BChgdro FOR GEt\JE lor\js B-1 Joanna Sofield Chief Regulatory Officer Phone: (0) -0 Fax: (0) -0 bchydroregulatorygroup@bchydro.com September 0,009 Ms. Erica M. Hamilton Commission Secretary British Columbia Utilities Commission Sixth Floor - 900 Howe Street Vancouver, BC VZ N Dear Ms. Hamilton: RE: British Columbia Utilities Commission (BCUC) British Columbia Hydro and Power Authority (BC Hydro) Three-Year Report BCUC Order No. G-10-09 BC Hydro is writing to the BCUC in compliance with BCUC Order No. G-10-09 and accordingly attaches its Three-Year Summary Report (the Report) for the three years commencing April 1, 00, to March 1, 009 (fiscal years F00, F008 and F009). In the Report BC Hydro has provided its responses to the eight questions found in Appendix A of BCUC Order No. G-10-09 regarding the Terms of Reference for the Transmission Service Evaluation Report that the BCUC is required to provide to Government by December 1, 009. It is BC Hydro's view that the Report, in combination with the three Transmission Service Rate Reports for each of F00, F008 and F009 (the latter filed concurrently with the Report) provides a common, factual basis for an informed understanding of the transmission customer events that have (or have not) occurred during the first three years of BC Hydro's Rate Schedule 18 - Transmission Services - Stepped Rate (RS 18). As discussed in detail in the Report, BC Hydro is of the view that RS 18 has facilitated energy conservation by BC Hydro's transmission customers, although there are challenges in quantifying the entire amount of demand side management (DSM) response from customers. BC Hydro remains of the view that there is no clear and objective way to discretely separate the impact of rate structure, Power Smart enabling activities and other customer decision-making factors for each DSM project. BC Hydro concludes in the Report that costs have been shifted from the transmission service class to other customer classes and to the shareholder as a result of the stepped rate. BC Hydro also concludes that it is important to take a longer-term view of cost-shifting impacts caused by changes (increases and decreases) in RS 18 energy sales and revenues. British Columbia Hydro and Power Authority, Dunsmuir Street, Vancouver BC VB R www.bchydro.com
September 0, 009 Ms. Erica M. Hamilton Commission Secretary British Columbia Utilities Commission Three-Year Report BCUC Order No. G-10-09 BChydro Pageof With regard to retail access and RS 18 time-of-use rate options, BC Hydro reports that RS 18 has not achieved one of its objectives of facilitating retail access by transmission service customers and no customer has used RS 18. The Report provides a discussion of the possible reasons that have resulted in no customers exercising the option to use retail access or RS 18. Finally, BC Hydro provides its views on whether or not RS 18, as currently structured, contains barriers or obstacles to further conservation, load reduction or preservation and optimization of self-generation by BC Hydro's transmission customers and whether there are elements of RS 18 that could lead to less than optimal results. It is BC Hydro's view that the purpose of this proceeding is to provide information and submissions to the BCUC to assist it with preparing its Transmission Service Evaluation Report to Government. The purpose is not to redesign or otherwise change the transmission service rates. As directed by BCUC Order No. G-10-09 BC Hydro has provided a copy of the Report to all intervenors in the TSR Re-pricing Application proceeding and to all of its transmission service customers. For further information, please contact Fred James at 0-1. Yours sincerely, Joanna Sofield Chief Regulatory Officer Enclosure c. BCUC Project No. 980 (BC Hydro Re-pricing Application) Registered Intervenor Distribution List. RS 18 Customers
Table of Contents 1 Introduction...1 Background... Responses to Terms of Reference Questions....1 Question 1: Has the transmission services stepped rate (RS 18) facilitated conservation by BC Hydro s transmission customers?....1.1 Introduction....1. Customer Reported DSM...8.1. Unreported DSM...11. Question : Has the transmission services stepped rate (RS 18) facilitated retail access by BC Hydro s transmission customers?...1. Question. If no retail access has occurred, why not? Are there features of the transmission services stepped rate that detract from the attractiveness of retail access?...1..1 If no retail access has occurred, why not?...1.. Are there features of the transmission services stepped rate that detract from the attractiveness of retail access?...19. Question : Has the transmission services stepped rate (RS 18) caused costs to shift to other BC Hydro customer classes or to the shareholder?.....1 Forecast Cost Shift..... After-the-fact Cost Shift.... Question : If there is cost shifting taking place, what are the reasons?...9..1 Treatment of Forecast Variances...9.. Treatment of After-the-fact Variances...1.. Longer-Term View...1. Question : Why have no customers used the Time of Use (TOU) Rate (RS 18)?.....1 Background..... RS 18 Design..... Reasons Why No Customers Have Used RS 18.... Question : Does the transmission services stepped rate (RS 18), as currently structured, contain barriers or obstacles to further conservation, load reduction, or preservation and optimization of self-generation by BC Hydro s transmission customers?.....1 Obstacles to Further Energy Efficiency and Conservation..... Obstacles to Preservation and Optimization of Customer Self-generation... i
