LETTER NO. L-2-02 ROBERT J. PELLATT SIXTH FLOOR, 900 HOWE STREET, BOX 250 COMMISSION SECRETARY VANCOUVER, B.C. CANADA V6Z 2N3 Commission.Secretary@bcuc.com TELEPHONE: (604) 660-4700 web site: http://www.bcuc.com BC TOLL FREE: 1-800-663-1385 FACSIMILE: (604) 660-1102 Log No. 429 VIA FACSIMILE January 10, 2002 Mr. Ray Aldeguer Senior Vice-President Legal, Regulatory Affairs and General Counsel British Columbia Hydro and Power Authority 333 Dunsmuir Street Vancouver, B.C. V6B 5R3 Dear Mr. Aldeguer: Re: British Columbia Hydro and Power Authority General Service Time of Use (“TOU”) Pilot Program Evaluation Report Thank you for your December 31, 2001 report on the General Service TOU Pilot Program. The Commission recognizes the problems with the Pilot Program but would be pleased to work with B.C. Hydro to develop a permanent program, which can overcome the initial shortcomings of the Pilot Program.
Yours truly, Original signed by: Robert J. Pellatt MAG/cms
BCH/Cor/GenSrvc TOU Evaluation Rpt
BChydro Eli Ray Aldeguer Senior Vice-President Legal, Regulatory Affairs and General Counsel Phone: (604) 623-4513 Fax: (604) 623-4407
Mr. Robert J. Pellatt Commission Secretary British Columbia Utilities Commission P.O. Box 250 600-900 Howe Street Vancouver, BC V6Z 2N3 Dear Mr. Pellatt: RE: British Columbia Hydro and Power Authority General Service Time of Use (TOU) Pilot Program December Pursuant to Appendix A of the British “Commission”) Order No. G-l 17-99 and the direction enclosed is BC Hydro’s Time of Use Pilot Program Evaluation
Enclosure
British Columbia Hydro and Power Authority, wwwbchydro
THE POWER IS YOURS 31 December 2001
(“PC Hydro”) Evaluation Report 2001 Columbia Utilities Commission (the in Commission Order G-105-00, Report. Yours very truly, cl <s-’ Ray Aldeguer :_: Senior Vice-President Legal, Regulatory Affairs and General Counsel
333 Dunsmuir Street, Vancouver BC V6B SR3 corn
BC HYDRO TIME OF USE PILOT PROGRAM EVALUATION REPORT DECEMBER 2001
1. How many customers participated in the BC Hydro’s TOU program? 2. Which TOU option did customers pick? The following table shows that there were 505 accounts that subscribed to the BC Hydro’s TOU Program. The upper half of the table breaks down this total by the TOU option chosen and the lower half breaks down the total by regional location.’
Table 1 TOU Subscription
By Location Regional Location Lower Mainland Northern District Southern Interior Vancouver Island Total 3. What was the response to the TOU Pricing Hourly load data for 361 of the 505 customer sites, representing 61% of the total subscriber load, has been analyzed. This sub-sample load data from March 2000 to the end of February 2001, which covered winter and non- winter periods. The remaining 144 sites had incomplete winter months, and hence were not included in the analysis.
The load response was examined compares actual percentage of consumption baseline consumption by the same periods. The baseline ‘averaged’ customer baseline load (CBL) shape for each segment, derived from a sample of representative customer sites collected prior to the start of the TOU program. The following table indicates the segments where there was, on average, noticeable price response to winter TOU pricing. The table shows instances where the I Appendix A contains a table which shows the TOU subscription by SIC and building type.
