2001

129 British Columbia Hydro and Power Authority Transmission Service Time of Use Pilot Program May PROGRAM IMPACT QUESTIONS Q1.O How many customers participated in the Transmission Service TOU Pilot Program? Al.0 Four customers participated in the Pilot Program. These included two TMP pulp mills, one Kraft pulp mill, and one other industrial site. Q2.0 Which TOU option did customers pick? A2.0 For the winter period (November to February), all customers selected the threetiered option (Option B) that included off-peak, peak, and premium peak periods. For the spring period (May and June), all customers selected the two-tiered option (Option A) that included off-peak and peak periods. Q3.0 What was the response to the TOU Pricing Options? A3.0 In order to mask customer identities, Table 1 - Customer Response to TOU Prices (refer to Page 17 shows the change in each customer s actual consumption compared to assumed CBL consumption on a percentage basis; and also the breakdown between peak period and off-peak periods, again on a percentage basis. The comparisons assume that the CBL consumption pattern is a fairly good representation of what each customer would have consumed had they remained on the standard Transmission Service tariff, Rate Schedule 1821 ( IRS 1821 ). FINAL EVALUATION REPORT Page 1

130 British Columbia Hydro and Power Authority Transmission Service Time of Use Pilot Program May At the theoretical level, the expected load response to TOU pricing would be an increase in the share of consumption during the lower priced off-peak period and a decrease in the share of consumption during the higher priced premium peak and peak periods, when compared to the shares based on the CBL consumption. An analysis of Table 1 indicates the following customer responses:. Customer 1 shifted load from the peak period to the off-peak period. For example, Customer l s actual consumption in the off-peak period in January was 50% of its total January load, compared to 44% for the January off-peak share estimated from the CBL. Customer 1 also reduced its total consumption in January and February, but increased consumption during May and June, when average prices were lower. However, in November and particularly in December, Customer 1 increased total consumption over its CBL despite the higher average winter TOU price. Customer 1 did not noticeably change its consumption pattern in November, but it reduced its share of load in the peak periods and increased its share of off-peak consumption in December. l Customer 2 s total consumption changes relative to its CBL consumption do not appear to be influenced by TOU prices. The customer did not load shift in any of the months, except for December when it increased its share of off-peak consumption. l Customer 3 s total consumption changes relative to its CBL consumption do not appear to be influenced by TOU prices. The customer reduced total loads in May and June when average TOU prices were lower. Although it reduced total consumption in November, it increased total consumption in December. The customer did not noticeably load shift in any of the months, except for December when it increased its share of off-peak consumption. FINAL EVALUATION REPORT Page 2

131 British Columbia Hydro and Power Authority Transmission Service Time of Use Pilot Program May Q A l Customer 4 s total consumption changes relative to its CBL consumption do not appear to be influenced by TOU prices. Customer 4 significantly reduced its load in May, when average TOU prices were lower than the average blended base tariff. It did not appear to respond to TOU pricing in May and June. However, the customer did increase its off-peak consumption shares in November and December. What were the total customer benefits of the TOU Pilot Program? At a conceptual level, customer benefit from TOU pricing is the difference between what the customer would have paid under the standard tariff based on the consumption expected under the standard tariff, and what the customer paid under TOU and based on actual consumption. Unfortunately, what the customer would have consumed, and hence paid, under the standard tariff is hypothetical and not measurable. A proxy for consumption on this basis may be derived by using normalized baseline consumption to estimate the baseline bill. Using this methodology, the monthly CBL energy is scaled by the percentage change in actual annual energy consumption relative to the annual CBL energy. The demand charge portion of the baseline bill is estimated based on the scaled CBL demand. The CBL demand is scaled by the percentage change in actual annual energy consumption, relative to the CBL annual energy consumption. Customer benefit is expressed in dollars and as a percentage of the baseline bill. Taxes are excluded from these calculations. Customer 1 and Customer 3 experienced an overall increase in consumption, while Customer 2 and Customer 4 experienced an overall reduction in consumption, relative to CBL consumption in calendar year FINAL EVALUATION REPORT Page 3

132 British Columbia Hydro and Power Authority Transmission Service Time of Use Pilot Program May Q A Table 2 - Customer Benefits of TOU Pilot Program (refer to Page 18) outlines the customer benefit results. The benefits are measured over the months that the customers participated in the Pilot Program during calendar year What were the total BC Hydro benefits of the TOU Pilot Program? BC Hydro benefits are equal to the change in revenue, minus the change in costs that arose due to the TOU Pilot Program. The TOU Pilot Program was designed to encourage load shifting from the peak periods to the off-peak periods, and BC Hydro would benefit from these actions if off-peak margin (revenue minus cost) were greater than on-peak margin. The TOU rate was designed to produce a positive net benefit for BC Hydro, given price and cost information available at the start of the Pilot Program. Hence, TOU prices were based on Mid-Columbia ( Mid-C ) forward prices, adjusted for expected transmission cost. The assumption was that if bulk wholesale markets are competitive, then expected spot electricity prices would - on average - be equal to forward electricity prices. If TOU prices properly reflect market opportunity costs, then BC Hydro benefits would simply be the change in off-peak consumption caused by the TOU Pilot Program multiplied by the 1 mill adder that was included in the off-peak price for both the winter and spring off-peak periods. The 1 mill adder was included to cover BC Hydro s risk and provide it with a return. BC Hydro benefits based on these assumptions are outlined in Table 3 - BC Hydro Benefits of TOU Pilot Program (refer to Page 19). More generally, the TOU Pilot Program provided incentives for the more efficient utilization of BC Hydro s generation and transmission assets by encouraging customers to shift load from peak periods to off-peak periods. Table 3 shows that there was a significant amount of load shifted to the off-peak period. To the FINAL EVALUATION REPORT Page 4

133 British Columbia Hydro and Power Authority Transmission Service Time of Use Pilot Program May extent that market prices exceeded the forward prices that were the basis for TOU, the value of load shifting to BC Hydro was not fully captured. Q6.0 In BC Hydro s view, did any TOU participants engage in significant curtailments to take advantage of TOU peak or premium peak period pricing credits? A6.0 Customers did not engage in significant curtailments to take advantage of TOU peak or premium peak pricing credits. The data does indicate that load shifting from peak to off-peak periods, or seasonal shifting of load from higher-priced winter months to the lower-priced spring months, was more evident. FINAL EVALUATION REPORT Page 5

134 British Columbia Hydro and Power Authority Transmission Service Time of Use Pilot Program May NEXT STEP QUESTIONS Ql Al.O Should Transmission Service - TOU be offered permanently? What is the purpose of a permanent TOU program? Time-differentiated commodity pricing is a good concept, since it promotes the economically efficient use of generating assets and the transmission network by discouraging growth during peak periods. It can be an effective mechanism to provide customers with marginal pricing signals so that customers have the opportunity to gauge the value of incremental consumption against the market value of electricity at that time. Customers that respond to time-differentiated pricing can decrease their average cost of supply by shifting consumption seasonally or within the day. The following issues need to be considered in a permanent TOU program: 0 The product must be structured and priced to reflect value for BC Hydro. Because customers will only participate in products from which they can benefit, BC Hydro is subject to adverse-selection risks. As a consequence, the only way for all parties to achieve value is if products provide mutual benefits for BC Hydro and participants, for all difference customer load characteristics. 0 Customer participation must reflect the seasonal nature of commodity prices and transmission constraints, and hence the value available to BC Hydro. Customers must enter into contracts that are a minimum of one year in order to avoid the benefits being one-sided.. BC Hydro must be able to reflect its level of price, volume, and foreign exchange risks. Failure to do so impacts non-participants by allowing participants to capture a disproportionate share of the program benefits. FINAL EVALUATION REPORT Page 6

135 British Columbia Hydro and Power Authority Transmission Service Time of Use Pilot Program May This approach is consistent with the recognition that products traded in the wholesale market are not the same as those provided to retail customers.. BC Hydro s time- and risk-differentiated prices must be part of a consistent portfolio. This means that any process to develop a permanent TOU rate should also include modifications to Real Time Pricing ( RTP ) so that the two products are aligned. The above notwithstanding, it is important to recognize that the drivers of a TOU program will change over time. As such, product structure and pricing mechanisms may have to change as circumstances change. Q2.0 Which aspects of the Transmission Service - TOU Pilot Program can be improved? A2.0 BC Hydro s Key Account Managers were surveyed shortly after the subscription period closed so that customers initial views could be reflected within this evaluation report. Based on this feedback, and despite having only four customers subscribe to participate in the Pilot Program, the Key Account Managers indicated that the program was reasonably well received. Specific feedback included the following:. TOU was fairly easily understood. Previous experience by Transmission Service customers with rate products such as RTP likely contributed to the level of understanding. That said, TOU was seen to be a simpler product than RTP. FINAL EVALUATION REPORT Page 7

136 British Columbia Hydro and Power Authority Transmission Service Time of Use Pilot Program May Customers liked the feature of price certainty associated with RS It allowed them to plan their operations and electricity consumption in advance. It also provided them with more stable electricity costs.. The symmetrical pricing aspect of TOU was seen as positive, in contrast to the complex and asymmetric Demand Credit under RTP. 0 The derivation of the CBL is difficult (as it is under RTP). In several cases, it was the combination of CBL and higher-than-rs 1821 prices that kept potential participants from subscribing, particularly when the customers expected to operate at higher levels in 2000/2001 than they had in the past. Although the Commission had approved a mechanism to modify CBLs when warranted, no customers chose to pursue modified CBLs. Based on this feedback, there appeared to be high-level satisfaction with the Pilot Program. Possible changes to the structure or pricing mechanism are considered in the Pricing Questions section of this evaluation report. Q3.0 How can the evaluation results be used to assist with the development of other programs? A3.0 As noted above, the evaluation of the TOU Pilot Program can be used to modify RTP such that value is properly identified and shared between the customer and BC Hydro. The TOU Pilot Program also showed an inconsistency in the treatment of Rate Schedule Transmission Service - Emergency, Maintenance and Special Supply ( RS 1880 ) with TOU and RTP. Changes could be made to make the programs consistent. FINAL EVALUATION REPORT Page 8

137 British Columbia Hydro and Power Authority Transmission Service Time of Use Pilot Program May PRICING QUESTIONS Ql.0 How different were actual market prices from the forward prices used to derive TOU prices? What was the impact on BC Hydro revenue? How different were the Dow Jones forward prices from the Powerex forward prices used to derive TOU rates? Q2.0 How are the pricing periods and price levels derived from Mid-C impacted by transmission constraints? Al.O & A2.0 These specific questions (i.e., Pricing Questions Q1.O and Q2.0) are difficult to answer. They focus on issues such as the accuracy of the forward market in predicting prices up to one year in advance, the relative ability of Powerex in forecasting prices as compared to other marketers, and the ability to predict generation and transmission constraints. It must also be recognized that TOU prices are meant to reflect the value of energy within the BC Hydro system, as opposed to the value at a trading hub such as Mid-C. As a result, BC Hydro offers the following series of questions and answers in response to the general question: Was the TOU pricing mechanism a fair and accurate means of reflecting the marginal value of energy to BC Hydro and its customers?. Winter Prices (November to February) (4 How did actual prices compare to the forward prices used to derive the winter TOU prices? Table 4 - u Comparison of Actual Winter Prices and Forward Prices (refer to Page 20) provides a general comparison of average ex-post High Load Hours ( HLH ) and Low Load Hours ( LLH ) prices against the winter forward prices. FINAL EVALUATION REPORT Page 9

138 British Columbia Hydro and Power Authority Transmission Service Time of Use Pilot Program May Table 4 shows that: 0 The actual January prices were lower than forward prices for the January contract. 0 The actual January price spread was lower than the January price spread for the January contract.. The actual February price spread was also lower than the February price spread for the January and February contracts. In addition, the actual November and December prices were significantly higher than the forward prices for the January and February contracts. The actual price spreads in these months are also much greater, particularly in December. The actual prices reflect the particularly tight wholesale market conditions that prevailed in November and December Table 5 - Comparison of Actual Winter Prices and TOU Prices (refer to Page 21), compares actual winter market prices with TOU prices. Actual prices for January and February 2000 were generally lower than the winter TOU prices for the January and February 2000 contracts. The actual peak and off-peak price differential for January and February 2000, as shown in the first price spread column of Table 5, are lower than the price spreads for the TOU prices derived for the January and February contracts. Actual market prices and actual price spreads for November and December 2000 were significantly higher than the winter TOU prices and TOU price spreads for the January and February 2000 contracts. FINAL EVALUATION REPORT Page 10