.8 Question 8: Are there elements of the RS 18 rate structure that could lead to less than optimal results in the future? If so, what are those elements and what are the less than optimal results?...9.8.1 DSM Potential of the Rate Structure is Capped...9.8. Tier 1 Rate...9.8. CBL Preservation...0.8. Market Conditions...1 List of Figures Figure 1 Illustration of Delivery of Retail Access Energy... 1 Figure Illustration of Energy Imbalance RS 1890... 18 List of Tables Table 1 Total DSM Summary (F00 F009)... Table Customer Reported DSM Summary (F00 F009)... 9 Table Estimate of Unreported DSM (F00 to F009)... 1 Table Subjective Estimate of Unreported DSM... 1 Table RS 1890 Imbalance Rates for 009 (based on RS 18)... 1 Table Price Comparisons (current Canadian dollars per MWh)... 1 Table Forecast Revenue Variance Impact (F00 F009)... Table 8 Actual Versus Forecast RS 18 Gross Margin Variance... Table 9 RS 18 Energy Rates... Appendices Appendix A Appendix B Appendix C Government Information Bulletin - BCUC Report and Recommendations on Inquiry Into A Heritage Contract BC Hydro Power Smart Impact Evaluation of the E Analysis of Unreported Demand-Side-Management of BC Hydro s ii
1 Introduction This is BC Hydro s (TSR) Three-Year Summary Report (the Report) for the three year period commencing April 1, 00, and ending March 1, 009 (F00 to F009). The Report is being filed to comply with the TSR Application Negotiated Settlement Agreement (TSR NSA) 1 and the Terms of Reference for the Evaluation (TSR Evaluation). 8 9 10 By Order No. G-10-09 issued on February 19, 009, the British Columbia Utilities Commission (BCUC) approved Terms of Reference for the TSR Evaluation comprising the following eight questions: 11 1 1. Has the transmission services stepped rate (RS 18) facilitated conservation by BC Hydro s transmission customers? 1 1. Has the transmission services stepped rate (RS 18) facilitated retail access by BC Hydro s transmission customers? 1 1. If no retail access has occurred, why not? Are there features of the transmission services stepped rate that detract from the attractiveness of retail access? 1 18. Has the transmission services stepped rate (RS 18) caused costs to shift to other customer classes or to the shareholder (provincial Government)? 19. If there is cost-shifting taking place, what are the reasons? 0. Why have no customers used the Time of Use Rate (RS 18)? 1 Approved by BCUC Order No. G-9-0, August 9, 00. 1
. Does the transmission services stepped rate (RS 18), as currently structured, contain barriers or obstacles to further conservation, load reduction, or preservation and optimization of self-generation by BC Hydro s transmission customers? 8. Are there elements of the rate structure (RS 18) that could lead to less-than-optimal results in the future? If so, what are those elements, and what are the less-than-optimal results. 8 9 10 11 1 The Report provides BC Hydro s responses to each of the eight questions and has been prepared to assist the BCUC and stakeholder review. BC Hydro s responses incorporate a consolidated view of the conservation and financial results reported in each of the TSR Annual Reports for the three years under review; a preliminary estimate of the total conservation response to the stepped rate structure; and TSR customer perspectives obtained from executive interviews, individual customer meetings, stakeholder meetings and rate workshops. 1 1 1 1 1 18 19 It is BC Hydro s view that the Report, in combination with the TSR Annual Reports (F00, F008, F009) provides the basis for an informed understanding of transmission customer s response to the new transmission service rates during the first three years that they have been in place. It is also BC Hydro s view that the purpose of this proceeding is to provide information and submissions to the BCUC to assist it with preparing its TSR Evaluation Report to Government which is due on December 1, 009. The purpose is not, at this time, to redesign or otherwise change the TSR rate design nor the terms and conditions. 0 1 Background The BC Government s 00 Energy Plan, Energy for Our Future: a Plan for B.C. (00 Energy Plan), mandated that the BCUC conduct an inquiry to develop and make recommendations to Government regarding a stepped rate structure for BC Hydro s large commercial and industrial customers. In its Report and Recommendations dated October 1, 00 the BCUC provided nine recommendations to Government related to stepped rates. Customer executive interviews were conducted by an independent research firm (Innovologie LLC). The firm is finalizing its report and BC Hydro expects to file the report with the BCUC prior to October 1, 009 (the date for information requests from BCUC staff and intervenors).
The Government responded to the BCUC s Report and Recommendations in an information bulletin dated November 8, 00, a copy of which is attached as Appendix A. The Government also responded with Heritage Special Direction No. HC to the BCUC (HC) enacted pursuant to the BC Hydro Public Power Legacy and Heritage Contract Act. HC includes the following directions to the BCUC with respect to rates for TSR customers: 8 9 10 11 1 1 1 1 1 1 18 19 0 1 Consideration in designing rates for transmission rate customers. (1) In designing rates for the authority's transmission rate customers, the BCUC must ensure that those rates are consistent with recommendations number 8 to number 1 inclusive in the BCUC's report and recommendations to the Lieutenant Governor in Council dated October 1, 00. () Without limiting subsection (1), the BCUC must ensure the following: (a) the rates for the authority's transmission rate customers are subject to (i) the terms and conditions found in Supplements and to the authority's tariff, and (ii) any other terms and conditions the BCUC considers appropriate for those rates; (b) customers who own multiple plants under common ownership may engage in load aggregation for energy, if each plant (i) is in operation, and (ii) meets the requirements to be a transmission rate customer that are set out in the authority's tariff, or is otherwise authorized by the BCUC to be treated as a transmission rate customer; (c) the authority publishes the Tier rate in the manner and with the frequency required by the BCUC. BC Hydro and intervenors subsequently entered into negotiations on the structure of the transmission service rate resulting in the TSR NSA which was approved by BCUC Order No. G-9-0 in August 00.