No. of Accounts 163 137 89 116 505 Options? approximately of sites had hourly data for the year 2000 non-
from two perspectives. The first perspective by peak and non-peak periods with the consumption assumes an which has been Page 2
percentage winter peak period consumption was lower using actual load data compared to baseline load data under each of the four TOU pricing options. This provides evidence of load shifting or conservation during the peak periods in the winter months. Table 2 Comparison of Percentage Consumption by Period Using Actual and Baseline Load Data SIC Winter A Winter A Winter B Winter 6 winter c Winter C Winter D Winter D % Consumption by Period Baseline Load Actual Load Baseline Load Actual Load Baseline Load Actual Load Baseline Load Actual Load Agriculture Evenmg Peak 10033 4 733 10.033 2 311 Mornmg Peak 0.000 0.000 0.000 Off-Peak 89.988 95,268 89.968 97.689 Colleges Universities Evening Peak 13.098 12.308 Morning Peak 0.000 0.000 Off-Peak 88.903 87.693 Evening Peak 12.050 8.790 Morning Peak 0.000 o.cQo Off-Peak 87 950 91210 Hotels Motels Evening Peak 12.068 10.915 Morning Peak 0.000 0.000 Off-Peak 87.933 89.085 Large offices Evening Peak 14.410 12.862 14.410 6100 14.410 12.925 Morning Peak 0.000 0.000 0.000 0.000 17.283 13.567 Off-Peak 85.590 87.138 85.590 93 900 68 308 73.508 Mining Evening Peak 15.090 12.070 15.090 13.063 Morning Peak 0.000 0.000 0.000 0.000 Off-Peak 84.910 87.930 84.910 86.938 Petroleum Evening Peak 13.355 9.575 13.355 7.846 13.355 4.755 Morning Peak 0.000 0000 0.000 o.wo 9.248 4.679 Off-Peak 86.645 90.425 86 645 92.354 77.390 90.566 Evening Peak 14.775 10.315 Morning Peak 0.000 0 000 Off-Peak 85.225 89.685 Retail Non Fooa Evening Peak 13.748 12.423 Morning Peak 0.000 0.000 Off-Peak 86.253 07.578 Small Offices Evening Peak 12.893 10.076 Mwning Peak 14.093 10.409 Off-Peak 73.015 79.515 Small Residential Evening Peak 13.018 12.563 Mom~ng Peak 0.000 o.wo Off-Peak 86.983 87.438 storage Ewxng Peak 12.355 7 249 12.355 10.263 Morning Peak 0.000 0.000 12.690 12.680 Off-Peak 87.845 92.751 74.955 77.058 Transportation Evening Peak Morning Peak Off-Peak Wood Evening Peak 13.618 12.218 Morning Peak 0.000 0.000 The second perspective compares the percentage of total consumption by peak and non-peak periods for the winter, with similarly defined percentages for the non- winter months. This tests if load shifting took place in the winter months. It assumes that the winter and non-winter percentage breakdown of consumption by period are similar in the absence of the TOU program. The following table shows segments which, on average, had a lower percentage of peak consumption in the winter compared to the non-winter months. This provides evidence of price response during the winter months. Table 3 supports the evidence in Table 2, and also provides additional evidence of load response in some other segments. Overall, the winter and non-winter comparison provides a level of comfort in the method and assumptions originally used to establish the baseline load and to determine price response.
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Comparison of Percentage Using Actual Summer SIC Period Actual Actual % Consumption By Period Summer A Winter A Summer Agriculture Evening Peak a.99 4.73 Morning Peak 0.00 0.00 Of-Peak 91.01 95.27 Chemicals Evening Peak 13.22 12.19 Morning Peak 0.00 0.00 Off-Peak 86.78 87.82 Construction Evening Peak 12.44 a.79 Morning Peak 0.00 0.00 Off-Peak 87.56 91.21 Forestry Evening Peak 15.25 13.78 Morning Peak 0.00 0.00 Off-Peak 84.75 86.22 Hospitals Evening Peak 12.56 11.99 Morning Peak 0.00 0.00 Off-Peak 87.44 88.01 Hotels Motels Evening Peak Morning Peak Off-Peak Ice Arenas Evening Peak 13.01 12.93 Morning Peak 0.00 0.00 Off-Peak 86.99 87.07 Large Offices Evening Peak 13.49 I 2.86 Morning Peak 0.00 0.00 Off-Peak 86.51 87.14 Nursing Evening Peak Morning Peak Off-Peak Other Buildings Evening Peak Morning Peak Off-Peak Petroleum Evening Peak Morning Peak Off-Peak Restaurants Evening Peak lo.87 10.32 Morning Peak 0.00 0.00 Off-Peak 89.13 89.69 Retail Non Food Evening Peak Morning Peak Off-Peak Sewage Treatment Evening Peak 11.43 10.75 Morning Peak 0.00 0.00 Off-Peak 88.57 89.26 Small Offices Evening Peak 13.32 12.67 Morning Peak 0.00 0.00 Off-Peak 86.68 87.33 Storage Evening Peak 12.32 7.25 Morning Peak 0.00 0.00 Off-Peak 87.68 92.75 Finally, load response was estimated on an aggregate sample. The interval data was used to estimate the percentages consumption using actual TOU consumption, These percentages were applied to the consumption in usage was estimated, as shown in the following aggregate basis there was a relatively small reduction winter period (840,679 kWh, or 1.3% of CBL peak consumption). increase in usage in the non-peak winter period (6,414,564 peak winter consumption). The increase in non-winter of CBL non-winter consumption.