139 British Columbia Hydro and Power Authority Transmission Service Time of Use Pilot Program May UN TOU prices did not make adjustments for the transmission differential between Mid-C and the British Columbia/United States border. Was this appropriate? In general, British Columbia border prices should be decreased by transmission costs to Mid-C when BC Hydro exports, and increased by transmission costs from Mid-C when BC Hydro imports. The basic assumption used to develop winter prices was that BC Hydro engages in imports and exports on a roughly equal basis. As a consequence, it was assumed that there were no net impacts of transmission on British Columbia border prices. To test this assumption, power flows on the British Columbia/United States transmission tie were analyzed for the months of November 1999 to February The following is a summary of the results: l During off-peak hours, power flows were balanced between imports and exports during the four-month period. As a result, there was no net impact on transmission costs between British Columbia and Mid-C. This is consistent with the pricing of the TOU Pilot Program. 0 Power flowed into the United States in approximately 75% of peak hours. As a result, exports occurred in a greater proportion of hours than was expected when the TOU Pilot Program was developed. The impact on pricing is that peak hour prices might reasonably have been lowered by $1.5 per MWh. Using an assumed $3 per MWh for transmission charges, peak hour pricing should be adjusted by [75% (-$3 per MWh)] + [25%*($3 per MWh)] = -$1.5 per MWh. FINAL EVALUATION REPORT Page 11

140 British Columbia Hydro and Power Authority Transmission Service Time of Use Pilot Program May Spring Prices (May and June) (cl How did actual prices compare to the forward prices used to derive the spring TOU prices? Table 6 - I Comparison of Actual Spring Prices and Forward Prices (refer to Page 22) shows that actual May and June 2000 prices and price spreads were significantly higher than the forward prices and prices spreads that were available in January and February Market conditions were significantly different than in the past for this time of year, as unusually high demand in California caused high prices in the West. As Table 7 - Comparison of Actual Spring Prices and TOU Prices (refer to Page 23) indicates customers benefited by paying TOU prices, which were significantly lower than actual market prices. The actual market price differentials between peak and off-peak prices were significantly higher than the TOU price differentials. (d) TOU prices made adjustments to off-peak prices to reflect minimum generation constraints and the transmission differential between Mid-C and the British Columbia/United States border. Was this appropriate? BC Hydro did not often run at minimum generation since tight market conditions left little energy available to import. Hence, from an ex post facto perspective, the off-peak spring pricing assumption did not materialize, and the actual weighting implied higher off-peak prices, reflecting the value of future exports. FINAL EVALUATION REPORT Page 12

141 British Columbia Hydro and Power Authority Transmission Service Time of Use Pilot Program May Rest of Year Prices (March, April, July, and September) (e) How did actual prices compare to the rest of year forward prices and TOU prices? The TOU prices for the peak and off-peak periods for the months of March, April, July, and September were not derived from market forward prices, hence the comparison is not provided. The pricing for these months is explained in BC Hydro s response (f) below. (fl A typical average blended rate (i.e., demand and energy) for a higher load was used in the months of March, April, July, and September because Mid-C was assumed not to be reflective of the value of energy at the British Columbia/United States border. Was this appropriate? During these months, BC Hydro is typically transmission constrained, and hence the load management potential of TOU has little value to the Utility. The average blended RS 1821 rate for a higher load factor customer was used, and this is lower than both the actual and forward market prices. If a market-based price had been used to derive a British Columbia/United States border price for this period, it would have been significantly higher than 3.3 cents per kwh and there would have been no uptake of the rate. Instead, the TOU price for these months ensured that the energy charge was, on average, equal to what BC Hydro would have collected from a high load factor customer. FINAL EVALUATION REPORT Page 13

142 British Columbia Hydro and Power Authority Transmission Service Time of Use Pilot Program May General Pricing Issues 3 (9) A risk premium of $1 per MWh was added to off-peak prices in the 4 5 winter and spring. Was the premium appropriate? 6 Yes, the risk premium was appropriate. Products that offer fixed prices 7 with open volumes place risks on the utility. The Transmission Service 8 TOU Pilot Program involved the offering of fixed rates for a one-year 9 period. Forward contracts are for a fixed volume, for a fixed price at some 10 future date. The forward price is risk adjusted for price risk, but not for 11 volume risk. Specifically, the forward price does not include the volume 12 risk associated with the TOU rate subscribers incremental load, and hence it was appropriate to add a risk premium in the TOU price. 15 (h) How did Powerex s forward price quotes compare with those from other sources? 18 Dow-Jones is currently the only independent source of Mid-C forward 19 pricing. However, these quotes are obtained from speaking with only marketers/traders. As a result, these quotes are not necessarily an 21 accurate indicator of the market. The Powerex indicative market prices are taken from a broader survey of the market, and hence should more closely reflect forward market conditions Q3.0 Should a permanent program be structured to reflect BC Hydro s own 27 costs of peak period generation, transmission and distribution, or should 28 generation and transmission prices reflect peak revenue opportunities 29 available from export markets? What would be the difference in peak 30 pricing? 31 FINAL EVALUATION REPORT Page 14

143 British Columbia Hydro and Power Authority Transmission Service Time of Use Pilot Program May A3.0 A permanent program should be structured so that prices reflect market conditions, as long as benefits exist for participating customers, non-participating customers, and BC Hydro. BC Hydro operates its system to maximize value in the wholesale electricity market. TOU has been designed to send price signals so that customers can make marginal consumption decisions in light of expected market conditions. Q4.0 Should a permanent program be based on a revenue neutral initial pricing by customer or by class of customer? A4.0 BC Hydro s current assumption is that a permanent TOU rate would be offered as an optional rate. Given the optional nature of the rate, the program would be based on revenue neutral initial pricing by customer. The rate would thus also be revenue neutral on a customer class basis. FINAL EVALUATION REPORT Page 15

144 British Columbia Hydro and Power Authority Transmission Service Time of Use Pilot Program May IMPLEMENTATION QUESTION Q1.O Did BC Hydro adequately bill and meter customers on the Pilot Program? 5 6 Al.O Yes, BC Hydro adequately billed and metered customers who participated in the 7 TOU Pilot Program FINAL EVALUATION REPORT Page 16

145 British Columbia Hydro and Power Authority Transmission Service Time of Use Pilot Program May 2001 TABLE 1 - Customer Response to TOU Prices Year 2000 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC CUSTOMER 1 % Change in kwh from CBL CBL % Premium Peak % Peak % Off-Peak Actual % Premium Peak % Peak % Off-Peak CUSTOMER 2 % Change in kwh from CBL CBL % Premium Peak % Peak % Off-Peak Actual % Premium Peak % Peak % Off-Peak CUSTOMER 3 % Change in kwh from CBL CBL % Premium Peak % Peak % Off-Peak Actual % Premium Peak % Peak % Off-Peak CUSTOMER 4 % Change in kwh from CBL CBL % Premium Peak % Peak % Off-Peak Actual % Premium Peak % Peak % Off-Peak FINAL EVALUATION REPORT

146 British Columbia Hydro and Power Authority Transmission Service Time of Use Pilot Program May 2001 TABLE 2 - Customer Benefits of TOU Pilot Program Year 2000 Customer Benefit Customer Benefit ($1 As % of Baseline Bill Customer 1 (January - December) 266, % Customer 2 (February - December) 105, % Customer 3 (March - December) 44, % Customer 4 (April - December) 15, % FINAL EVALUATION REPORT Page 18

147 British Columbia Hydro and Power Authority Transmission Service Time of Use Pilot Program May 2001 TABLE 3 - BC Hydro Benefits of TOU Pilot Program Year 2000 Customer 1 Customer 2 Customer 3 Customer 4 TOTAL Change in Off-Peak BC Hydro Consumption Benefit W W (8 14,732,538 14,732 3,708,898 3,709 1,555,305 1, , ,133,573 20,133 FINAL EVALUATION REPORT Page 19

148 British Columbia Hydro and Power Authority Transmission Service Time of Use Pilot Program May 2001 TABLE 4 - Comparison of Actual Winter Prices and Forward Prices ACTUAL PRICE I FORWARD PRICE January 2000 Contract February 2000 Contract 2000 Ex Post Ex Post HLH LLH January February November December Spread / alar 1 y- $r / spread 1 y:i / ytie2t 1 Spread ( I ( ( I I I I I I * The $1 per MWh risk premium was removed from the winter LLH prices to allow a direct comparison with wholesale prices at Mid-C. Prices are based on Dow-Jones 6x16 monthly index definition. FINAL EVALUATION REPORT Page 20

149 British Columbia Hydro and Power Authority Transmission Service Time of Use Pilot Program May 2001 TABLE 5 - Comparison of Actual Winter Prices and TOU Prices ACTUAL PRICE TOU PRICE January 2000 Contract February 2000 Contract 2000 Ex Post Ex Post Winter Winter Winter Winter Spread HLH LLH Spread HLH LLH HLH LLH Spread January February November December FINAL EVALUATION REPORT Page 21

150 British Columbia Hydro and Power Authority Transmission Service Time of Use Pilot Program May 2001 TABLE 6 - Comparison of Actual Spring Prices and Forward Prices ACTUAL PRICE FORWARD PRICE January 2000 Contract February 2000 Contract I I I / Eiy ( Etv 1 Spread 1 Ecig Spring Spring Spring Spread LLH HLH LLH Spread FINAL EVALUATION REPORT Page 22

151 British Columbia Hydro and Power Authority Transmission Service Time of Use Pilot Program May 2001 TABLE 7 - Comparison of Actual Spring Prices and TOU Prices ACTUAL PRICE TOU PRICE May June 2000 I January 2000 Contract February 2000 Contract ExPost Ex Post Spring Spring Spring Spring Spread Spread HLH LLH HLH LLH HLH LLH FINAL EVALUATION REPORT Page 23

152 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 13.0 Reference: Application, p Time of Use Rate On December 23, 1999, the Commission approved a Transmission Service TOU Pilot Program covering the period January 21, 2000 to March 31, BC Hydro filed a Final Evaluation Report for the Pilot Program on May 31, Page Please discuss the extent to which BC Hydro incorporated the results of the evaluation of its Pilot Program into the proposed TOU program RESPONSE: BC Hydro did not explicitly incorporate specific results of the evaluation of its Pilot Program into the TOU program. One reason is that the pricing of the Pilot Program was based on 1-year Mid-Columbia (Mid-C) forward prices. In addition, the Pilot Program TOU rate structure employed a different two-part rate structure, with the first part comprised of a fixed charge based on RS 1821 and the second part comprised of charges and credits based on the TOU rate. Given that the current TOU is based on a longer-term marginal price, as a result of customer consultation, and that its rate structure is integrated with the Stepped Rate structure, it is not possible to incorporate specific results from the TOU Pilot Program evaluation into the current TOU rate. On a broader level, the Final Evaluation Report provides support for the TOU rate concept concluding that time-differentiated commodity pricing can promote more efficient use of generating assets and the transmission network by discouraging consumption during peak periods.

153 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 14.0 Reference: Application, p Time of Use Rate The Time of Use Rate is intended to provide better price signals that will encourage customers to respond by changing their consumption pattern within a day and between seasons. In accordance with BCUC recommendation #13, it should also not result in cost shifting to other customers and customer classes. Page Given the TOU Rate is optional, does BC Hydro agree it is reasonable to expect only those customers whose load patterns already exhibit higher than average weighting in the low load hours to opt for the TOU Rate? RESPONSE: No. As explained on p of the Application, the TOU CBL would be established separately for each month and for both the HLH and LLH for each winter month. As a result, customers who maintain their current load shape would be revenue neutral to the TOU Rate. Only customers who can shift load from their current load shape could benefit from the TOU option. As also explained in BC Hydro s response to BCUC IR # , the TOU rate has been designed to ensure that any such load shifting does not result in cost shifting to other customers and customer classes.