The BCUC subsequently approved the TSR NSA by Order No. G-9-0. Section 10 of the TSR NSA established that BC Hydro will file a public Annual Report with the BCUC regarding the new TSR schedules: Rate Schedule 18 Transmission Service Stepped Rate (RS 18); Rate Schedule 18 Transmission Service Time-of-Use (TOU) Rate - (RS 18); and Rate Schedule 18 Transmission Service Rate for Exempt Customers - (RS 18). 8 9 The new TSR schedules came into effect on April 1, 00. Accordingly, BC Hydro has filed Annual TSR Reports for each of the three completed fiscal years (April 1 to March 1), being F00, F008 and F009. 10 Each TSR Annual Report provides a detailed summary of the following: 11 Customer Baseline Load (CBL) adjustments; 1 Forecast RS 18 energy sales and revenue; 1 Actual RS 18 energy sales and revenue; 1 An estimate of customer conservation, efficiency and self-generation; 1 Public information regarding economic expansions of customer facilities; and 1 An estimate of financial and cost-shifting impacts. 1 18 19 0 Further to recommendation number 9 in the BCUC s 00 Report and Recommendations, section 10 of the TSR NSA also established that, after BC Hydro s third TSR Annual Report (F009), the BCUC will provide a comprehensive evaluation to Government regarding the new TSR schedules by December 1, 009. 1 The TSR NSA described the TSR Evaluation as follows:
8 9 This Evaluation will be filed by the end of 009 and will be an expansive review of whether the new rates are achieving the objectives of the Energy Plan and Heritage Inquiry Report and Recommendations, including the objective of avoiding cost-shifting between customer classes. The parties expect that BCUC staff will work with interested parties to formulate the terms of reference for the Evaluation to ensure that it will provide a comprehensive review of the operation and results of the new rates. The parties expect that the BCUC will make recommendations to the government regarding any necessary or desirable changes to Special Direction HC. 10 11 The BCUC established the Terms of Reference for the TSR Evaluation by Order No. G-10-09, which also established the following regulatory timetable: 1 TSR Three-Year Summary Report filed by BC Hydro September 0, 009; 1 BCUC and Stakeholder Information Requests October 1, 009; 1 BC Hydro IR Responses November, 009; 1 Stakeholder Final submissions November 18, 009; 1 BC Hydro Final submission November, 009; and 1 BCUC submits its TSR Evaluation Report to Government December 1, 009. 18 19 0 1 As described above, the TSR NSA includes an expectation that, as part of its TSR Evaluation report to Government, the BCUC will make recommendations regarding any necessary or desirable changes to section of HC. In light of the comments that follow in this report, BC Hydro s general observation is that some changes to section of HC may be desirable to allow the BCUC more flexibility to approve TSR design changes that enhance energy efficiency, conservation and self-generation opportunities (including retail access), or that address elements of the rate structure that may lead to less than optimal results in the future.
Responses to Terms of Reference Questions.1 Question 1: Has the transmission services stepped rate (RS 18) facilitated conservation by BC Hydro s transmission customers?.1.1 Introduction The stepped rate has facilitated conservation by TSR customers. 8 9 Prior to April 00, energy sales to transmission customers were based on a flat rate under Rate Schedule 181 Transmission Service (RS 181). For many transmission customers, RS 181 did not allow a sufficient return on investment for capital projects designed to reduce electrical energy use or increase self-generation output. 10 11 1 1 1 1 1 1 18 19 0 1 8 9 0 1 The 00 Energy Plan contained two policy actions which described the basis for new rate structures for transmission voltage customers: Policy Action #1 (new): Under new rate structures, large electricity consumers will be able to choose a supplier other than the local distributor. New stepped pricing (see Conservation and Efficiency) will provide an incentive for large industrial or transmission rate customers to purchase from IPPs, or to self-generate, when they can do so less expensively than the utility s cost of new supply Policy Action #1 (new): New rate structures will provide better price signals to large electricity consumers for conservation and energy efficiency. The BC Utilities Commission will conduct a hearing to develop new stepped and time-of-use pricing for BC Hydro s industrial and large commercial customers. As a principle, for stepped rates, the last block of energy consumed should reflect the cost of new supply. This will encourage these customers to meet part of their electricity needs through conservation and energy efficiency, or from other sources (self-generation or IPP purchases), where they can do so cost-effectively. To keep rates low overall, the stepped rate structure will be revenue neutral. Time-of-use rates will encourage customers who can manage the timing of their electricity use to shift consumption to low priced off-peak periods.
Therefore, RS 18 was designed to elicit a customer demand side management (DSM) response. The Tier Rate provides customers with a transparent indication of BC Hydro s long term marginal cost of new supply; and an efficient price signal to drive DSM investment. 8 9 10 The definition of DSM in Section.0 of the CBL Determination Guidelines is capital projects relating to energy efficiency, energy conservation and load displacement. BC Hydro is of the view that this definition is consistent with the definition of Demand-Side Measure in the amended Utilities Commission Act (UCA) which is a rate, measure, action or program undertaken: (a) to conserve energy or promote energy efficiency, (b) to reduce the energy demand a public utility must serve, or (c) to shift the use of energy to periods of lower demand. 11 1 There are two categories of RS 18 customer DSM, as shown in Table 1 below. The sum of these two categories is an estimate of the Total DSM response: 1 1. Customer Reported DSM (reported energy savings) 1. Unreported DSM (residual energy savings) 1 Table 1 Total DSM Summary (F00 F009) RS 18 Customer F00 F008 F009 DSM Category GWh GWh GWh Customer Reported DSM 8 8 Unreported DSM 1 0-1 11 1 Total DSM - 8 98 100 The CBL Determination Guidelines are found in BC Hydro Electric Tariff Supplement No.. Customer Reported DSM is acquired energy savings that reflects the total estimated electrical energy reduction that was deemed (or physically measured) to have occurred at the BC Hydro meter each year. For each GWh of acquired energy savings from DSM, the customer is deemed to have purchased one less GWh of energy at the BC Hydro meter. Acquired energy savings are not cumulative between fiscal years. The estimate of acquired energy savings changes each year in line with changes in individual project persistence (life) and measurement and verification results. The CBL Determination Guidelines are found in BC Hydro Electric Tariff Supplement No..