Table 3 Consumption by Period and Winter Load Data Actual Actual Actual Actual Actual Actual B Winter B Summer C Winter C Summer D Winter D 8.66 2.31 0.00 0.00 91.34 97.69 11.75 10.92 0.00 0.00 88.25 89.09 la.32 13.52 0.00 0.00 81.69 86.49 16.76 6.10 0.00 0.00 83.24 93.90 13.48 12.83 0.00 0.00 86.52 87.18 13.84 13.87 12.01 10.34 74.15 75.79 10.21 4.76 12.53 4.68 77.26 90.57 13.36 12.42 0.00 0.00 86.64 87.58 12.39 10.33 12.71 2.52 ii.81 5.19 0.00 0.00 14.12 2.92 13.65 5.85 87.61 89.67 73.17 94.56 74.54 88.96 15.37 14.60 11.19 10.08 14.75 15.18 11.75 10.41 69.88 70.23 77.06 79.52 basis for the whole TOU of peak and off-peak and using customer baseline consumption. of the total sample and the change table. The table shows that on an in evening peak usage in the There was also an kWh, or 1.5% of CBL non- load was 7,890,512 kWh, or .85% Page 4
Table 4 Load Response Relative to CBL (kWh) Season Actual Usage 12 Month 2000/2001 Peak Non-Peak Winter 62,593,525 427,951,339 63,434,204 Non-winter 937,745,981 Total 12 Month 62,593,525 1,365,697,320 63,434,204 4. What were the total customer benefits The following table summarizes consumption the TOU program and during the TOU program (which ran 19 months in total). For the TOU period, 12XX revenue and actual TOU revenue are reported. The 12XX revenue is the amount that would have been billed under 12XX based on actual TOU consumption. This data is used below to determine customer benefits of the TOU program.
Table 5 Consumption and Revenue Data For TOU Subscribers
Consumption Revenue 12XX kWh Revenue TOU CBL (12 month prior year) 1,414,826,448 $65,386,727 Actual 12 Month (March 2000 - 2001) 1,428,290,845 $66,043,659 $65,686,659 Actual - 7 Month Extension (April to October 2001) 281,665,750 !$12,638,003 $12,007,550 Actual Total - 19 Month 1,709,956,595 $78,681,662 $77,694,209 Customer benefits of the TOU Pilot Program are equal to bill savings plus consumer surplus. Bill savings are equal to the baseline bill minus the actual bill. The baseline bill is based on the CBL and the standard 12XX tariff. The actual bill is based on actual consumption and TOU prices. Consumer surplus is an economic term used to denote the added value that a customer receives when it responds to lower prices by increasing its overall electric consumption. It is difficult to get an estimate of the value of consumer surplus without having an estimate of each customer’s demand curve. Hence, the following will provide only an approximate estimate of total customer benefits. Page 5 - .--
CBL Usage Change in Usage Peak Non-Peak Peak Non-Peak 421,536,775 -840,679 6,414,564 929,855,469 7,890,512 1,351,392,244 -840,679 14,305,076 of the TOU Pilot Program? and revenue for the year prior to
The following defines total customer net benefit (CNB) as equal to bill saving (BS) plus consumer surplus (CS):*
CNB = BS+CS = Base Bill - TOU Bill + CS = (CBLxl2XX) - (Actual IoadxTOU price) + (A load x CSV) Where: A load = Actual load - CBL CSV = consumer surplus value Since actual load may exceed the CBL, it is possible that bill savings take on a negative value. This is reported in the first Column A in the table below. Also the value of consumer surplus requires an estimate of the customer’s willingness-to-pay (or demand curve).
One estimate of CNB assumes that customers’ consumer surplus value is equal to the 12XX rate:
CNB = (CBLxl2XX) - (Actual IoadxTOU price) + (A load x 12Xx) = (Actual load x 12xX) - (Actual IoadxTOU price) Another way to think of this is that the customer would be paying more under the base tariff assuming the higher actual load, and hence has a positive bill saving. This estimate is provided in Column B in the table below.
This estimate can be considered an upper bound of the customer net benefit, since it is likely that the consumer surplus value is valued lower than 12Xx. For example, simulated values from EPRl’s C-Value load response model indicated that the consumer surplus was valued at approximately 4.1 cents per kWh. The CNB using the simulated CSV value is reported for 12 months in Column C in the table below and is approximately 30% lower than the estimate in Column B. * The Appendix shows graphically the customer benefit from a reduction in price under a two-part rate.
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Customer (For Period March 2000 to 31 October Column A Bill Saving Non-Winter 2000 Winter 2000/2001 Sub-Total Annual (12 Months) -$299,932 Non-Winter 2001 (Program extension period) Total (19 Months) Without Bill Guarantee Bill Guarantee (defined on p. 8) Total Customer Benefit (With Bill Guarantee) Column A: Customer Bill Saving = Bill under 12xX assuming assuming actual consumption Column B: Customer Net Benefit = Bill under 12XX assuming assuming actual consumption Column C: Customer Net Benefit = Bill under 12XX assuming assuming actual consumption + A load x 4.1 cents/kWh Note: Taxes are excluded from these calculations. Assuming the upper bound estimate, program, which includes the bill guarantee, 5. What were the total BC Hydro Benefits BC Hydro benefits of the TOU Pilot Program revenues, as a result of the program, minus the change in costs.