154 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 14.0 Reference: Application, p Time of Use Rate The Time of Use Rate is intended to provide better price signals that will encourage customers to respond by changing their consumption pattern within a day and between seasons. In accordance with BCUC recommendation #13, it should also not result in cost shifting to other customers and customer classes. Page If this is true, and if the prices are set to collect the same revenues for the entire rate class on a forecast basis, how can the rate be revenue neutral, either by individual customer or for the rate class? RESPONSE: Please see BC Hydro's response to BCUC IR #

155 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 14.0 Reference: Application, p Time of Use Rate The Time of Use Rate is intended to provide better price signals that will encourage customers to respond by changing their consumption pattern within a day and between seasons. In accordance with BCUC recommendation #13, it should also not result in cost shifting to other customers and customer classes. Page How would BC Hydro propose to forecast this revenue change and ensure it is not transferred to other customers or customer classes? RESPONSE: Please see BC Hydro's response to BCUC IR #

156 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 15.0 Reference: Application, pp and Time of Use Rate BC Hydro is proposing to use the long-term forecast Mid-Columbia ( Mid-C ) monthly price shape for HLH and LLH to shape the Tier 2 rate for each TOU season. Page Did BC Hydro consider any other forecasts (e.g., either a different trading hub or different forecast term or both) for shaping the Tier 2 rate? If not, why not? If so, what other forecasts were considered and why were they rejected in favour of the Mid-C long-term forecast? RESPONSE: BC Hydro did not consider forecasts for a different trading hub, as the Mid-C trading hub is the closest liquid trading hub to the BC/US border. The BCUC has accepted the Mid-C price index in past BC Hydro retail rate designs (e.g., RTP and the Pilot TOU program) as the best reflection of BC Hydro's market opportunity cost. Please also see BC Hydro s response to BCUC IR # regarding the different forecast terms.

157 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 15.0 Reference: Application, pp and Time of Use Rate BC Hydro is proposing to use the long-term forecast Mid-Columbia ( Mid-C ) monthly price shape for HLH and LLH to shape the Tier 2 rate for each TOU season. Page Please describe the difference between a long-term forecast Mid-C monthly price and a forward market price of a one-year contract for Mid-Columbia delivery. RESPONSE: The difference is that one is a yearly price shape based on a long-term forecast and the other is based on the shape from a yearly forward market price. The following describes these in more detail. Long-term forecast Mid-C monthly price: BC Hydro's long-term forecast of the Mid-C monthly price is based on Mid-C forward market prices in the short-term, Henwood model results for the mid-term, and the long-run marginal cost (LRMC) for the long-term. The annual values can be levelized to provide a single forecast long-term Mid-C price. Mid-C forward indicative prices for the short-term are based on brokers' quotes for wholesale bulk power purchases. The long-term forecast Mid-C monthly price shape is based on an average of the forecast monthly price shape from the Henwood model. Henwood Prosym is a structural model of the western electricity markets. BC Hydro's implementation of the Prosym model simulates hourly supply and demand balances for the various western markets based on assumed levels of generation capacity (and associated technology), demand characteristics, and natural gas prices. The LRMC is based on the fully loaded (i.e. natural gas costs, O&M, sustaining capital, depreciation, and return to capital) costs associated with the construction and operation of a Combined Cycle Gas Turbine generator in the Lower Mainland. The LRMC is shaped by the long-term forecast Mid-C monthly price shape that provides the monthly long-term forecast values. Forward market price of a 1-year contract for Mid-C delivery: A forward market price of a 1-year contract for Mid-C delivery is the negotiated price set out in the contract between two parties for a standard block of power delivered at Mid-C for a 1-year period.

158 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application Please see BC Hydro's response to BCUC IR # , which explains why BC Hydro uses the yearly price shape from the long-term forecast instead of the shape from a yearly forward price quote to shape the Tier 2 rate. Page 2

159 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 15.0 Reference: Application, pp and Time of Use Rate BC Hydro is proposing to use the long-term forecast Mid-Columbia ( Mid-C ) monthly price shape for HLH and LLH to shape the Tier 2 rate for each TOU season. Page Please explain why a long-term forecast monthly price shape is preferred over a one-year forward monthly price shape. RESPONSE: The long-term forecast monthly price shape was used to shape the TOU Tier 2 rate since the Tier 2 rate is longer-term and the price shape and price should match the longer contract term. The Mid-C market forward prices represent current expectations of electricity supply/demand. These prices and the yearly price shapes are variable, as they represent price expectations over the short-term. The yearly price shape as derived from short-term forecasts will contain significant excursions from expected averages due to temporary market and supply/demand conditions. BC Hydro considers that a more representative yearly shape is that derived from a long-term forecast.

160 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 16.0 Reference: Application, p Time of Use Rate Page BC Hydro states that if it were to provide a HLH and a LLH TOU price signal during the non-winter months, customers might shift load from HLH to LLH, thereby transferring some of the benefit that could be obtained by the use of storage in the non-winter months from all BC Hydro ratepayers to TOU customers. Please expand on the potential for transferring benefits under a TOU rate and the conditions required for such a transfer to occur. For instance, are there conditions (e.g. with respect to the amount of available storage) under which such a transfer of benefits would not occur? If helpful, please use examples to illustrate the response. RESPONSE: The reason for the potential for transferring benefits is that the market price shape may not reflect BC Hydro's opportunity cost when there are generation and transmission constraints. The use of storage allows BC Hydro to buy during the LLH and sell later at a higher price. During times of constraints, BC Hydro does not have access to the market and it may need to reduce some of the benefit obtained by the use of storage to compensate for the customer s shift in load, thereby transferring benefit from all BC Hydro ratepayers to TOU customers. The potential for transferring benefits in the non-winter periods is illustrated in Scenarios 1 and 2 below. Scenario 3 below shows the circumstances where BC Hydro could offer TOU prices in the non-winter period based on a market based price shape, and where there is no transfer of benefits from all BC Hydro ratepayers to TOU customers. All scenarios assume the following TOU prices shown in Table 1 for the nonwinter period based on the shaped $54/MWh using the long-term Mid-C market price shape: Table 1 Non-winter TOU prices based on long-term Mid-C market price shape $/MWh HLH LLH Spring Summer and other Scenario 1: Spring Period with Minimum Generation and Transmission Constraints In the spring period, there is the potential for transferring of benefits. This may occur when the BC Hydro system faces minimum generation constraints and is importing to transmission limits during the LLH period. If domestic load is greater

161 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application than minimum generation levels in the LLH, BC Hydro will be using storage and low cost imports to serve part of the generation levels. However, if imports are at transmission limits, then any incremental load in the LLH may have to be served by additional generation, which has a higher opportunity cost than the LLH price. The reservoir could be re-filled by purchasing at the HLH price, as it is assumed that there are no import or export constraints in the HLH period. Assume a customer reduces its HLH consumption by 10MWh and increases its LLH consumption by 10MWh in response to TOU pricing in the spring. Table 2 outlines the change in the customer s bill, the change in BC Hydro's energy costs and the net change in BC Hydro income, where net change in BC Hydro income is equal to the change in revenue minus the change in energy costs: Table 2 Scenario 1 - Example of Load Shift Impact in Spring Period Spring Period HLH s LLH s Customer Action Reduce load by 10 MWh Increase load by 10 MWh Change in Customer Bill Higher/(Lower) ($529) $365 Net Change in Customer Bill Higher/(Lower) ($164) BCH response Sell 10 MWh into market Increase generation during LLH, and buy 10 MWh from market during HLH to re-fill reservoir Change in BCH Energy Costs Higher/(Lower) ($529) $529 Net Change in BCH Energy Costs $0 Higher/(Lower) Net Change in Revenue Higher/(Lower) ($164) Net Change to BCH Income Higher/(Lower) ($164) In this scenario, the customer saves $164 on its bill as a result of shifting its load. BC Hydro's energy costs are lower in the HLH period by $529 as a result of the load reduction, but higher in the LLH period by $529 as a result of the load increase. Note that transmission constraints during LLH do not allow for purchases from the market to serve incremental load during LLH. Energy will be generated to serve incremental load and re-purchased in a subsequent HLH period to re-fill the reservoir. Therefore, there is no net change overall in BC Hydro s energy costs. However, there is a net decrease of $164 in BC Hydro's net income, which is the source of transfer of benefit from all ratepayers to TOU customers. Scenario 2: Summer/Other Period with Export Transmission Constraints In the summer and other months, assume that there are no import or export constraints during the LLH, no import constraints during the HLH and no available Page 2

162 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application transmission for incremental exports in the HLH. Using the same customer load shift assumptions, Table 3 shows the change in the customer bill, the change in BC Hydro's energy costs and net change in BC Hydro income: Page 3 Table 3 Scenario 2 - Example of Load Shift Impact in Summer/Other Period Summer/Other HLH s LLH s Period Customer Action Reduce load by 10 MWh Increase load by 10 MWh Change in Customer Bill Higher/(Lower) ($569) $500 Net Change in Customer Bill Higher/(Lower) ($69) BCH response Store 10 MWh in reservoir; offsets LLH purchase Increase generation during LLH or buy 10 MWh from market Change in BCH Energy Costs Higher/(Lower) ($500) $500 Net Change in BCH Energy Costs $0 Higher/(Lower) Net Change in Revenue Higher/(Lower) ($69) Net Change to BCH Income Higher/(Lower) ($69) In this scenario, the customer saves $69 on its bill as a result of shifting its load. BC Hydro's energy costs in each period again offset each other, as the $500 decrease in energy cost in the HLH is offset by the $500 increase in the LLH. Since transmission constraints during HLH do not allow for incremental sales to the market, the freed-up 10MW is stored in the reservoir in the HLH period and is used to offset the cost of the additional 10MW of load in the LLH period. There is a net decrease of $69 in the net change in BC Hydro's income, which is the source of transfer of benefit from all ratepayers to TOU customers. Scenario 3: Above Scenarios with Unlimited Transmission Access In this scenario, BC Hydro has transmission access which allows it to export or import without limit in both HLH and LLH periods, and BC Hydro can provide the TOU pricing in the non-winter months without transferring some of the benefits of storage from all ratepayers to TOU customers. The following Tables 4 and 5 summarise the net change in energy costs, the net change in revenue and the net change in income for the spring and summer/other periods under the scenario of unlimited transmission access:

163 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application Table 4 Scenario 3 - Example of Load Shift Impact in Spring Period Spring Period HLH s LLH s Customer Action Reduce load by 10 MWh Increase load by 10 MWh Change in Customer Bill Higher/(Lower) ($529) $365 Net Change in Customer Bill Higher/(Lower) ($164) BCH response Sell 10 MWh into market Buy 10 MWh from market during LLH Change in BCH Energy Costs Higher/(Lower) ($529) $365 Net Change in BCH Energy Costs $(164) Higher/(Lower) Net Change in Revenue Higher/(Lower) ($164) Net Change to BCH Income Higher/(Lower) $0 Table 5 Scenario 3 - Example of Load Shift Impact in Summer/Other Period Summer/Other HLH s LLH s Period Customer Action Reduce load by 10 MWh Increase load by 10 MWh Change in Customer Bill Higher/(Lower) ($569) $500 Net Change in Customer Bill Higher/(Lower) ($69) BCH response Sell 10 MWh in HLH period Buy 10 MWh in LLH period Change in BCH Energy Costs Higher/(Lower) ($569) $500 Net Change in BCH Energy Costs ($69) Higher/(Lower) Net Change in Revenue Higher/(Lower) ($69) Net Change to BCH Income Higher/(Lower) $0 Tables 4 and 5 show that with unlimited transmission access, there is no net change in income from offering the TOU prices in the non-winter months, and hence there is no transfer of some of the benefits of storage from all ratepayers to TOU subscribers under these scenarios. Page 4

164 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 17.0 Reference: Application, p Rate for Exempt Customers and Part 2, Tab D, RS 1827 Simon Fraser University ( SFU ) requested by letter dated August 4, 2004 (attached) that it be granted an exemption from the Stepped/Time-of-Use Rate on the same basis as the University of British Columbia. Page In BC Hydro s view can the Commission grant the exemption requested by SFU? If not, what prevents the Commission from granting such an exemption and what would be required for SFU to be granted such an exemption? RESPONSE: No. In BC Hydro's view the Commission cannot grant the exemption requested by SFU. Section 3(1) of the Heritage Special Direction No. HC2 to the Commission requires the Commission to ensure that in designing rates for BC Hydro's transmission rate customers, the rates are consistent with recommendations #8 to #15 in the Commission's report and recommendations to the Lieutenant Governor in Council dated October 17, Recommendation #14 states that: "That industrial and large commercial customers eligible for BC Hydro's Rate Schedule 1821 be required, at their election, to take service from BC Hydro from either the stepped rate or the time-ofuse rate. Rate Schedule 1821 would be terminated." Recommendation #15 sets out the exceptions to recommendation #14 as UBC, Fortis and the City of New Westminster. In other words, recommendation #14 applies to all industrial and large commercial customers eligible for RS 1821, including SFU, while recommendation #15 sets out the exceptions to recommendation #14, which do not include SFU. For these reasons it would be unlawful, in BC Hydro's view, for the Commission to grant the exemption sought by SFU, whatever its merits. Only the Lieutenant Governor in Council can grant relief from the mandatory nature of the stepped rate (and the TOU alternative).