Customer Reported DSM is an estimate of energy savings from energy conservation, efficiency and self-generation projects that were funded/installed by the customer. These projects were reported to BC Hydro as part of the annual CBL adjustment process and verified by BC Hydro to be operational. Customer Reported DSM occurs in response to the stepped rate and Power Smart enabling activities working in combination. These results have been provided in each of the TSR Annual Reports. 8 9 10 11 1 Unreported DSM is an estimate of residual energy savings from energy conservation and efficiency and self generation actions that were funded/installed by the customer. These actions were neither reported to, nor verified by, BC Hydro. Unreported DSM is assumed to occur in response to the stepped rate and Power Smart enabling activities working in combination. These results have not been provided in the TSR Annual Reports. A more detailed summary of each DSM category follows. 1 1 1 1 1 18 19.1. Customer Reported DSM These projects are 100 per cent funded by the customer. In all cases of Customer Reported DSM, BC Hydro has not provided a direct capital incentive towards the capital cost of the project. However, in some cases, BC Hydro has provided financial assistance to identify the DSM project and/or provided technical, key account manager and rate analysis support to verify the project energy savings and investment economics. These efforts are collectively regarded as Power Smart enabling activities. 0 1 BC Hydro s approach is to work with customers to identify, implement and verify DSM projects that are beneficial to customers under the stepped rate. BC Hydro has calculated the total acquired energy savings by fiscal year from Customer Reported DSM projects in each of the TSR Annual Reports. These projects reflect the total acquired energy savings from DSM projects that were verified to be operational at each individual RS 18 customer site. There are many complex variables that impact customer electricity use and DSM investment decision-making. There is no clear objective way to discretely separate the impact of rate 8
structure, Power Smart enabling activities and other customer decision-making factors for each reported DSM project. For convenience, BC Hydro has further separated Customer Reported DSM into three sub-categories, as shown in Table, and described in more detail below: a. Legacy Conservation and Efficiency (November, 00 to December 1, 00); b. New Conservation and Efficiency (January 1, 00 to March 1, 009); and c. Incremental self-generation (relative to an established generator baseline). 8 9 Table Customer Reported DSM Summary (F00 F009) F00 F008 F009 Sub-Category GWh GWh GWh Legacy conservation and efficiency 1 11 19 New conservation and efficiency 18 9 Incremental self-generation 1 18 19 TOTAL 8 8 10 11 1 1 1 1 1.1..1 Legacy Conservation and Efficiency These DSM projects were installed between November, 00 and December 1, 00. The significance of the November, 00, start date is the introduction of the 00 Energy Plan, which set the stage for the implementation of new transmission service rates. Subsequently, through the TSR NSA, all parties implicitly agreed that customer investment in Legacy DSM projects was, at least in part, influenced by the 00 Energy Plan policy action for stepped rates. 1 18 19 Since the customers initial CBLs were to be established using actual metered calendar 00 energy consumption (00 metered energy), it was agreed that customers should not be penalized for any DSM investment after November, 00, that reduced 00 metered 9
energy. Accordingly, the annual energy savings from Legacy DSM projects were included as a credit adjustment to each customer s initial CBL, pursuant to section of the CBL Determination Guidelines. 8.1.. New Conservation and Efficiency These DSM projects were installed after January 1, 00. The intent of these projects is to reduce Tier energy purchases, although some customers have invested in larger DSM projects that reduced their energy purchases to below 90 per cent of their CBL, to achieve a combination of Tier and Tier 1 energy reduction. 9 10 11 1 1 1 1 Whereas the energy savings from Legacy DSM projects resulted in a credit adjustment to the initial CBL, the energy savings from New DSM projects installed after January 1, 00 do not result in a CBL adjustment unless the customer s actual energy purchases fall outside the annual 90 per cent - 110 per cent dead-band used for CBL resets. If the adjusted energy purchases fall below, or above, the established dead-band, the CBL is reset to the adjusted amount. As such, the reset CBL includes the energy savings associated with New DSM projects. 1 1 18 19 0 1.1.. Incremental Self-Generation These DSM projects reflect the increase in annual self-generation output between each fiscal year and the CBL establishment year (calendar 00 is the default CBL establishment year). BC Hydro has worked to establish a non-contracted generation baseline (non-contracted GBLs) for most customers with self generation based on the actual gross metered output of each generator in the CBL establishment year. The non-contracted description refers to generation output that is not under contract for off-site sales. 8 The non-contracted GBL represents the baseline generation output used by the customer in the CBL establishment year to serve an equivalent portion of the customer s historical plant load. A non-contracted GBL is required because the initial CBL is based on actual TSR energy purchases, which reflect the balance of the plant s total electricity requirements net of non-contracted self-generation. The non-contracted GBL calculation, using calendar 00 as the default CBL establishment year, follows the general formula: 10