The components of the benefit calculation for the first 12 months of the TOU program are provided in the following table. The financial impact of the extension period is examined beginning on page 17 of this report. The benefit from TOU pricing is given in row (6) in the table. The relatively low value reflects that the price response of the whole sample was not significant.3 The table also reports the costs that were incurred for various components of the program. 3 Note that this value is also approximate since the actual data was from billing data, which only covered roughly 12 months for each account. The baseline data was manually pro-rated so that it covered exactly 365 days for each account. Page 7
Table 6 Benefits 2001) Column B Column C Bill Saving Bill Saving plus Consumer Surplus plus Consumer Surplus (CSV=I2xx) (CSV=4.1 clkWh) $1,778,095 -$I ,421,095 $357,000 $252,108 $630,453 $987,453 $608,488 $1,595,941 CBL consumption - Bill under TOU rate actual consumption - Bill under TOU rate CBL consumption - Bill under TOU rate the total customer benefit for the TOU is $1,595,941. of the TOU Pilot Program? are equal to the change in
Table 7 BC Hydro Benefits (for 12 Month Period to end-March 2001) Net Benefit Component Method $ Estimate (1) Revenue based on TOU rate and actual WWhpeak * Ppead + C(kWhofipeak * Pavpead + consumption $65,686,659 BDelivery Charges +Program Charge (2) Revenue based on standard tariff and baseline consumption 8(12xx ENT&%is~nca~ + 12xx Demandh,tio& $659386,727 (3) Change in Domestic Revenue =(l)-(2) $299,932 (4) Increase in winter export sales revenue Assumes Forward Pricea minus change in winter off-peak costs AkWh peak(Nov-Feb) l $55 Per MWh - -$I 78,272 AkWhoff.peak(Nov-Fe*b )$ 35 Per MWh
(5) Increase in cost of serving change in non- Assumes Forward Priceb winter off-peak load $213,044 AkWh,,,od,fl,,,k l $27 per MWh (6) TOU Price Benefit (3)+(4)-(5) -$91,384 (7) Incremental costs of supporting TOU Fixed costs, collected through work orders program - Billing Administration $24,000 - Software for delivery charge calculation $8,000 - Marketing Communications $20,806 Sub-total $52,806 (8) Incremental capital costs for TOU metering Fixed costs based on capital expenditures and billing -500 meters at $500 each $250,000 -Meter installation $13,103 -Lodestar Billing license fee $125,000 -Billing Setup $29,500 Sub-Total $417,603 (9) Bill Guarantee (for total TOU Pilot) TOU bill - 12XX bill (where both bills are based on actual consumption, and where TOU bill is greater $608,488 than 12XX bill) (10) Quarterly Data Reports - Special Meter Reads and downloading of data $38,351 - Reporting Labour Cost $61,463 - Capital cost of handheld computer (10 @ $65,000 $6500) - Software for handheld (10 @ $2000) $20,000 - Sub-Total $184,814 Total Cost (11) TOU Capital and Operating Cost” (7)+(8) $470,409 (12) Total TOU Cost with Bill Guarantee and Data Reporting (9)+(10)+(11) $1,263,711 -N. otes a. This estimate assumes that reductions in winter peak energy consumption can be sold under a fixed- price open-volume contract at market rates. The average winter “sell price” of $55/MWh is based on the four-hour peak period being 30% higher than the Mid-C HLH average block. The winter energy cost of serving load in the off-peak period is $35. It is assumed to be equal to the weighted average Mid-C LLH price and the HLH price that TOU considers as off-peak periods. Hence, there is an assumed profit of $20 per MWh when a customer shifts load from the peak to off-peak period. This is based on the differential between the winter “sell price” and the winter off-peak energy cost. Note that the winter costs are based on forward market prices, which reflect market value of generation energy and capacity at the bulk transmission level. b. This estimate assumes that increases in non-winter off-peak energy consumption will be satisfied under a fixed-price open-volume contract at market rates when this product was priced. The price is the weighted average of market prices in non-winter off-peak TOU hours as forecast using the Mid-C forwards. The weighting reflects the general condition that transmission constraints limit HLH sales in the summer. c. Note that the full capital cost of equipment is reported. This ignores any salvage value of equipment or that the equipment could continue to have use beyond the TOU Pilot. Page 8
1. Should BC Hydro’s TOU be offered permanent TOU program? Can a summer Should BC Hydra’s TOU be offered permanently? BC Hydro’s TOU could be offered permanently re-priced to reflect changes in market conditions BC Hydro and for customers.
The results of the TOU pilot indicate that benefits were not positive in the first year. This was partially a result of not targeting the right customer segments, as more load response would have provided greater benefits. The program also offered a bill guarantee and data reporting service, which added significant costs to the program. On a going-forward basis, any permanent TOU program would have to review these features.