165 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 17.0 Reference: Application, p Rate for Exempt Customers and Part 2, Tab D, RS 1827 Simon Fraser University ( SFU ) requested by letter dated August 4, 2004 (attached) that it be granted an exemption from the Stepped/Time-of-Use Rate on the same basis as the University of British Columbia. Page Aside from SFU, are there any other customers that could be eligible for RS 1827 besides the City of New Westminster and the University of British Columbia? RESPONSE: Please see BC Hydro s response to BCUC IR #

166 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 17.0 Reference: Application, p Rate for Exempt Customers and Part 2, Tab D, RS 1827 Simon Fraser University ( SFU ) requested by letter dated August 4, 2004 (attached) that it be granted an exemption from the Stepped/Time-of-Use Rate on the same basis as the University of British Columbia. Page Apart from the University of British Columbia, what is the number of commercial customers and the corresponding commercial sales that will be served under the mandatory stepped rate schedule? RESPONSE: Not including UBC, there are 18 commercial accounts that will be served under the mandatory stepped rate schedule. Please refer to BC Hydro s response to BCUC IR # for the actual total annual energy consumption in F2005 for commercial accounts including UBC.

167 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 18.0 Reference: Application, p. 1-33, and Part 2, Tab E BC Hydro proposes to limit the availability of RS 1880 to that of replacement of energy due to outages of the customer s on-site generation for the purpose of maintaining production at the customer s plant. Page The Period of Use for Standby and Maintenance Supply under Schedule 1880 is defined as A period of consecutive hours during which Electricity is taken under this Schedule which may extend into subsequent Billing Periods. The Period of Use is defined by the Customer when making the request to BC Hydro for Service under Schedule Is the Period of Use defined prior to the requirement or after the fact? If it is prior to the requirement, how much notice is required and why? RESPONSE: Pursuant to Special Condition #3 of the proposed tariff, the customer is required to notify BC Hydro within 30 minutes of taking energy under RS At that time, the customer also notifies BC Hydro of the start and end times of the Period of Use. Notification can be made within a 30-minute grace period after the customer starts taking RS 1880 service due to the unplanned nature of generation outages caused by equipment failures.

168 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 18.0 Reference: Application, p. 1-33, and Part 2, Tab E BC Hydro proposes to limit the availability of RS 1880 to that of replacement of energy due to outages of the customer s on-site generation for the purpose of maintaining production at the customer s plant. Page What will BC Hydro require from the customer as proof that the requested service under RS 1880 is strictly for the intended purpose? RESPONSE: Pursuant to Special Condition #6 of the proposed tariff, BC Hydro may request the installation of metering equipment, at the customer s expense, to monitor the output of the customer s generating units. In the past, customers have provided supporting data when requested by BC Hydro.

169 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 19.0 Reference: Application, p Standby/Maintenance Rate Section 6.3 states that any energy consumed within the Period of Use that is above the High kwh/hr should be deemed as energy charged under RS Page Please confirm that the service taken under the High kwh/hr will be taken at the customer s regular rate schedule (RS 1823, RS 1825, RS 1827 or RS 1852). If not, please explain why not. RESPONSE: Confirmed.

170 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 19.0 Reference: Application, p Standby/Maintenance Rate Section 6.3 states that any energy consumed within the Period of Use that is above the High kwh/hr should be deemed as energy charged under RS Page Please confirm that the energy consumed within the Period of Use that is above the High kwh/hr and that will be charged as RS 1880 will only apply to customers who are RS 1880 customers as well as RS 1823, RS 1825, RS 1827 or RS 1852? If not, please explain why not. RESPONSE: Confirmed.

171 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 19.0 Reference: Application, p Standby/Maintenance Rate Section 6.3 states that any energy consumed within the Period of Use that is above the High kwh/hr should be deemed as energy charged under RS Page Are there circumstances where the Mid-C price plus the 0.3 cents adder charged under RS 1880 will be less than the otherwise applicable rate under RS 1823, RS 1825, RS 1827 or RS 1852? If so, is that an appropriate outcome? Why or why not? RESPONSE: The marginal energy rates for RS 1827 and RS 1852 are based on embedded costs (i.e., the energy rate is flat). The marginal energy rates for RS 1823 and RS 1825 are based on BC Hydro s long-term energy acquisition cost. The Mid-C price reflects the daily electricity price of the wholesale electricity market in the Pacific Northwest. At any point in time, the daily Mid-C index price can be higher or lower than the customer s applicable base rate. The use of RS 1880 service is non-firm and of a relatively short-term nature (from a few hours to repair minor problems to a few weeks for maintenance work). As such, BC Hydro believes that the Dow Jones Daily Mid-C indices plus a 0.3 cent adder would be a reasonable and transparent proxy for its short-term opportunity cost for acquisition of the energy required to provide this short-term non-firm service. This pricing structure will prevent cost shifting to other customers from the provision of this non-firm service.

172 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 20.0 Reference: Application, p Standby/Maintenance Rate BC Hydro proposes to eliminate the demand and minimum charges on RS 1880, and that the price for the energy be based on the Mid-C indices plus an adder of 0.3 cents per kwh which is intended to be a proxy for BC Hydro s opportunity costs for the service. The Application also states that the 0.3 cents/kwh adder represents a contribution to the fixed costs of the system as well as additional administrative costs and any transmission costs associated with energy purchases in the wholesale market. Page Please provide additional detail about the determination of the 0.3 cents/kwh adder and the costs of the components (i.e., contribution to fixed costs, administrative costs, additional transmission costs) that make up the 0.3 cents. RESPONSE: The proposed 0.3 cents / kwh adder is BC Hydro s assessment of a reasonable contribution toward the recovery of fixed costs, additional administrative cost of the tariff, and any incremental transmission costs associated with energy purchases from the wholesale market, based on experience with similar tariffs in other jurisdictions.

173 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 20.0 Reference: Application, p Standby/Maintenance Rate BC Hydro proposes to eliminate the demand and minimum charges on RS 1880, and that the price for the energy be based on the Mid-C indices plus an adder of 0.3 cents per kwh which is intended to be a proxy for BC Hydro s opportunity costs for the service. The Application also states that the 0.3 cents/kwh adder represents a contribution to the fixed costs of the system as well as additional administrative costs and any transmission costs associated with energy purchases in the wholesale market. Page Does BC Hydro agree that this service effectively provides assurance to a customer that he will be able to meet 100% of his production requirements even in the event of an outage of the onsite generation? RESPONSE: No. The service provided under RS 1880 is non-firm. BC Hydro will endeavour to provide this service to the best of its ability. BC Hydro may curtail the provision of this service when it does not have sufficient energy or capacity. During such times, subject to supply availability, the customer may still be served up to its Maximum kv.a Demand and would be billed per its base rate.

174 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 20.0 Reference: Application, p Standby/Maintenance Rate BC Hydro proposes to eliminate the demand and minimum charges on RS 1880, and that the price for the energy be based on the Mid-C indices plus an adder of 0.3 cents per kwh which is intended to be a proxy for BC Hydro s opportunity costs for the service. The Application also states that the 0.3 cents/kwh adder represents a contribution to the fixed costs of the system as well as additional administrative costs and any transmission costs associated with energy purchases in the wholesale market. Page Does the proposed rate reflect the value of the service? RESPONSE: Value of service was not the driving factor in the design of this rate. BC Hydro cannot readily assess the value of service from the customer s perspective as it changes significantly from time to time given the market conditions of the customer s product. The value of service to the customer may or may not be higher than the rate charged for the service; but the customer will only take this service if its value is greater than the rate.

175 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 20.0 Reference: Application, p Standby/Maintenance Rate BC Hydro proposes to eliminate the demand and minimum charges on RS 1880, and that the price for the energy be based on the Mid-C indices plus an adder of 0.3 cents per kwh which is intended to be a proxy for BC Hydro s opportunity costs for the service. The Application also states that the 0.3 cents/kwh adder represents a contribution to the fixed costs of the system as well as additional administrative costs and any transmission costs associated with energy purchases in the wholesale market. Page How will the revenue from this rate be treated? (e.g. is the actual historical or forecast revenue from the rate used to offset the forecast costs to be recovered from RS 1823 and RS 1825?) RESPONSE: As in the past, the revenue from this rate remains with the transmission voltage rate class for revenue requirement and rate design purposes. For reference, the actual revenue collected from RS 1880 in F2005 was $2.8m and the total revenue collected from the transmission voltage class was $620m.

176 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, 2005 British Columbia Hydro and Power Authority Transmission Service Rate Application 21.0 Reference: Application, p Retail Access Page Please provide the definition of excess generation from Commission Order G that BC Hydro refers to in section 7.2. RESPONSE: Attached is a copy of Commission Order G In Order #1: The Commission directs B.C. Hydro to allow Rate Schedule 1821 customers with idle self-generation capability to sell excess self-generated electricity, provided the self-generating customers do not arbitrage between embedded cost utility service and market prices The Commission recognizes that considerable debate may ensue over whether a self-generator has met this principle, but the Commission expects B.C. Hydro to make every effort to agree on a customer baseline, based either on historical energy consumption of the customer or the historical output of the generator [emphasis added]

177 B R I T I S H C O L U M B IA U T I L I T I E S C O M M I S S I O N O R D E R N U M B E R G SIXTH FLOOR, 900 HOWE STREET, BOX 250 VANCOUVER, B.C. V6Z 2N3 CANADA web site: TELEPHONE: (604) BC TOLL FREE: FACSIMILE: (604) IN THE MATTER OF the Utilities Commission Act, R.S.B.C. 1996, Chapter 473 and British Columbia Hydro and Power Authority Obligation to Serve Rate Schedule 1821 Customers with Self-Generation Capability BEFORE: P. Ostergaard, Chair ) B.L. Clemenhagen, Commissioner ) April 5, 2001 K.L. Hall, Commissioner ) WHEREAS: O R D E R A. On February 23, 2001, British Columbia Hydro and Power Authority ( B.C. Hydro ) advised the Commission that some of B.C. Hydro s industrial customers served under Rate Schedule 1821 Transmission Service ( RS 1821 ) with self-generating capability wished to sell power they generate at market prices; and B. On February 23, 2001, B.C. Hydro requested that the Commission initiate a process, beginning with a Commission-led workshop, to explore B.C. Hydro s obligation to serve RS 1821 customers who wish to take their self-generation output to the market; and C. In a letter to the Commission dated February 27, 2001, Howe Sound Pulp and Paper ( HSP ), a RS 1821 customer with self-generating capability, responded to B.C. Hydro s February 23, 2001 letter, and requested that the Commission direct B.C. Hydro to permit and facilitate sales of incremental power from HSP; and D. B.C. Hydro, in a letter dated February 28, 2001, expressed concern that substantial fairness issues could arise between self-generators, and that HSP s proposal could create incentives that, in time, may lead to a reduction in employment and economic activity as customers with self-generation may seek to reduce production in order to provide electricity sales to the market; and E. By Order No. G-27-01, the Commission established a Workshop and subsequent written process to review the issues, with parties other than B.C. Hydro providing written comments by Monday, March 26, 2001, and B.C. Hydro providing reply comments by Monday, April 2, F. The Commission has reviewed the submissions from interested parties, the reply comments from B.C. Hydro and the Commission Staff Report, attached as Appendix A. The Commission concludes that it must act to meet the complementary objectives of creating conditions which allow B.C. Hydro to safeguard its own supply to British Columbians at lowest cost, assisting British Columbia industries with idle self-generation capability to capitalize on current market opportunities, and helping to mitigate the potential energy shortages in the Pacific Northwest and California. /2