00 metered energy + 00 gross generator output = total 00 plant load Where: 00 metered energy (net of RS 1880 energy) = unadjusted 00 CBL Where: 00 gross generator output = non-contracted GBL Each fiscal year, the participating customer provides BC Hydro with a Declaration of Generation for each of its generator units. This information is compared to the non-contracted GBL to determine the incremental generation output as follows: Gross generator output - non-contracted GBL = incremental generation (DSM) 8 9 10 11 1 Increased self-generation displaces metered RS 18 energy purchases, and is considered DSM (load displacement) for CBL purposes. In the absence of a Declaration of Generation, BC Hydro would not be able to determine the cause of significant changes in metered RS 18 energy purchases that may otherwise trigger a CBL reset in accordance with the annual dead-band provisions of the CBL Determination Guidelines. 1 1 1 1 1 18 Some customers with self-generation sell a portion of their incremental generation output to off-site customers (mainly to BC Hydro and Powerex). In such cases, BC Hydro establishes a contracted GBL for the customer that represents the amount of generation output that must first be used to meet historical plant load requirements. Generation output that is incremental to the contracted GBL is then sold under contract as "off-site sales", usually via an Electricity Purchase Agreement (EPA). 19 0 1 Any incremental self-generated energy that is surplus to the contracted GBL and EPA requirements, and that is used to serve an equivalent portion of the customer s plant load (thereby displacing actual RS 18 energy purchases), is considered incremental DSM for CBL purposes as follows: Gross generator output - contractual requirements = Incremental generation (DSM).1. Unreported DSM BC Hydro has provided a preliminary estimate of Unreported DSM in an attempt to provide an estimate of the total conservation response to the TSR rate structure. 11
.1..1 Unreported DSM Definition Unreported DSM is an estimate of residual energy savings from energy conservation and efficiency and self generation actions that were funded/installed by the customer. These actions were neither reported to, nor verified by, BC Hydro. This definition of Unreported DSM includes energy savings from both unreported DSM projects and customer DSM actions such as behavioural and/or operational changes. This includes capital and non-capital DSM activity. 8 9 10 11 For example, unreported customer DSM projects may include actual capital projects such as motor replacements or control system upgrades. Unreported customer DSM actions may include non-capital behavioural/operational change actions such as turning off idle equipment, product grade changes, or compressor leak repairs. 1 1 1.1.. Unreported DSM Preliminary Estimate BC Hydro has not provided an estimate of Unreported DSM in prior TSR Annual Reports. This is a challenging analysis for the following reasons: 1 1 Data: BC Hydro has incomplete information on how customers have responded to the rate and/or what they would have done in absence of the rate change; 1 18 Control group: There is no control group of industrial customers that are not on the stepped rate. 19 0 Multiple variables: There are multiple data inputs that must be standardized and treated with specific assumptions, for statistical and econometric analysis to be performed. 1 Model Specification: An estimation model must be able to separate and measure the impact of different factors, including the stepped rate, on total conservation so that the amount of unreported conservation can be estimated. Nevertheless, BC Hydro considers it important to attempt to provide an estimate of the unreported conservation impact of the stepped rate and proposes two alternative methods by rate evaluation experts: 1
Method 1: TSR Impact Evaluation (BC Hydro Evaluation) (Appendix B); and Method : Statistical Analysis (Energy and Environmental Economics (E)) (Appendix C) Method 1 and Method utilize econometric and statistical analysis models, respectively. Table presents the results of each method, providing an estimate of the range of Unreported DSM. Table Estimate of Unreported DSM (F00 to F009) Unreported DSM F00 F008 F009 GWh GWh GWh Method 1 1 11 Method 1 0 1 PRELIMINARY RANGE 1 0 1 11 1 8 9 10 11 1 1 Note that the estimates of Unreported DSM are not directly comparable, since each method utilizes different data sets and employs different modelling and analysis logic. Furthermore, although the estimate of Unreported DSM may be generally viewed as the residual price response to the change in rate structure, BC Hydro has no knowledge of the specific drivers of customer projects and actions that are reflected in the Unreported DSM estimate. Thus, it is reasonable to assume that some of the Unreported DSM may include other factors such as Power Smart enabling activity. 1 1 1.1.. Subjective Test of Reasonableness BC Hydro has used subjective judgement to test the reasonableness of the Unreported DSM estimated by each method. 1 18 19 This subjective test is premised on the assumption that Customer Reported DSM is a conservative estimate of the Total DSM response. That is, Customer Reported DSM reflects a percentage (some number less than 100 per cent) of Total DSM. These are estimates only, and are not used by BC Hydro for DSM planning purposes. 1
As described above, Unreported DSM reflects the sum total of residual energy savings from DSM projects and actions at TSR customer sites that have not been reported to BC Hydro and are therefore not known or verified by BC Hydro. 8 BC Hydro estimates that there is a 10 to 0 per cent Unreported DSM response to RS 18 in addition to the Reported DSM. This estimate is based on the experience of BC Hydro Key Account Managers working with RS 18 customers on a regular basis, as well as the CBL annual review process. Table below provides the estimated range of Unreported DSM for each fiscal year based on the 10 to 0 per cent estimates. 9 Table Subjective Estimate of Unreported DSM 10 The two estimates of Unreported DSM shown in Table provide a range of numbers which 11 are not inconsistent with the estimates under the subjective estimates using a 1 10 to 0 per cent range, as shown in Table. 1
. Question : Has the transmission services stepped rate (RS 18) facilitated retail access by BC Hydro s transmission customers? The stepped rate has not facilitated retail access by TSR customers. Retail access arose from the 00 Energy Plan s Policy Action #1: under new rate structures, large electricity consumers will be able to choose a supplier other than the local distributor. 8 9 10 The stepped rate would provide the incentive for BC Hydro s TSR customers to purchase from alternative suppliers, such as IPPs, or to self-generate, when they can do so less expensively than BC Hydro s long term cost of new supply. The policy change introduced retail competition for TSR customers. 11 1 1 No customers have entered into Retail Access Program Agreements in any of the past three years. Accordingly, no customer has used RS 1890 (energy imbalance for retail access customers). 1 1 A detailed overview of the retail access design is provided in the response to question, in the next section. 1