What is the purpose of a permanent TOU program? Time-differentiated commodity pricing is a good concept, economically efficient use of generating discouraging growth during peak periods. customers with marginal pricing signals so that customers have the opportunity their value of incremental consumption against the market value of electricity time. Customers that respond to time-differentiated cost of supply by shifting consumption seasonally or within the day. The following issues need to be considered l The product must be structured Because customers will only participate BC Hydro is subject to adverse-selection for all parties to achieve value is if products provide mutual benefits for BC Hydro and participants, for all different customer load characteristics. permanent rate would have to be a two part rate that includes a delivery charge derived from a customer’s baseline load.
l 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 to avoid the benefits being one-sided.
l 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. This approach is consistent with the recognition that products traded in the wholesale market are not the same as those provided to retail customers.
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permanently? What is the purpose of a program be accommodated? as an optional product if it can be and if there is mutual benefit for
since it promotes the assets and the transmission network by It is an effective mechanism to provide to gauge at that pricing can decrease their average in a permanent TOU program: and priced to reflect value for BC Hydro. in products from which they can benefit, risks. As a consequence, the only way To achieve this, a
It is important to recognize that the market for a TOU product will change over time. For example, the pilot TOU product encouraged expanded consumption during off peak periods and load shifting. A TOU based on the forward prices seen during the fall of 2000 would encourage reduced consumption and load shifting. As such, product structure and pricing mechanisms may have to be allowed to change as circumstances change.
Can a summer program be accommodated? A summer TOU program may be accommodated if there is value to BC Hydro from load shifting or conservation during the summer months. This value is limited by the fact that BC Hydro usually has available energy, which it exports, often to transmission limits, in the summer months. A summer TOU program can be accommodated to the extent that BC Hydro expects to have excess transmission capacity (e.g., as a result of low hydro conditions), and can benefit from additional conservation or load shifting in the summer months. These conditions prevailed in the summer of 2001, when BC Hydro primarily imported power due to unusually low reservoir levels.
2. Which aspects of the BC Hydro’s TOU program can be improved? Marketing and Subscription l More education of customers would encourage more involvement with price responsive load management and greater energy conservation. l Target marketing to customers with potential to conserve or load shift would improve response.
l The TOU load data provides valuable information on which customers and segments to target in any future program.
l Less paperwork will assist in the administrative process. Billing Staff was able to produce bills for all TOU subscribers with very little delay. In general, the process of using meter-reading sheets faxed to Billing worked well. One of the time consuming aspects of the billing was the processing of the meter exchanges as a requirement for the CIS and meter inventory system. The billing implementation could be improved by: l Streamlining the process of meter exchanges. l Eliminating data entry of meter reading sheets and moving to automated meter reading or processor technology. This would allow quicker access to customer data, which is also important for any data reporting to the customer. The collection of hourly data via automated meter reading would also allow more flexibility in changing future pricing periods and windows.
l Confirming incremental staffing required based on pilot experience. l Increasing communication with front line Customer Services staff. Page 10
Metering Meter Acquisition - there were various problems resulting in delays in the purchase of the meters:
l The original tender specified 3 element instead of 2 l/2 element TOU meters. l The vendor delayed delivery of the meters. l There was a miscommunication around the correct number of meters in the original order.
l The vendor informed BC Hydro that the majority of meters that were shipped were not Measurement Canada certified for varh billing. There is a need to find a better way to get the TOU meters into the field as soon as they are required in order to minimize the time that they are held in either the local stores or the central stores.
The metering process could be improved by the following: Development of more technical expertise and experience with the large-scale implementation of TOU metering. Need to involve BC Hydro Stores and Meter Shop earlier in the meter procurement and specification process. Need to source multiple vendors for time constrained programs. Need to include a non-performance clause for vendors that do not deliver within their quoted time frame. Need more responsive technical support for TOU metering issues.
Data Reporting Load profile information was provided quarterly to customers for free as part of the TOU program.
l The data reporting provided load profile information, of date. This reduced the value of the information unable to immediately relate behavioral reports.
l There were significant costs to providing the data reporting service. l BC Hydro should investigate offering data reporting as a separate for-fee service, with updated load profile data (e.g., week or day before) possibly provided via the web. There is some evidence that customers would pay for such a service.
Rate Design l Other pricing windows, such as a longer window during the afternoon (e.g., noon- 6pm or 3pm-9pm), might be considered in lieu of the split window. There is some evidence that some customers would prefer this design.
l There is opportunity to design an on-peak product to fit the August through January season, which would appeal to some customers.
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which were several months out to customers, since they were consumption changes to the load profile
3. Should BC Hydro’s TOU be expanded Optional time-differentiated products expanded to other groups, as long as there are mutual benefits to BC Hydro and to customers.
The value to BC Hydro and to customers will depend on the size of customer, prevailing market conditions, market prices and TOU price levels relative to tariff levels, and program costs.
The additional program administration any expansion of the TOU program. Given that the smaller commercial general service customers (less than 35kW) use relatively small amounts of electricity, may be difficult to justify the installation customer class.