178 B R I T I S H C O L U M B IA U T I L I T I E S C O M M I S S I O N O R D E R N U M B E R G NOW THEREFORE the Commission orders as follows: 1. The Commission directs B.C. Hydro to allow Rate Schedule 1821 customers with idle self-generation capability to sell excess self-generated electricity, provided the self-generating customers do not arbitrage between embedded cost utility service and market prices. This means that B.C. Hydro is not required to supply any increased embedded cost of service to a RS 1821 customer selling its self-generation output to market. The Commission recognizes that considerable debate may ensue over whether a self-generator has met this principle, but the Commission expects B.C. Hydro to make every effort to agree on a customer baseline, based either on the historical energy consumption of the customer or the historical output of the generator. In instances where the parties cannot agree on an appropriate baseline, an affidavit may be required from the self-generator that it will not adjust its consumption of electricity under Rate Schedule 1821 to take advantage of market sales from its self-generation. 2. Due to the unique circumstances that currently exist and without prejudice to the resolution of long-term rights of self-generators to take their generation to the market, this program is established until March 31, 2002 and may be continued after that date if conditions warrant. 3. The sales contracts are to be negotiated by the eligible self-generator and B.C. Hydro/Powerex or an independent marketer utilizing the Wholesale Transmission Services ( WTS ) tariff. The Commission will monitor the level of complaints with respect to pricing issues and may take action with respect to the availability of capacity under the WTS if it becomes required. 4. In an effort to assist both the self-generator sellers and B.C. Hydro/Powerex, the Commission directs that either party may request the views of the Commission staff on any unresolved issues before negotiations are terminated. Commission staff are to advise the Commission if there are any significant issues which the Commission must address to assist it in meeting the objectives of this program. The Commission believes that it would not be timely to debate the issue of filing of contracts within the context of establishing this short-term program of purchases and sales. 5. B.C. Hydro is directed to file a full report on the program with the Commission by March 1, DATED at the City of Vancouver, in the Province of British Columbia, this sixth day of April Attachment BY ORDER Original signed by: Peter Ostergaard Chair Order/BCH/RS1821 Self-Generation, Staff Report

179 APPENDIX A to Order No. G Page 1 of 5 BRITISH COLUMBIA HYDRO AND POWER AUTHORITY OBLIGATION TO SERVE RATE SCHEDULE 1821 CUSTOMERS WITH SELF-GENERATING CAPABILITY COMMISSION STAFF REPORT 1.0 BACKGROUND On February 23, 2001, the British Columbia Hydro and Power Authority ( B.C. Hydro ) wrote to the B.C. Utilities Commission (the Commission ) requesting that a workshop and public process be established to review issues pertaining to the obligation to serve those industrial customers with self-generating capability that have indicated a desire to sell the power they generate at market prices and take increased load requirements under Rate Schedule 1821 ( RS 1821 ). B.C. Hydro identified Section 39 of the Utilities Commission Act (the Act ) and Section 6(a) of the Electricity Supply Agreement which require B.C. Hydro to not unreasonably refuse the service requirements of customers. B.C. Hydro argued that these tariffs provisions were drafted under different circumstances and that the existing circumstances of high export electricity market prices and low embedded cost of service from B.C. Hydro required the Commission to review the issues pertaining to obligation to serve under the jurisdiction of the Act. B.C. Hydro believes that significant financial impacts could occur for all remaining Utility customers if self-generators were allowed to take their own generation to market and supplement their load requirements under RS On February 27, 2001, Howe Sound Pulp and Paper Limited ( HSP ) wrote to the Commission to identify that any self-generation which would be used by HSP for market sales would not require B.C. Hydro to deliver any additional electricity to HSP pursuant to RS High natural gas prices had idled some of the self-generation capacity, although this generation would be profitable at market prices for electricity available outside of British Columbia. HSP identified that the province, B.C. Hydro and the self-generator would all benefit from the incremental power sales. HSP urged the Commission to immediately direct B.C. Hydro to not only permit sales of incremental power, but to facilitate them. B.C. Hydro made a further submission on February 28, 2001 in which it accepted HSP s general proposition: that supply-constrained energy markets may benefit from initiatives aimed at encouraging idle capacity to come back on line. B.C. Hydro also accepted that the sale of truly idle generation into the market may not harm other ratepayers, as long as increased takes of RS 1821 electricity were not above normal historical levels, to produce the current idle capacity. That B.C. Hydro submission went on to identify the special circumstances surrounding the generation agreement with HSP and argued that it was inappropriate for HSP to seek market opportunities for its idle generation when it is contractually obligated to be using that generation now to meet its own energy needs.

180 APPENDIX A to Order No. G Page 2 of 5 The Commission responded to the expressed urgency to resolve these matters by issuing Order No. G on March 2, That Order established a public workshop for March 19, 2001 followed by submissions by interested parties no later than March 26, 2001 and reply comments from B.C. Hydro on April 2, The public workshop on March 19, 2001 was well attended and the discussion focused on alternative forms of self-generation which should be provided market access. Meeting Notes from the Workshop were distributed to assist participants in preparing their submissions. Submissions and reply were received from ten participants. 2.0 ISSUES 2.1 Term of Contracts At the March 19, 2001 Workshop, Commission staff suggested that parties might best focus on a short-term solution for this summer, because the broader issue of entitlement may require government involvement and would be better left for a future process. All parties generally agreed that the Commission should focus on the near-term circumstances in establishing a program which can assist utilities in the Pacific Northwest and California in alleviating expected shortages this summer; will assist B.C. Hydro in replenishing its reservoirs after a dry winter; and, can provide profits to self-generators. A number of intervenors suggested various terms for the contracts. B.C. Hydro also supported restricting sales agreements to the short term, although B.C. Hydro would prefer to define the short term as the period until a longer term solution is reached. B.C. Hydro suggested that sales conditions should remain in force until a further Commission determination arises from either: replacement with more permanent conditions; or energy market (including water) conditions rendering them redundant. 2.2 Eligibility The Workshop Meeting Notes identified seven scenarios of potential self-generation circumstances which might meet a definition of truly idle generating capacity. They are as follows: 1. Investments by a customer in conservation or demand-side management; 2. Cuts in production with and without employment impacts; 3. Shifting of planned maintenance from one period to another; 4. Connecting portable generators to the grid;

181 APPENDIX A to Order No. G Page 3 of 5 5. Increasing the utilization of existing generation, thereby reducing energy consumption under Rate Schedule 1821; 6. Improving generation efficiency; and 7. Purchasing energy from Independent Power Producers ( IPP ) and displacing Rate Schedule 1821 purchases. Interventions addressed this matter in differing ways. HSP submitted that generation should be defined as idle if it can be brought into service without increasing the customer s contract demand with B.C. Hydro. Mr. C. Johnson indicated his support for all of the scenarios outlined in the Meeting Notes and suggested that a sworn affidavit from the most senior person in charge of the industrial operation from which the power is generated could be provided as validation that the self-generator has not taken additional 1821 power in order to supply the incremental power to the grid. The Consumers' Association of Canada (B.C. Branch) et al. ( CAC (B.C.) et al. ) agreed with scenarios 1, 3, 4, 5, and 6 as described in the Workshop Meeting Notes. CAC (B.C.) et al. did not support encouraging companies to shut down production for the purpose of selling energy, particularly when there would be employment impacts. The CAC (B.C.) et al. opposed scenario 7 as it could be interpreted as supporting retail competition in B.C. Hydro s market. Willis Energy Services Ltd. proposed two eligibility conditions as follows: 1. B.C. Hydro should be permitted to purchase power from Rate Schedule 1821 customers with selfgenerated capacity under any conditions and prices provided that such purchase transactions on an individual basis can be demonstrated to not negatively affect other B.C. Hydro ratepayers or the B.C. Government shareholder. 2. Rate Schedule 1821 customers with self-generated capacity should be permitted to sell selfgenerated power to an independent marketer (using B.C. Hydro s WTS tariffs) or to Powerex under the following conditions: (a) (b) At any time when a Rate Schedule 1821 customer is selling self-generated power, the customer s power purchases from B.C. Hydro are less than the customer s Customer Baseline Load amount; and B.C. Hydro has the first right of refusal to purchase such power at 75 percent of the Mid-C index price applicable to the time of sale (high load hour price during high load hours, low load hour price during low load hours). B.C. Hydro responded with six principles which it would prefer as part of the Commission s determination. The first three principles address eligibility. The first principle is that self-generating customers should not be allowed to arbitrage between embedded cost utility service and market prices. This means that B.C. Hydro s obligation to serve must be defined so that B.C. Hydro is not required to supply any increased embedded cost service to a customer while that customer is selling its self-generation output to market. The second principle rejects the contract demand proposal of HSP and encourages the Commission to consider the energy usage of a self-generator in determining self-generation rights. The third principle identifies that

182 APPENDIX A to Order No. G Page 4 of 5 a customer baseline energy level could be established either through the use of historical load or historical self-generation, as may be appropriate. B.C. Hydro was concerned that reliance on the contract demand with B.C. Hydro could result in a circumstance where a customer could buy incremental embedded cost service from B.C. Hydro, while at the same time selling to market the output of its self-generator in instances where the customer had set its contract demand based on a relatively low load factor. B.C. Hydro concluded that incremental generation could be measured using a customer baseline approach as proposed in the Willis Energy Services Ltd. submission, based either on the customer s historic load or the actual use of the self-generator. The definition of incremental generation would need to be established, but it should be developed on the principle that the customer must receive no additional embedded cost energy while it is selling the output of its self-generation assets. B.C. Hydro agreed that scenarios 1, 4, 5, and 6 represented idle generation, but indicated that scenario 3 should not be considered since it results in no incremental generation. The representative of the Ministry of Employment and Investment indicated at the Workshop that the provincial government is primarily concerned that other ratepayers not be harmed as a result of the activities of Rate Schedule 1821 self-generating customers. All parties seem to accept that scenarios 1, 4, 5, and 6 should meet the test of eligibility. 2.3 Price Most parties supported the proposal that B.C. Hydro and the self-generators enter into bi-lateral contracts with no fixed mechanism for the sharing of benefits. The Joint Industry Electrical Steering Committee proposed that a high level of flexibility should be given to industrial customers and B.C. Hydro to attempt to achieve the solutions which are in the interests of the contracting parties and not prejudicial to other B.C. Hydro customers. B.C. Hydro agreed with many of the parties and articulated principle number four that: BC Hydro and its self-generating customers should negotiate the sharing of proceeds on a bilateral basis, with no fall back sharing mechanism or right-of-first-refusal. If fallbacks or rights-of-first-refusal are mandated, these must imply no obligation to purchase on the part of BC Hydro. BC Hydro does not believe that the Commission has the jurisdiction to direct BC Hydro to make particular energy purchases. B.C. Hydro supports the notion that contracts be negotiated freely between B.C. Hydro and the selfgenerators with the option that self-generators could access the WTS tariff and alternatively sell their generation to marketers or other parties.