. Question. If no retail access has occurred, why not? Are there features of the transmission services stepped rate that detract from the attractiveness of retail access?..1 If no retail access has occurred, why not? In order to understand why retail access has not occurred, it is helpful to first review retail access design. 8 9 10 Retail access gives transmission customers the option to purchase a portion of their monthly energy requirements from a supplier other than BC Hydro. Customers can displace their Tier energy purchases from BC Hydro by purchasing the energy from an alternate (third-party) supplier. 11 1 1 1 The retail access customer is required to enter into a Retail Access Program Agreement, also known as Tariff Supplement No. 1 (TS No. 1), with BC Hydro. TS No. 1 requires monthly firm energy to be scheduled and delivered by the third-party supplier over a month initial term. This is the retail access energy. 1 1 1 18 The retail access customer also enters into an agreement with a third-party supplier or suppliers pursuant to which the supplier(s) provide the retail access energy to the BC Hydro system from the supplier s own generation or from the market. The retail access energy is supplied to the BC Hydro system at the Point of Receipt (POR) defined in the contract. 19 0 1 BC Hydro applies a postage-stamp energy loss charge of.8 per cent in relation to the delivery of the retail access energy from the POR to the retail access customer s site called the Point of Delivery (POD). This charge is based on the average real power transmission losses in the British Columbia Transmission Corporation s (BCTC) Open Access Transmission Tariff (OATT). The arrangement is shown in Figure 1 below. 1
Figure 1 Illustration of Delivery of Retail Access Energy The third-party supplier provides retail access energy to the BC Hydro system in accordance with the Output Schedule that forms part of TS No. 1. 8 9 Each month, actual gross energy delivered to the POR is compared to Gross Scheduled Output, the.8 per cent energy loss charge is deducted, and Net Actual Output is deemed to have been delivered to the retail access customer. Each month, for billing purposes, BC Hydro then deducts the Net Actual Output from actual metered RS 18 energy purchases at the customer site. 10 11 1 1 If Net Actual Output is higher than Net Scheduled Output, there is an energy surplus and a credit applies to the incremental energy. If Net Actual Output is lower, there is an energy shortfall and a charge applies to the decremental energy. Energy imbalance credits and charges are set out in RS 1890 and described (using F009 rates) in Table below. 1 1 Table RS 1890 Imbalance Rates for 009 (based on RS 18) 1
The imbalance credit for the first 10 per cent energy surplus is the seasonally/hourly adjusted RS 18 Tier Rate. The imbalance credit for the balance of the energy surplus is the RS 18 Tier 1 Rate. The imbalance charge for all energy shortfalls is the seasonally/hourly adjusted RS 18 Tier Rate. Figure, below, shows the retail access design including imbalance charges. Figure Illustration of Energy Imbalance RS 1890 18
.. Are there features of the transmission services stepped rate that detract from the attractiveness of retail access?...1 Introduction What has become clear to BC Hydro is that the underlying premise upon which retail access was originally based (that some customers would wish to acquire some or all of their electricity supply from a third party other than BC Hydro) has not been borne out. 8 9 10 Interviews and workshops with customers revealed that most customers were not aware of the retail access alternative. For those customers that were aware, the terms, conditions, risks and complexities of purchasing power from a third-party supplier combined to made retail access less attractive than purchases from BC Hydro under RS 18. 11 1 1 The specific features of the transmission services stepped rate that deter customers from pursuing retail access are the amount of energy priced at Tier and the Tier Rate. In addition, the risks to customers of retail access outweigh the benefits. 1 1 1 With respect to energy priced at Tier, many RS 18 customers have already made significant DSM investments such that there is not sufficient Tier energy being purchased to be displaced by retail access. 1 18 19 With respect to the Tier Rate, despite being reset in F009, the prevailing Tier Rate is lower than the prevailing marginal price of IPP energy, such that the margin is not sufficient to warrant retail access. 0 1 With respect to risks, the customer perspective, as understood from customer interviews and workshops, is generally that TS No. 1 and RS 1890 seem complex and restrictive. For most customers the risks of taking retail access energy outweigh the potential benefits. These features are described in more detail below. 19
... The Tier Rate and the Amount of Energy Priced at Tier In order to secure project financing, IPPs secure contractual commitments for energy sales in advance of project construction. In B.C. this usually takes the form of a long-term EPA with BC Hydro. Almost all of the firm generation output from existing IPPs in the province is already committed to BC Hydro or another purchaser pursuant to a long-term EPA. Any surplus energy that an IPP may have available to sell on a short-term, non-firm basis would not be a suitable energy product for retail access. 8 9 10 11 1 1 1 Thus, there is little (if any) firm IPP power in B.C. that is currently available to retail access customers, and it is unlikely that an IPP would build a new generation facility to serve retail access customer loads under shorter term contracts. In addition, RS 18 s Tier 1 and Tier pricing split at 90 per cent of CBL effectively limits the amount of Tier energy that a customer may be interested in obtaining through retail access to 10 per cent of the customer s CBL (or aggregated CBL). Many RS 18 customers have already reduced their Tier purchases by investing in DSM which further reduces the retail access market. 