4. How can the evaluation results be used to assist with the development of other programs?
The evaluation results can be used to identify which customer benefit most from time-differentiated pricing, the extent of customer segment, and also which price options and features are most attractive to customers.
The evaluation results are useful for the development of other load response products, such as real-time pricing. The results are also useful in the development of TOU options for other customer classes.
The evaluation results also provide lessons learned from implementing the time- of-use program. The lessons learned can easily be applied to implementing other optional pricing programs that may require the targeting of specific customer segments, more advanced metering and billing, and data reporting.
A post-program survey of TOU valuable information. The information would include the features that the subscribers liked. It would also include any new features that they would like to see in any future offering. BC Hydro intends to undertake such a survey.
to other customer groups? such as BC Hydro’s TOU could be
and metering costs must be covered in and industrial it and capital cost of TOU meters with this
segments can price response by
subscribers would also provide additional of the TOU program Page 12
1. How different were actual market derive TOU prices ? What was the impact on BC Hydro’s How different were actual market prices TOU prices?
This question relates to how well one year-ahead forward market prices reflected actual market prices. The following table compares the forward market prices used to derive the TOU prices with actual market prices.
Table 8 Comparison of Forward Forward Prices used to Derive 2000 Actual TOU Prices 6x16 6x6+24 7x24 6x16 Month HLH Price LLH Price HLH Price Jan 41.21 32.36 37.12 39.68 Feb 35.1 29.23 32.6 38.96 Mar 30.52 27.7 29.34 40.58 Apr 24.43 12.98 19.6 41.18 May 21.76 9.54 16.11 87.88 Jun 21 9.54 16.16 268.11 Jul 28.25 19.01 24.18 185.64 Aw 36.88 36.88 45.8 317.9 Sep 36.88 36.88 49.69 200.13 act 42.52 36.04 39.66 155.29 Nov 45.73 34.66 40.81 272.24 Dee 45.73 34.66 40.85 850.66 Forward prices that prevailed at the end of 1999 were significantly actual prices experienced in the year 2000 and the first half of 2001. The drivers behind the extreme market prices in the West supply/demand imbalance, high natural gas prices, drought conditions warmer than usual temperatures, and a large percentage maintenance and forced outages. The following table compares the TOU prices offered in the pilot program and the TOU prices based on 2000 actual market prices. The table shows that peak prices would be more than ten times higher and off-peak prices two to four times higher if actual market prices were used.
Table 9 Option TOU Price Based on Forwards Peak A 7 B 10 C 7
prices from the forward prices used to Revenue? from the forward prices used to derive
and Actual Market Prices Prices 2001 Actual Prices 6x8+24 7x24 6x16 6x8+24 7x24 LLH Price HLH Price LLH Price 33.48 36.81 435.69 343.81 393.21 36.82 38.05 419.77 381.69 417.99 38.95 39.90 430.81 375.17 407.47 26.98 34.24 487.5 418.15 453.59 58.24 74.82 412.78 264.93 347.6 92.52 193.97 107.51 80.14 95.95 123.53 156.92 165.1 250.53 134.37 170.91 127.44 142.41 204.09 241.95 489.63 675.97 lower than are now well documented and include in the Northwest, of generation out due to
TOU Price Based on 2000 Actual Off-Peak Peak Off-Peak 3.5 84 13.2 3.3 120 11.5 3.3 84 9.6 Page13
What was the impact on BC tiydro’s Revenue? Under the TOU pilot program, bill assurance ensures that the customer will pay no more under TOU than what it would pay if actual consumption were billed under 12xX. Hence, if the customer increased consumption in both peak and off-peak periods under TOU, there would not be a revenue difference using forward versus actual market prices, since the bill guarantee would be in effect. However, if the customer curtailed or shifted load in the winter, there would be a significant difference in revenue, because of the much higher peak prices if actual market prices were used.
However, TOU programs are priced using forward market prices, since the prices are fixed over a period of time. The volatility and price level change seen during the period of the TOU program demonstrates the need to account for risk in setting TOU prices. Real time pricing programs are based on actual spot market prices, which may change as of often as each hour.
2. How are the pricing periods and price levels derived from Mid-C impacted by transmission constraints? This question relates to whether the method used to derive the TOU pricing periods and price levels using the Mid-C forward prices is appropriate given the existence of transmission constraints. The peak and off-peak TOU prices have been derived from Mid-C forward prices. The peak pricing windows in the TOU Pilot program are available only in the winter period (November through February). Off-peak prices apply to all other months and to the off-peak periods of the winter months.
TOU prices should ideally reflect BC Hydro’s market price at the BClUS Border. However, the Mid-C is the closest wholesale hub which has active trading and which also has a forward market where prices can be obtained.
When there are no transmission constraints, of the BC/US Border price. If there are transmission BC Hydro is exporting, then the BCXJS Border price is expected Mid-C price. If there are transmission constraints importing, then the BC/US Border price is expected to be higher than the Mid-C price.