183 APPENDIX A to Order No. G Page 5 of 5 Other participants were concerned that the availability of firm transmission capacity is constrained and this could result in self-generators being captive to the pricing options put forward by B.C. Hydro. However, the availability of non-firm transmission capacity may be sufficient to provide realistic pricing options to assist the parties in establishing fair prices for B.C. Hydro purchases from self-generators. While B.C. Hydro may only wish to purchase low load hour energy based on its unique circumstances, Powerex may be interested in purchasing power from self-generators which can be remarketed profitably to the export market based on the availability of the generation from the self-generator. 2.4 Filing of Contracts B.C. Hydro strongly opposes the filing of these contracts with the B.C. Utilities Commission. B.C. Hydro states that it does not file with the Commission its energy purchase agreements, and would strongly object to such filings, particularly if the Commission were to consider undertaking price adjustments. This is an unresolved issue as the past actions of B.C. Hydro have not necessarily met the requirements of Section 71 of the Utilities Commission Act. The nature of the relationship between B.C. Hydro and Powerex is also not fully resolved as it pertains to Section 71. The issue of filing of Energy Supply Contracts will likely be addressed as part of B.C. Hydro s revenue requirement review expected this fall.

184 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, Reference: Application, p Retail Access British Columbia Hydro and Power Authority Transmission Service Rate Application On page 1-40 BC Hydro states that it believes that the Energy Imbalance Price as proposed by BCTC s Rate Schedule 106 (Energy Imbalance Service) is a reasonable and transparent proxy of its short term opportunity cost, but that it considers the BCTC proposal to be complex. Page Please confirm that BC Hydro is referring to the amended RS 106 the Energy Imbalance Price submitted in the BCTC Open Access Transmission Tariff ( OATT ) and BC Hydro Interconnected Operations Services ( IOS ) hearing with the document titled BCTC and BC Hydro Proposal for Energy Imbalance Service ( BCTC/BC Hydro Imbalance Proposal ). RESPONSE: Confirmed. BC Hydro is referring to the attached Exhibit B1-23 from the BCTC OATT / BCH IOS Hearing.

185 "BritiSh CORPORATION'" Cameron Lusztig Director, Regulatory Affairs Phone: Fax: Columbia Transmission February 23, 2005 Mr. Robert J. Pellatt Commission Secretary British Columbia Utilities Commission P.O. Box Howe Street Vancouver, BC V6Z 2N3 Dear Mr. Pellatt:, ::;:~,I ! I I -23 1,. '''~.,._--,.,"--,-,~,.,.. ","! rj--,-%~i Re: British Columbia Transmission Corporation ("BCTC") Project No Order No. G Application for an Open Access Transmission Tariff and British Columbia Hydro and Power Authority ("BC Hydro") Interconnected Operations Services to BCTC BCTC writes to file the attached "BCTC and BC Hydro Proposal for Imbalance Energy Service" ("the Proposal"), and clean and black-lined versions of amended BCTC Rate Schedule 106 and amended Schedule 06 of Attachment L to the proposed BCTC OATT in this proceeding. The amendments to the Rate Schedules are described in the Proposal. BCTC understands that BC Hydro is making a complementary filing of the Proposal and an amended BC Hydro Rate Schedule BCTC draws the attention of the Commission to the complementary nature of the amendments contained in the Proposal and notes that the Proposal does not contemplate the approval of one utility's rate schedules without approval of the rate schedules of the other utility, and that changes to the rate schedules filed by one utility would require complementary changes to the rate schedule or rate schedules of the other utility. Yours truly, Original signed by: Cameron Lusztig Director, Regulatory Affairs CC. Registered Intervenors Richard Stout, Chief Regulatory Officer

186 Introduction BCTC and BC Hydro Proposal For Energy Imbalance Service BCTC and BC Hydro (the "Utilities") file this evidence with the Commission to support BCTC's proposed amendments to its OATT Application in respect of its energy imbalance Ancillary Service, and BC Hydro's proposed amendments to its 105 Application in respect of its energy service available to BCTC as 105. The purpose of the amendments proposed by the Utilities is to narrow the fundamental differences between them in respect of these issues that exist in the current evidence. These differences of view have been well canvassed in the written portions of this proceeding so far (see, for example, BC Hydro's response to BCUC IR 2 5.1), and are summarized in the first bullet of issue #11 in Exhibit A-23. The Utilities believe that the compromise proposal described in this evidence is efficient, fair to all system users, and strikes an appropriate balance between the interests of OATT customers and the financial implications for BC Hydro's ratepayers. Moreover, both Utilities believe that the proposal appropriately and cautiously introduces energy imbalance services in light of the BC Hydro/BCTC separation, and the developing market. Finally, the Utilities believe that the proposal will reduce substantially the issues surrounding energy imbalance service in the oral phase of the hearing. The Proposal The proposal described in this evidence is based on four simple principles: 1. Given the nature of BC Hydro's generation system, there is a spread between the value at which BC Hydro is willing to buy energy, and the value at which BC Hydro is willing to sell energy (the "buy-sell spread"). 2. For a moderate amount of Energy Imbalance provided to or taken from the system inadvertently and without systemic bias (Le., not predictably putting energy to the system or calling on energy from the system), BC Hydro is prepared to forego the economic value of the buy-sell spread. Instead, it can provide this service at some measure of the average value of the energy. BCTC does not believe that the Energy Imbalance Service will be significant in the near term; however, BC Hydro believes it is important to signal the principles related to the value of the energy to BC Hydro in anticipation of Energy Imbalance usage becoming significant in the future. 3. Where the Energy Imbalance deviations are large in aggregate, or where any individual customer is significantly and persistently providing an imbalance against its schedule (Le., an arbitraging behaviour), the

187 ratepayers of BC Hydro are effectively providing a free put or call option to system users. In such cases, ratepayers should be compensated with appropriate buy or sell prices rather than the average value. 4. Losses are different from Energy Imbalance because losses are predictably a call of energy on the system, and can be self-supplied easily. As such, provision of an option to buy loss compensation from BC Hydro would reflect a pure call option on the system. 5. BCTC will flow through to BC Hydro any excess revenues collected through its Energy Imbalance Service rate. In effect, this mechanism is an automatically clearing deferral account that will keep the balance in BCTC's Cost of Market Deferral Account from predictably increasing. Nature of the Amendments To effect these principles relative to the existing proposals of both BCTC and BC Hydro, several changes would be required to the proposed Rate Schedules of each utility. In particular: BC Hydro would modify its proposed energy service Rate Schedule 3011 as follows: 1. Schedule 3011 will retain its indexed buy and sell price as BC Hydro initially proposed. 2. However, as long as BCTC's net energy take on this service is less than or equal to 400 MWh in a calendar week, the hourly buy or sell price to BCTC will be equal to the average of BC Hydro's hourly buy and sell prices. 3. At such time or times as the imbalance exceeds 400 MWh in a calendar week, BC Hydro's hourly buy or sell price will apply. 4. BCTC will remit to BC Hydro all revenues in excess of amounts payable to BC Hydro pursuant to the Special Rate Provision in Schedule 3011 that are collected through its Energy Imbalance Service rate less any cost incurred through the purchase of IDS Energy Services from suppliers other than BC Hydro. BCTC would modify its proposed Energy Imbalance Rate Schedule 106 and Rate Schedule 06 to Attachment L of the OATT, as follows: 1. Each BCTC customer would see a single price for Energy Imbalance within a 4 MW hourly band (this was previously proposed to be 5MW, WhJJi9 in the current tariff it is 2MW).

188 2. Hourly deviations outside the band would be billed at the buy and sell prices in BC Hydro's Schedule In addition, a customer with a net Energy Imbalance of more than 20 MWh in any "Energy Imbalance Period" would pay either the buy or sell price (as appropriate) for the full amount of their imbalance within that period. The Energy Imbalance Periods will be defined as: HE 23-6, HE 7-14, and HE15-22 (intended to reflect overnight, morning peak, and afternoon peak). This provision would not apply to BC Clean generators below 50 MW, on the principle that they cannot control their generator output well enough to engage in the arbitrage behaviour that the 20 MWh limit is seeking to prevent. Consistent with the cautious approach to introduction of energy imbalance services mentioned above, and to allow for ongoing review of Energy Imbalance usage, BCTC will file quarterly reports with the Commission of the usage of BCTC's Ancillary Services rates. The reports will also be publicly available. There continue to be fundamental differences between BCTC and BC Hydro in respect of whether loss compensation service should be offered (see, for example, BC Hydro's response to BCUC IR and BCTC's response to BCH IR ). As a result, a loss compensation service proposal is not included here. Conclusion The Utilities believe that this proposal reflects a sensible approach to the energy imbalance issue, and an improvement over either of the IDS/AS proposals now before the Commission.

189 British Columbia Transmission Co o en Access Transmission Tariff oration Attachment L Transmission Rates PREAMBLE This attachment contains the transmission rates for services provided under the OATT. It includes rates charged to customers for the following services: 1) Network Integration Transmission Service 2) Long and Short-Firm Point-to-Point Transmission Service 3) Non-Firm Point-to-Point Transmission Service 4) Scheduling, System Control and Dispatch Service 5) Reactive Supply and Voltage Control from Generation Sources Services 6) Regulation and Frequency Response Service 7) Energy Imbalance 8) Operating Resource (OR) - Spinning Resource Service 9) Operating Resource (OR) - Supplemental Resource Services 10) Loss Compensation Transmission Service 11) Real Power Losses The rates in this attachment for Network Integration Transmission Services, Long and Short-Term Firm Point-to-Point Transmission and Non-Firm Point-to-Point Transmission Service are the combined rates of the Transmission Provider and the Transmission Owner.

190 British Columbia Transmission Co o en Access Transmission Tariff oration Pa e2 Terms and Conditions SCHEDULE 06 ENERGY IMBALANCE SERVICE Preamble: Energy Imbalance Service is provided when a difference occurs between the scheduled and the actual delivery of energy to a load located within a Control Area or to a Control Area boundary over a single hour. BCTC must offer this service when the transmission service is used to serve load within its Control Area or to export to neighbouring Control Areas. The Transmission Customer must either purchase this service from BCTC or make alternative comparable arrangements to satisfy its Energy Imbalance Service obligation. BCTC shall establish a deviation band of 4 MW to be applied hourly to any energy imbalance that occurs as a result of the Transmission Customer's scheduled transaction(s). The Transmission Customer will compensate BCTC for such service. Energy imbalances outside the deviation band will be subject to charges to be specified by BCTC. The charges for Energy Imbalance Service are set forth below. In this Rate Schedule, "BC Hydro's hourly buy price" means the hourly rate at which BC Hydro buys electricity pursuant to the Rate Section of BC Hydro Rate Schedule "BC Hydro's hourly sell price" means the hourly rate that BC Hydro charges for electricity pursuant to the Rate Section of BC Hydro Rate Schedule "Energy Imbalance Period" means one of three 08 hour periods defined as HE23-6, HE7-14 or HE Availability: Energy Imbalance: In support of Network Integration Transmission Services, Long and Short-Term Firm Point-to-Point Transmission Service, and Non- Firm Point-to-Point Transmission Service. Energy imbalances are calculated hourly based on deviations from scheduled generation and load. Positive imbalances occur when actual generation is greater than scheduled generation or when actual load is less than scheduled load. Negative imbalances occur when actual generation is less than scheduled generation or when actual load is greater than scheduled load. Energy imbalances less than or equal to 4 MW in any hour will be settled at BCTC's hourly Energy Imbalance Price. For Transmission Customers other than Transmission Customers (of less than 50 MW capacity) taking service under Schedule 11 of Attachment L to BCTC's OATT:

191 British Columbia Transmission Co o en Access Transmission Tariff oration Pa e 3 Terms and Conditions positive imbalances that exceed 4 MW in any hour, but which do not exceed 20 MWh over an Energy Imbalance Period, will be settled at BCTC's hourly Energy Imbalance Price for the amount of the imbalance that does not exceed 4 MW in any hour, and at BC Hydro's hourly buy price for the amount of the imbalance in any hour that exceeds that amount. positive imbalances that exceed 20 MWh over an Energy Imbalance Period will be settled at BC Hydro's hourly buy price for the entire amount of the imbalance over that Energy Imbalance Period. negative imbalances that exceed 4 MW in any hour, but which do not exceed 20 MWh over an Energy Imbalance Period, will be settled at BCTC's hourly Energy Imbalance Price for the amount of the imbalance that does not exceed 4 MW in any hour, and at BC Hydro's hourly sell price for the amount of the imbalance in any hour that exceeds that amount. negative imbalances that exceed 20 MWh over an Energy Imbalance Period will be settled at BC Hydro's hourly sell price for the entire amount of the imbalance over that Energy Imbalance Period. For Transmission Customers (of less than 50 MW capacity) taking service under Schedule 11 of Attachment L to BCTC's OATT: positive imbalances that exceed 4 MW in any hour will be settled at BCTC's hourly Energy Imbalance Price for the amount of the imbalance that does not exceed 4 MW in any hour and at BC Hydro's hourly buy price for the amount of the imbalance in any hour that exceeds that amount. negative imbalances that exceed 4 MW in any hour will be settled at BCTC's hourly Energy Imbalance Price for the amount of the imbalance that does not exceed 4 MW in any hour and at BC Hydro's hourly sell price for the amount of the imbalance in any hour that exceeds that amount. BCTC's Energy Imbalance Price will be calculated hourly based on the average ofbc Hydro's hourly buy price and BC Hydro's hourly sell price.