1 1 1 18 The Tier Rate was $/MWh in F00 and F008 (based on BC Hydro s 00 Green Power Generation Call) and reset to $.0/MWh in F009 (based on BC Hydro s 00 Call for Tenders). The prevailing Tier Rate has, to date, been a lagging indicator of BC Hydro s long term marginal cost of new supply. 19 0 1 For example, the Tier Rate of $.0/MWh in F009 is less than the average levelized plant gate price of $101/MWh of the four contracts awarded in the 008 Bioenergy Call Phase 1 Request for Proposals (008 Bioenergy RFP). 8 The Tier Rate can also be compared to market electricity prices, using the Mid-Columbia (Mid-C) hub as the market reference. The Mid-C price, plus wheeling charges from Mid-C to the border, is broadly representative of the short term wholesale market price available to retail access customers in B.C. Table below shows that the price for Mid-C energy, excluding delivery to the BC Hydro system, was comparable to or higher than the Tier Rate in F00 and F008. The Mid-C price excluding delivery was lower than the Tier Rate in F009. 0
Table Price Comparisons (current Canadian dollars per MWh) Tier 1 Rate Tier rate Mid-C Difference between Mid-C and Tier 1 Rate Mid-C and Tier Rate F00..00 1.. (.8) F008..00 8.9.0.9 F009..0.8.1 (1.) 8 Retail access also allows TSR customers to arrange for transmission service directly from BCTC. TSR customers can expose their load on a full or partial basis to retail access, provided that BC Hydro has access to the information necessary to properly bill such a customer for imbalance service. However, no customers have elected to make these arrangements with BCTC mainly because of the low cost of RS 18 relative to the cost of retail access supply alternatives. 9 10 11 1... The Retail Access Program Agreement (TS No. 1) TS No. 1 requires the transmission customer and the third-party retail supplier to commit to a -month delivery schedule of firm monthly output (scheduled output). The scheduled output can only be provided within a fixed monthly range. 1 1 1 1 The highest entry within any month cannot exceed 10 per cent of the lowest entry for any other month over the entire -month term. Further, scheduled output must be specified for heavy load hours (HLH) and light load hours (LLH) for the winter months of November to February. 1 18 19 In effect, the energy product contracted for delivery under retail access during the months of March to October is firm monthly energy. The energy product contracted for delivery during the months of November to February is firm hourly energy. 0 1 Interviews, meetings and workshops with TSR customers and potential third-party suppliers revealed that these terms and conditions are considered to be, for the most part, unattractive. 1
... Risks Versus Benefits The benefit of retail access is the opportunity to displace Tier energy purchases by obtaining lower cost supply from an alternate supplier. However, the retail access customer takes the risk that it may end up paying more for the energy than the Tier Rate. The customer s energy price risk is based on the following considerations: 8 The customer must estimate its annual Tier energy purchases from BC Hydro for the next three years that it will seek to replace with lower priced retail access energy purchases that meet the requirements of TS No. 1; 9 10 11 1 The customer s actual energy purchases from BC Hydro would be impacted by load reduction events such as DSM, force majeure, unplanned outages, and adverse economic conditions. All of these events would serve to reduce the customer s actual Tier energy purchases from BC Hydro; 1 1 1 1 1 18 19 To the extent the customer is not able to foresee such energy reduction events and commits to purchasing a defined monthly volume of energy from a third-party supplier, the customer could be required to pay the third-party supplier for energy at the contract price at times when the customer would otherwise pay BC Hydro the Tier 1 Rate. The energy price risk may not be symmetrical for unplanned increased purchases from BC Hydro. The risk is equal to the contracted energy sales price minus the prevailing Tier 1 Rate; and 0 1 Per the example below, the potential benefit of retail access could be a $/MWh discount on Tier energy purchases, offset by a potential price risk of $.8/MWh. Unless the customer is able to transfer this energy price risk to the third-party supplier through their contract, which is unlikely, the risk would be borne by the retail access customer.
Retail Access Example: For a transmission customer with a CBL of 10 GWh/yr, the potential Tier energy available for replacement with retail access energy is 10 per cent x CBL = 1 GWh/yr = 1,000 MWh/month. Assumptions: Energy CBL = 10,000 MWh; Actual F009 Tier 1 Rate = $./MWh; 8 Actual F009 Tier Rate = $.0/MWh; 9 Assume $/MWh Tier discount for retail access energy = $8.0/MWh; and 10 Energy price risk = Discounted Tier energy Tier 1 Rate = $.8/MWh 11 1 1 1 For illustrative purposes, it is assumed the discounted F009 energy sales price for retail access energy is $/MWh less than the F009 Tier Rate of $.0/MWh = $8.0/MWh. This is the price that the transmission customer would pay to the third-party supplier for monthly delivered energy. 1 1 1 18 The third-party supplier needs to supply 1,0 MWh of gross energy for every 1,000 MWh of net energy delivered to satisfy BC Hydro s.8 per cent energy loss charge. This reduces the effective realized energy price to the third-party supplier by.8 per cent = $8.0/MWh - $.0/MWh = $.0/MWh. 19 0 1 A retail access customer probably would not be able to do any better than a $/MWh discount since a realized price lower than $.0/MWh (for a firm monthly energy product) may not be economic for the third-party supplier, which illustrates the thin margins on the Tier Rate spread.
Benefit: Assuming a $/MWh discount, the transmission customer could save $0,000/year: ($/MWh discount x 1,000 MWh/month = $,000/month x 1 = $0,000/year. Risk: Assuming a price risk of $.8/MWh, the transmission customer could pay an additional $,000/year (notwithstanding the ability to recover incremental imbalance charges for energy shortfalls and/or non-delivery): ($.8/MWh price risk x 1,000 MWh/month = $,000/month x 1 = $,000/year).