For the TOU Pilot program, it was assumed that there is relatively encouraging load shifting away from peak times during the non-winter peak TOU prices apply.4 It was assumed transmission constraints during the summer months of August and September, Mid-C prices are high for the HLH period. For these months, assumed for all hours. For other non-winter prices for each month were averaged to provide a flat price for each month. The TOU off-peak price was derived by the average of the non-winter 4 Similar assumptions were made for most of the non-winter Time-of-Use Pilot Program (December 1999).
opportunity cost, which is the market
the Mid-C index is a good measure constraints on the BC inter-tie, and to be lower than the on the BC inter-tie, and BC Hydro is
little value in months, and off- that BC Hydro is exporting and facing when the LLH values were months, the Mid-C forward HLH and LLH prices along with the winter months in the Transmission Service Page 14
Mid-C off-peak prices, where the prices were weighted month. The assumptions regarding transmission summer months of 2000, as BC Hydro had significant limits, during this period.
In the winter months, it was assumed that Mid-C is a good proxy of opportunity cost, since BC Hydro is likely to be generation these months. Peak TOU prices apply during the peak pricing windows in the winter to encourage conservation or load shifting from peak periods. Any marginal available by the TOU program in peak periods Reduced demand during peak periods may also reduce purchases system peaks when BC Hydro is generation transmission constraints proved accurate in the winter months including to February 2001. During these months, BC Hydro both exported and imported power, but seldom to transmission limit levels. Since there are few trades at the BC/US Border, the difference between the Mid- C price and BC/US Border price during a transmission The reason for accepting the Mid-C price as a reasonable that the unadjusted Mid-C price is simple and transparent.5 3. Should a permanent program be structured costs of peak period generation, generation and transmission prices available from export markets? pricing?
A permanent program which offers short and medium term contracts structured so that energy prices reflect BC Hydro’s forward market (or opportunity) to ensure benefits exist for non-participating customers to self select ensures that benefits will occur for participants. prices reflect the market value of generation BC Hydro operates its system to maximize market, subject to its domestic market obligation. TOU has been designed to send price signals in order that customers can make marginal expected market conditions.
If long-term contracts are developed, energy prices should reflect the long-run opportunity cost of energy. These prices would reflect the different long-run opportunity costs of serving load by time of day. The peak prices could also reflect the value in delaying transmission and distribution investments to the extent that the expected load reduction during peak periods delays the need for future system additions.
5 This is the argument used in supporting the Mid-C index for pricing Rate Schedule 1853, Transmission Service-Station Service for Maintenance and Blackstarts (effective January 2001). Rate Schedule 1853 is offered on a permanent basis, and for simplicity the Mid-C pricing does not reflect the transportation differential to the BC/US border or the presence of transmission constraints.
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by the number of hours in each constraints proved accurate in the exports, often to transmission
rather than transmission constrained in load made can be exported at Mid-C prices. required to meet constrained. The assumptions regarding November 2000 constraint cannot be determined. proxy for a BC market price is to reflect BC Hydro’s own transmission and distribution or should reflect peak revenue opportunities What would be the difference in peak
has to be costs customers and BC Hydro. The ability of The energy energy and capacity. value in the wholesale electricity consumption decisions in light of
4. How will a permanent program impact the appropriate collection from the commercial class and TOU commercial The TOU rate is a two-part rate. The first part collects requirement and reflects the customers’ embedded cost use of the system. The second part is based on the TOU rate and, assuming provide benefits to BC Hydro when compared to the standard embedded costs should be allocated in a manner consistent general-service rates. The expected benefit, however, customers. From a practical perspective, however, this benefit would be immaterial and in BC Hydro’s view it would not be worthwhile effort to capture the effect of allocating the benefits over all customers.
5. Should a permanent program be based on a revenue by customer or by class of customer? BC Hydro’s current assumption is that a permanent as an optional rate. Given the optional nature of the rate, the program would be based on revenue neutral initial pricing by customer characteristics do not change. The rate would customer class basis.
1. Did BC Hydro adequately bill and meter customers on the Pilot? Billing Yes, customers were adequately billed on the Pilot program. BC Hydro chose not to modify its legacy billing system to accommodate the TOU pricing. Instead it used a new stand-alone billing system that was being used for its largest commercial and industrial accounts. The billing service team met all targets set for them and was able to have all bills issued on time and error free.
Metering Yes, once meters were installed, customers were adequately metered. However, the meter supply process was a challenge in that there were delays and certification problems with the supplier. When the meters did arrive there were problems with the receipt of the TOU meters into our warehousing system because they did not conform to the energy and demand meter format of most of our meters. Once the TOU meters were issued into the field, there was no timely way of finding out whether or not they had been installed. A hard copy work order had to be returned to the head office to determine that installation had occurred. As a result, the meter acquisition and installation process took longer than expected.