192 British Columbia Transmission Co en Access Transmission Tariff oration Pa e4 Terms and Conditions Taxes: Note: The Charges contained herein are exclusive of the Goods and Services Tax and Social Service Tax. A description of the methodology for discounting Energy Imbalance Services provided under this Schedule is contained in Section 3 of the British Columbia Transmission Corporation OAIT.

193 British Columbia Transmission Corporation Open Access Transmission Tariff Original Page X-XXX Effective: ENERGY IMBALANCE SERVICE SCHEDULE 106 Preamble: Energy Imbalance Service is provided when a difference occurs between the scheduled and the actual delivery of energy to a load located within a Control Area or to a Control Area boundary over a single hour. BCTC must offer this service when the transmission service is used to serve load within its Control Area or to export to neighbouring Control Areas. The Transmission Customer must either purchase this service from BCTC or make alternative comparable arrangements to satisfy its Energy Imbalance Service obligation. BCTC shall establish a deviation band of 4 MW to be applied hourly to any energy imbalance that occurs as a result of the Transmission Customer's scheduled transaction(s). The Transmission Customer will compensate BCTC for such service. Energy imbalances outside the deviation band will be subject to charges to be specified by BCTC. The charges for Energy Imbalance Service are set forth below. In this Rate Schedule, "BC Hydro's hourly buy price" means the hourly rate at which BC Hydro buys electricity pursuant to the Rate Section of BC Hydro Rate Schedule "BC Hydro's hourly sell price" means the hourly rate that BC Hydro charges for electricity pursuant to the Rate Section of BC Hydro Rate Schedule "Energy Imbalance Period" means one of three 08 hour periods defined as HE23-6, HE7-14 or HEI5-22. Availability: Energy Imbalance: In support of Network Integration Transmission Services, Long and Short-Term Firm Point-to-Point Transmission Service, and Non- Firm Point-to-Point Transmission Service. Energy imbalances are calculated hourly based on deviations from scheduled generation and load. Positive imbalances occur when actual generation is greater than scheduled generation or when actual load is less than scheduled load. Negative imbalances occur when actual generation is less than scheduled generation or when actual load is greater than scheduled load. Energy imbalances less than or equal to 4 MW in any hour will be settled at BCTC's hourly Energy Imbalance Price. For Transmission Customers other than Transmission Customers (of less than 50 MW capacity) taking service under Schedule II of

194 Attachment L to BCTC's OATT: British Columbia Transmission Corporation Open Access Transmission Tariff Original Page X-XXX Effective: positive imbalances that exceed 4 MW in any hour, but which do not exceed 20 MWh over an Energy Imbalance Period, will be settled at BCTC's hourly Energy Imbalance Price for the amount of the imbalance that does not exceed 4 MW in any hour, and at BC Hydro's hourly buy price for the amount of the imbalance in any hour that exceeds that amount. positive imbalances that exceed 20 MWh over an Energy Imbalance Period will be settled at BC Hydro's hourly buy price for the entire amount of the imbalance over that Energy Imbalance Period. negative imbalances that exceed 4 MW in any hour, but which do not exceed 20 MWh over an Energy Imbalance Period, will be settled at BCTC' s hourly Energy Imbalance Price for the amount of the imbalance that does not exceed 4 MW in any hour, and at BC Hydro's hourly sell price for the amount of the imbalance in any hour that exceeds that amount. negative imbalances that exceed 20 MWh over an Energy Imbalance Period will be settled at BC Hydro's hourly sell price for the entire amount of the imbalance over that Energy Imbalance Period. For Transmission Customers (of less than 50 MW capacity) taking service under Schedule 11 of Attachment L to BCTC's OATT: positive imbalances that exceed 4 MW in any hour will be settled at BCTC's hourly Energy Imbalance Price for the amount of the imbalance that does not exceed 4 MW in any hour and at BC Hydro's hourly buy price for the amount of the imbalance in any hour that exceeds that amount. negative imbalances that exceed 4 MW in any hour will be settled at BCTC's hourly Energy Imbalance Price for the amount of the imbalance that does not exceed 4 MW in any hour and at BC Hydro's hourly sell price for the amount of the imbalance in any hour that exceeds that amount. BCTC's Energy Imbalance Price will be calculated hourly based on the average of BC Hydro's hourly buy price and BC Hydro's hourly

195 British Columbia Transmission Corporation Open Access Transmission Tariff Original Page x-xxx Effective: sell price. Taxes: Note: The Charges contained herein are exclusive of the Goods and Services Tax and Social Service Tax. A description of the methodology for discounting Energy Imbalance Services provided under this Schedule is contained in Section 3 of the British Columbia Transmission Corporation OATT.

196 British Columbia Transmission Co o en Access Transmission Tariff oration Attachment L Transmission Rates PREAMBLE This attachment contains the transmission rates for services provided under the OATT. It includes rates charged to customers for the following services: 1) Network Integration Transmission Service 2) Long and Short-Finn Point-to-Point Transmission Service 3) Non-Finn Point-to-Point Transmission Service 4) Scheduling, System Control and Dispatch Service 5) Reactive Supply and Voltage Control from Generation Sources Services 6) Regulation and Frequency Response Service 7) Energy Imbalance 8) Operating Resource (OR) - Spinning Resource Service 9) Operating Resource (OR) - Supplemental Resource Services 10) Loss Compensation Transmission Serivce.end~ 11) Real Power Losses The rates in this attachment for Network Integration Transmission Services, Long and Short-Term Firm Point-to-Point Transmission and Non-Firm Point-to-Point Transmission Service are the combined rates of the Transmission Provider and the Transmission Owner.

197 British Columbia Transmission Co o en Access Transmission Tariff oration Page 2 Terms and Conditions SCHEDULE 06 ENERGY IMBALANCE SERVICE Preamble: Energy Imbalance Service is provided when a difference occurs between the scheduled and the actual delivery of energy to a load located within a Control Area or to a Control Area boundary over a single hour. BCTC must offer this service when the transmission service is used to serve load within its Control Area or to export to neighbouring Control Areas. The Transmission Customer must either purchase this service from BCTC or make alternative comparable arrangements to satisfy its Energy Imbalance Service obligation. BCTC shall establish a deviation band of +/ 1.5 percent (\',:ith a minimum of 5 MW) of the scheduled transaction4 MW to be applied hourly to any energy imbalance that occurs as a result of the Transmission Customer's scheduled transaction(s). The Transmission Customer will compensate BCTC for such service. Energy imbalances outside the deviation band will be subject to charges to be specified by BCTC. The charges for Energy Imbalance Service are set forth below...l11 t}lis ~a!e Sch~4ule.L~'BG RydrQ'shourlybuypnce"me.arl.s.JhehourlyrateatwhichBGHvdro 1Jl1y~~J~91D9ttymPll.l'.~11~tJQ J4~..~t~ ~~cjiq!:1ql)?qhy4rq R'!!~ S.ch.eduk_3Qll,_..~B.c_Hy.dm.:.s._hQ].u.:lY.. elld1ice~~..me.ans.jb_e_hojjllv r,;u~c-th.alj.3j;:=e-ydiq_~~h.ar.g~ljql"~ekc...tri.citx=pcyr.mid.tj9--1b~_ral~ 5.e..c..tiillLofBC Hydro Rate Schedule "Energy Imbalan~ Period" means one of three 08 hour periods defined as HE23-6. HE7-14 or HE Availability: Energy Imbalance: In support of Network Integration Transmission Services, Long and Short-Term Firm Point-to-Point Transmission Service, and Non- Firm Point-to-Point Transmission Service. Energy imbalances are calculated hourly based on deviations from scheduled generation and load. Positive imbalances occur when actual generation is greater than scheduled generation or when actual load is less than scheduled load. Negative imbalances occur when actual generation is less than scheduled generation or when actual load is greater than scheduled load. Energy imbalances less than 5 MW or 1.5% of scheduled 10adQI eq1lalto 4 MW in any hour will be settled at BCTC's hourly Energy Imbalance Price. Positive imbalan-ccsgreater than 5 MW and 1.5% ef-sefledu!ed load will be pai~o-ef

198 British Columbia Transmission Co o en Access Transmission Tariff oration Pa e 3 Terms and Conditions For Transmission Customers other than Transmission Customers (of less than 50 MW caoacitv) takinl! service under Schedule 11 of Attachment L to BCTC's OATT: ~itiye imbalances that exceed 4 MW in any hour. but which do not exceed 20 MWh oyer an Enef!!V Imbalance Period. will be sett~ BCTC's hourly Energy Imbalance Price for the amount of the imbalance that does not exceed 4 MW in any hour. and at BC Hydro's hourly buy price for the amount of the..imb.al.ancein-any hour that exge~l1hat amount. Negative imbalances greater than 5 MW and 1.5% of scheduled load "'Jillbe charged 125% of BCTC's positiye imbalances that exceed 20 MWh oyer an Energv.Imhalan~eriod will be settled at BC Hydro's hourly buy orice for the entire amount of the imbalance oyer that Enef!!y Imba.lanc_eJ~eriQd, ne~atiye imb~_es that excee~ MW in...july..hq!jf. but which do not exceed 20 MWh oyer an Enerl!V Imbalance Period. wui be settled at BCTC's hourly Energy. Irp.balaJ1c~ Price for tl:;1eamount of the imbalance that does not exceed 4 MWjnanyhQUI,_and_a.tllCHydro~shQudYselLp_ricefQLthe 1:1mQJJA!gtJh~_jg(tJ~l~~_~e. i.:~lanx._hqj!r th.?t ~:1(~~~dsth~t am.<mnt. ne~atiye imbalances that exceed 20 MWh oyer an Enen!V Imbalance Period will be settled at BC Hydro's hourly sell mice for the entire amount of the imbalance oyer that EneIgY ~Jp;l:>_~~c;s:J~_~!iQ4_, for Tran~mission CustomersJ.Qf less than 50 MW ca,p-acity)tak:in,g se.itke under Scheduk 11 of A1t~hIDent L to ocn::s DATI:...nositiye imbalances that.exceed 4 MW ijuilly~ur will be set1loo-.-m..j1cic~lhourlyenergy Imbalance Price_:fu.Lthe amount of the impalance that doe~ not exceed 4 MW ip any hour and at BC Hydro's hourly buy mice for the amount of the imbalance in any hour that exceeds that amount. neg:atiy~j2alanc.e..5-tha.lex~eda MW in any-001il... willbe settl~d at acre's hourly Enerl!V Imbala.nce Pric.e fur the amount of the imbalance that does not exceed 4 MW iujilly hour and at BC Hydro's hourly sell price for the amount of the imbalance in ailyhour that exceeds th'!t amount.