. Question : Has the transmission services stepped rate (RS 18) caused costs to shift to other BC Hydro customer classes or to the shareholder? Costs have been shifted from the TSR class to other customer classes and to the shareholder as a result of the stepped rate. There are two points in time at which a cost shift from RS 18 customers can be identified: on a forecast rate-setting basis; and on an actual, after-the-fact basis. 8 9 10 11 1..1 Forecast Cost Shift On a forecast basis, a revenue variance arises from the pricing difference between the former RS 181 flat rate structure and the RS 18 stepped rate structure (in combination with CBLs) applied to the same forecast of energy sales. This analysis establishes the upper bound of a potential cost shift in that it assumes that forecast energy sales volumes and costs under RS 18 would be the same under RS 181, regardless of the difference in rate structure. 1 1 1 1 1 The analysis is imperfect because the revenue variance does not take into account the DSM response to the RS 18 rate structure which would result in differences between energy revenues and costs between the rate structures. A comparable estimate of DSM savings and costs was not created for a scenario where RS 18 was not implemented and all TSR customers remained on RS 181, which was terminated in April 00. 18 19 0 1 The revenue variance that arises is, nevertheless, an estimate of the cost or benefit shift to all customer classes via an across-the-board class average rate change pursuant to a BC Hydro Revenue Requirements Application (RRA). If the forecast revenue variance is positive, it will reduce the requested across-the-board rate increase. If the revenue variance is negative, it will increase the requested across-the-board rate increase. Estimated RRA cost-shift impacts for each fiscal year are shown in Table below.
Table Forecast Revenue Variance Impact (F00 F009) F00 RRA F008 RRA F009 RRA Transmission Rates $/MWh $/MWh $/MWh RS 18 Tier 1 Rate... RS 18 Tier Rate.00.00.0 RS 18 Rate.0.0 8. Forecast Energy Sales GWh GWh GWh Forecast CBL 1,0 1,0 1,18 RS 18 Tier 1 energy sales 1,01 1,88 1,098 RS 18 Tier energy sales 1,9 1,9 8 Total Forecast RS 18 energy sales 1,9 1, 1,8 Forecast Energy Revenue $ million $ million $ million Forecast RS 18 sales revenue. 18. 1.1 Reference RS 18 sales revenue 9.. 8.1 8 9 10 11 1 Revenue Variance*.0 (.) (.9) * As noted above, this analysis does not take into account the reduced costs to BC Hydro due to the forecast DSM response to the RS 18 stepped rate. Nor can it, given there is no way of estimating the DSM response to a continued flat rate under RS 181... After-the-fact Cost Shift On an actual, after-the-fact basis, a gross revenue variance arises from the difference between forecast RS 18 energy sales and actual RS 18 energy sales. When forecast energy sales to customers are lower than forecast energy sales in a fiscal year, BC Hydro receives less revenue than forecast, but it also supplies less energy than forecast. This load variance therefore results in an offsetting reduction in the cost of energy. These revenue and cost variances arise irrespective of rate structure. 1 1 1 1 BC Hydro has used a short-run marginal cost estimate to value the avoided cost of energy for the purposes of this analysis. The difference between the Tier Rate and the short-run marginal cost determines the extent to which RS 18 is margin neutral, all other things being equal.
8 9 10 11 The short-run marginal cost value is based on the average cost of market energy prices in each fiscal year. The actual average market price was used to value avoided energy costs in F00 and F008 as BC Hydro did not include load variance in its cost of energy deferral accounts in F00 and F008. In BCUC Order No. G-1-09 and Reasons for Decision regarding BC Hydro s F009/F010 Revenue Requirements Application (F09/F10 RRA) the BCUC approved a change to the Non-Heritage Deferral Account to include cost of energy variances arising from load variance for two years, F009 and F010. Under the cost of energy deferral account rules, BC Hydro uses the forecast Plan average cost of market electricity purchases if forecast supply is greater than actual supply. This was the case in F009 and the forecast Plan average cost of market electricity purchases for F009 was $./MWh. The gross margin calculations are shown in Table 8 below: 1 1 Table 8 Actual Versus Forecast RS 18 Gross Margin Variance F00 F008 F009 Avoided Cost of Energy Reference $/MWh $/MWh $/MWh Forecast market price of energy 8.00.0. Actual market price of energy.80.90.98 Energy Sales GWh GWh GWh Actual RS 18 energy sales 1,8 1,99 1,18 Forecast RS 18 energy sales 1,9 1, 1,8 Energy Sales Variance () (1,8) (9) Energy Revenue $ million $ million $ million Actual RS 18 energy revenue 91. 8. 1. Forecast RS 18 energy revenue 8.9 18. 1.1 Gross Revenue Variance (.) (0.0) (.) Avoided cost of energy adjustment 8.1 8.8 1.9 Gross margin (9.).8 (.) 1 1 1 In F00 and F008, BC Hydro s cost of energy deferral accounts did not account for variances in cost of energy arising from variances in customer load. As a result, the F00 and F008 impact on gross margin was effectively borne by BC Hydro, and ultimately its
shareholder (in the form of net income that was lower in F00, and higher in F008, than it otherwise would have been). 8 In F009, cost of energy variances arising from differences between forecast and actual RS 18 energy sales, net of cost of energy savings or losses, are captured in BC Hydro s Non-Heritage Deferral Account. As a result, the F009 impact on gross margin will effectively be borne by all customer classes through an adjustment to the deferral account rate rider. BC Hydro notes that this deferral account treatment is applied equally to all customer classes. 9 10 11 1 BC Hydro does not prepare separate income statements for any specific customer class. Accordingly, the gross margin analysis shown in Table 8 is a high-level estimate only that excludes the impact of demand charges, line losses, TSR administration costs, Power Smart program and enabling costs, and all other non-rs 18 industrial customer electricity sales. 8