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revenue requirement customers? the historic revenue the rate is designed correctly, should rate. Ideally, the historic with other embedded cost should be allocated across all to complicate an allocation study in an
neutral initial pricing TOU rate would be offered when the customer’s consumption thus also be revenue neutral on a
Since the spring and summer months did not have time-differentiated pricing, the delays in meter installation did not affect customer billing in this period. However, the delays resulted in the extension of the program by seven months so that BC Hydro could keep its commitment to provide 12 months of hourly consumption data to all TOU subscribers.
This section examines the financial impact of the seven month program extension (31 March 2001 to 31 October 2001) of the TOU Pilot program. BC Hydro requested the extension, as it had committed to providing customers who enrolled in the TOU Pilot program with 12 months of hourly consumption and load profile data. Although, 505 customers were transferred to TOU rate schedule 1267 prior to 31 March 2000, there were delays in the installation of the time-of-use meters. Hence, not all customers had received 12 months of load profile data by the end of March 2001. Customers were therefore given the option of staying on the program till the end of October 2001. There were 181 accounts that were on TOU during some portion of the extension period. The financial impact is reported in the table below. It assumes that the baseline consumption is the same as actual consumption. Hence the net financial impact to BC Hydro is the change in revenue plus the additional billing and reporting cost.
Table 10 Financial Impact of TOU Program (April 2001 to October (1) Revenue based on C(kWh,,,k * P,,&) + C(kWhoffpeak* P&peak) TOU rate and actual consumption
(2) Revenue based on - C(12xx Energy + 12xx Demand) standard tariff and - Assumes baseline consumption equals actual baseline consumption $12,638,003 consumption, since baseline has not been established for the extension period (3) Change in Domestic Revenue =(l)-(2) -$630,453 (4) Additional Billing and Reporting Cost $13,137 Page 17
Extension 2001) Method $ Estimate + CDelivery Charges $12,007,550
Appendix Table A.1 TOU Subscription by SIC and Building kWh Percentage Agriculture 22,750,102 Chemicals 4,538,880 Colleges Universities 87,232,667 Construction 5,069,699 Food and Beverages 49,779,040 Forestry 12,227,904 Hospitals 62,514,350 Hotels Motels 55,497,347 Ice Arenas 49,650,179 Large Offices 176,630,338 Mining 17,420,710 Nursing 2,208,445 Other Buildings 33,530,644 Other Manufacturing 113,396,633 News Press 10,540,800 Petroleum 29,751,114 Pulp and Paper 34,008,OOO Restaurants 1,618,040 Retail Food 9,758,046 Retail Non Food 114,556,189 Schools 44,651,687 Sewage Treatment 45,206,905 Small Offices 40,901,342 Small Residential 946,114 Storage 52,807,500 Transportation 8,056,625 Wood 329,577,148 1.414.826.448 100.0%
A Type No. Sites Percentage Average kWh 1.6% 14 2.8% 1,625,007 0.3% 1 0.2% 4,538,880 6.2% 21 4.2% 4,153,937 0.4% 3 0.6% 1,689,900 3.5% 7 1.4% 7,111,291 0.9% 3 0.6% 4,075,968 4.4% 27 5.3% 2,315,346 3.9% 24 4.8% 2,312,389 3.5% 29 5.7% 1,712,075 12.5% 39 7.7% 4,528,983 1.2% 9 1.8% 1,935,634 0.2% 1 0.2% 2,208,445 2.4% 22 4.4% 1,524,120 8.0% 36 7.1% 3,149,906 0.7% 1 0.2% 10,540,800 2.1% 14 2.8% 2,125,080 2.4% 1 0.2% 34,008,OOO 0.1% 3 0.6% 539,347 0.7% 11 2.2% 887,095 8.1% 8 1.6% 14,319,524 3.2% 77 15.2% 579,892 3.2% 51 10.1% 886,410 2.9% 34 6.7% 1,202,981 0.1% 1 0.2% 946,114 3.7% 13 2.6% 4,062,115 0.6% 6 1.2% 1,342,771 23.3% 49 9.7% 6,726,064 505 100.0% Page 18 --- --.-~_____
The following chart shows the customer benefit from a reduction in price under a two-part rate. The TOU rate is a two-part rate, where the customer pays the base bill if it does not change its consumption profile. $/kVVh
Base Bill The Base Bill is equal to the customer tariff:
Base Bill = A+B Under a two-part rate, the customer the area A.
DC = Base Bill - QoxPl = P,,x Qo- QoxP, = A+B-B =A
The bill under the two-part TOU rate is: TOU Bill=DC+Energy Charge =A+B+C
The customer benefit from the TOU rate is: Customer Benefit = (Bill Saving) + (Consumer Surplus) = -C+(C+D) =D
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QO - QI kVVh baseline load billed under the standard
pays a fixed or delivery charge (DC) equal to