199 British Columbia Transmission Co o en Access Transmission Tariff oration BCTC's Energy Imbalance Price will be calculated hourly based on BCTC's actual cost of procuring the Energy Imbalance Up and Energy Imbalance Down Interconnected Operating Services from BC Hydro or other Qualified Suppliersthe average of BC Hydro's hourlv buy mice and BC Hvdro's hourly sell Drice. Taxes: Note: The Charges contained herein are exclusive of the Goods and Services Tax and Social Service Tax. A description of the methodology for discounting Energy Imbalance Services provided under this Schedule is contained in Section 3 of the British Columbia Transmission Corporation OATT.

200 ENERGY IMBALANCE SERVICE SCHEDULE 106 Preamble: Energy Imbalance Service is provided when a difference occurs between the scheduled and the actual delivery of energy to a load located within a Control Area or to a Control Area boundary over a single hour. BCTC must offer this service when the transmission service is used to serve load within its Control Area or to export to neighbouring Control Areas. The Transmission Customer must either purchase this service from BCTC or make alternative comparable arrangements to satisfy its Energy Imbalance Service obligation. BCTC shall establish a deviation band of +/ 1.5 percent (with a minimum of 5 MW) of the scheduled transaction1 MJY to be applied hourly to any energy imbalance that occurs as a result of the Transmission Customer's scheduled transaction(s). The Transmission Customer will compensate BCTC for such service. Energy imbalances outside the deviation band will be subject to charges to be specified by BCTC. The charges for Energy Imbalance Service are set forth below. In this Rate Schedule. "BC Hvdro's hourly buv mice" means the hourlv rate at which BC Hvdro buylelectricity pursuant to the Rate Section of BC Hydro Rate Schedule "BC Hvdro's hourly sell orice" means the hourlv ~..1~_thaLBC_IfydL~hM~JQL~l~tri~ity ID!f.sllanLt(LJh~LRat~ Section of BC Hvdro Rate Schedule "Enerl!v Imbalance Period" means one of three 08 hour oeriods defined as HE23-6. HEl::JA-illBEli:22 Availability: Energy Imbalance: In support of Network Integration Transmission Services, Long and Short-Term Firm Point-to-Point Transmission Service, and Non- Firm Point-to-Point Transmission Service. Energy imbalances are calculated hourly based on deviations from scheduled generation and load. Positive imbalances occur when actual generation is greater than scheduled generation or when actual load is less than scheduled load. Negative imbalances occur when actual generation is less than scheduled generation or when actual load is greater than scheduled load. Energy imbalances less than 5 1\1W or 1.5% of scheduled loadqr eaual to 4 MW in any hour will be settled at BCTC's hourly Energy Imbalance Price. Positive imbalances groater than 5 MW and 1.5% of scheduled load viill be paid 75% of for TransmissiQn Customers other than Transmission Customers (of l~::s_s than 50 MW capacity) taking service un<ler_s~heg!lte J 1 of Attachment..._._._ ~ L to BCTC's OATT:

201 yositive _ili!balances that _exceed 4 MW _in any ho~ but which do not exceed 20 MWh over an EnerQ:V Imbalance Period. will be settled at BCTC's hourly Energy Imbalance PriceJQrJhe amount of the imbalance that does not exceed 4 MWjuJlllY_hour. and at BC HY-drilho.urlv buy oricllir the (lq1ol,lt!t_qffuejmbal(liw~ jj:l (lj:ly_4qj.!l1:h lt(;:){9~(;:_@!h(l t amount. Negative imbalances greater than 5 MW and 1.5% ofsoheduled load will be charged 125% ofbetc's _ positive itp.b(ilances that exceed 20 MWh over an EnerlN Imbalance Period will be settled at BC Hvdro's hourly buy price for the entire amount of the imbalance over that EnerlN Imbalance PIDillL negative imbalances that exceed 4 MW in any hour. but yvhich do not exceed 20 MWh. over an En~rQ:V Imbalance period. will be se.ttled at HCTqs hqurly Energy Imbalance Price for the amount of the imbalance that does not exceed 4 MW in any hour. and at BC Hydro's hourly sell price for the amount of the imbalance in any hour t~xceeds that amq..u1lt ne~ative imbalances that exceed 20 MWh over an EnerlN Jmbalance Period will be settled at J?C Hvdro's hourly sell Rrice for the entire amount of the imbalance over that Energv Imhalan~ P.e_riQ_d., For Transmission Customers (of less than 50 MW caoacitv) takin~ s.ervic.e..jid.derschedule 11 of Attachment L to HerC's OA TT:. ~Dositiye imbalances that exceed 4 MW in any hour will be settled at J3CrC's hourly Energy Imbalance Price";"_for the!!-mq@.tpf ~ imb_alance t4at.does---i!qlexceed.4 M.W in al!y hour and at BC Hydro's hourly Quy-12-rke for the amoidltof the imbalance in any hour that exceeds that amount. ~ n~~a1iy~limbal!lncj~_ltbjll_.e~~-a MW.jJLallY bqjjl}yillb~ settled at HCTC's hourly Energv Imbalance Price for the amount of the imbalance that does not exceed 4 MW in any hour and at BC Hydro's hourly sell price for the amount of the imbal<.!!lcein. any hour that exceeds that amount. BCTC's Energy Imbalance Price will be calculated hourly based on HCTC's actual cost of procuring the Energy Imbalance Up and Energy Imbalance DO\vn Interconnected Operating Services from Be Hydro or other Qualified Suppliers.th_e_ID'.enlge_oLBLH)'drQ~s hmlrly buy orice and BC Hvdro's hourly sellp.rice. Taxes: The Charges contained herein are exclusive of the Goods and

202 Services Tax and Social Service Tax. Note: A description of the methodology for discounting Energy Imbalance Services provided under this Schedule is contained in Section 3 of the British Columbia Transmission Corporation OATT.

203 British Columbia Utilities Commission Information Request No Dated: April 4, 2005 BC Hydro Response issued April 22, Reference: Application, p Retail Access British Columbia Hydro and Power Authority Transmission Service Rate Application On page 1-40 BC Hydro states that it believes that the Energy Imbalance Price as proposed by BCTC s Rate Schedule 106 (Energy Imbalance Service) is a reasonable and transparent proxy of its short term opportunity cost, but that it considers the BCTC proposal to be complex. Page Please file a copy of the BCTC/BC Hydro Imbalance Proposal along with BC Hydro s February 23, 2005 transmittal letter and amended BC Hydro Rate Schedule 3011 (collectively filed in the BCTC OATT/BC Hydro IOS hearing as Exhibit B2-19). RESPONSE: Attached is Exhibit B2-19 of the BCTC OATT / BC Hydro IOS hearing.

204 BChydro m B2-19 Richard Stout Chief Regulatory Officer Phone: (604) Fax: (604) February 23,2005 Mr. Robert J. Pellatt Commission Secretary British Columbia Utilities Commission Sixth Floor Howe Street Vancouver, BC V6Z 2N3 Dear Mr. Pellatt: RE: British Columbia Transmission Corporation ("BCTC") Application for an Open Access Transmission Tariff ("OATT") and British Columbia Hydro and Power Authority ("BC Hydro") Application for Interconnected Operations Services ("IOS") to BCTC Project No BC Hydro writes further to the proceedings yesterday February 22, 2005 in this matter. As articulated by counsel for BC Hydro and BCTC, a potential resolution to most of the issues between their clients relating to the provision of energy service from BC Hydro to BCTC as IOS, and the provision of energy imbalance ancillary service from BCTC to third party users of the transmission system seems possible. In particular, BC Hydro and BCTC believe that they have come to a compromise proposal that both reflects and largely resolves their concerns. Therefore, BC Hydro files in this proceeding an amended Rate Schedule 301 1, Energy Service Available to BCTC as IOS, and a document entitled BCTC and BC Hydro Proposal for Energy Imbalance Service. The former is filed for the Commission's approval. The latter is joint evidence of BC Hydro and BCTC in support of BC Hydro's proposed amendments to its applied-for Schedule 301 1, and BCTC's proposed amendments to its applied-for Schedules 106 and Schedule 06 to Attachment L of the OATT. BC Hydro observes that the ability of the amended Schedule to address BC Hydro's concerns with energy imbalance service turns on the approval of BCTC's amended Schedules. Any changes to one would require complementary changes to the other. British Columbia Hydro and Power Authority, 333 Dunsmuir Street, Vancouver BC V6B 5R3 www. bchydro.com

205 -2- Enclosure (2) C. Cameron Lusztig British Columbia Transmission Corporation Registered Intervenors

206 Introduction BCTC and BC Hydro Proposal For Energy Imbalance Service BCTC and BC Hydro (the "Utilities") file this evidence with the Commission to support BCTC's proposed amendments to its O AT Application in respect of its energy imbalance Ancillary Service, and BC Hydro's proposed amendments to its IOS Application in respect of its energy service available to BCTC as 10s. The purpose of the amendments proposed by the Utilities is to narrow the fundamental differences between them in respect of these issues that exist in the current evidence. These differences of view have been well canvassed in the written portions of this proceeding so far (see, for example, BC Hydro's response to BCUC IR 2 5. l), and are summarized in the first bullet of issue #11 in Exhibit A-23. The Utilities believe that the compromise proposal described in this evidence is efficient, fair to all system users, and strikes an appropriate balance between the interests of OAT customers and the financial implications for BC Hydro's ratepayers. Moreover, both Utilities believe that the proposal appropriately and cautiously introduces energy imbalance services in light of the BC Hydro/BCTC separation, and the developing market. Finally, the Utilities believe that the proposal will reduce substantially the issues surrounding energy imbalance service in the oral phase of the hearing. The Proposal The proposal described in this evidence is based on four simple principles: 1. Given the nature of BC Hydro's generation system, there is a spread between the value at which BC Hydro is willing to buy energy, and the value at which BC Hydro is willing to sell energy (the "buy-sell spread"). 2. For a moderate amount of Energy Imbalance provided to or taken from the system inadvertently and without systemic bias (Le., not predictably putting energy to the system or calling on energy from the system), BC Hydro is prepared to forego the economic value of the buy-sell spread. Instead, it can provide this service at some measure of the average value of the energy. BCTC does not believe that the Energy Imbalance Service will be significant in the near term; however, BC Hydro believes it is important to signal the principles related to the value of the energy to BC Hydro in anticipation of Energy Imbalance usage becoming significant in the future. 3. Where the Energy imbalance deviations are large in aggregate, or where any individual customer is significantly and persistently providing an imbalance against its schedule (Le., an arbitraging behaviour), the

207 ratepayers of BC Hydro are effectively providing a free put or call option to system users. In such cases, ratepayers should be compensated with appropriate buy or sell prices rather than the average value. 4. Losses are different from Energy Imbalance because losses are predictably a call of energy on the system, and can be self-supplied easily. As such, provision of an option to buy loss compensation from BC Hydro would reflect a pure call option on the system. 5. BCTC will flow through to BC Hydro any excess revenues collected through its Energy Imbalance Service rate. In effect, this mechanism is an automatically clearing deferral account that will keep the balance in BCTC's Cost of Market Deferral Account from predictably increasing. Nature of the Amendments To effect these principles relative to the existing proposals of both BCTC and BC Hydro, several changes would be required to the proposed Rate Schedules of each utility. In particular: BC Hydro would modify its proposed energy service Rate Schedule as follows: 1. Schedule will retain its indexed buy and sell price as BC Hydro initially proposed. 2. However, as long as BCTC's net energy take on this service is less than or equal to 400 MWh in a calendar week, the hourly buy or sell price to BCTC will be equal to the average of BC Hydro's hourly buy and sell prices. 3. At such time or times as the imbalance exceeds 400 MWh in a calendar week, BC Hydro's hourly buy or sell price will apply. 4. BCTC will remit to BC Hydro all revenues in excess of amounts payable to BC Hydro pursuant to the Special Rate Provision in Schedule that are collected through its Energy Imbalance Service rate less any cost incurred through the purchase of IOS Energy Services from suppliers other than BC Hydro. BCTC would modify its proposed Energy Imbalance Rate Schedule 106 and Rate Schedule 06 to Attachment L of the OATT, as follows: 1. Each BCTC customer would see a single price for Energy Imbalance within a 4 MW hourly band (this was previously proposed to be 5MW, while in the current tariff it is 2MW).