Terasen Gas (Vancouver Island) Inc. ( TGVI ) 2010 and 2011 Revenue Requirements and Rate Design Application (the Application )

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1 Tom A. Loski Chief Regulatory Officer Fraser Highway Surrey, B.C. V4N 0E8 Tel: (604) Cell: (604) Fax: (604) Regulatory Affairs Correspondence British Columbia Utilities Commission Sixth Floor, 900 Howe Street Vancouver, B.C. V6Z 2N3 Attention: Ms. Erica M. Hamilton, Commission Secretary Dear Ms. Hamilton: Re: Terasen Gas (Vancouver Island) Inc. ( TGVI ) 2010 and 2011 Revenue Requirements and Rate Design Application (the Application ) Response to the British Columbia Utilities Commission ( BCUC or the Commission ) On June 29, 2009, Terasen Gas filed the Application as referenced above. In accordance with Commission Order No. G setting out the Regulatory Timetable for the Application, Terasen Gas respectfully submits the attached response to BCUC IR No. 2. If there are any questions regarding the attached, please contact the undersigned. Yours very truly, TERASEN GAS (VANCOUVER ISLAND) INC. Original signed: Tom A. Loski Attachment cc ( only): Registered Parties

2 Page Reference: External Situational Impact Comparable electric efficiencies Exhibit B-1, Part III, Section A, p. 33, par. 1 Exhibit B-4, BCUC IR TGVI has assumed 75% efficiency as a reasonable average 1.1 Please provide the calculation done by TGVI to arrive at the reasonable average. TGVI used a 75 per cent efficiency adjustment to BC Hydro s rates for existing customers consistent with TGVI s 2009 Price Risk Management Plan, approved by the Commission on June 8, The 75 per cent efficiency adjustment represents an estimate of the average efficiency of appliances used by existing TGVI residential customers, rather than a calculated percentage. TGVI has calculated an average efficiency adjustment of current residential customers based on the preliminary results of the 2008 Residential End Use Study ( REUS ), but TGVI believes the 75 per cent efficiency adjustment is more representative of current TGVI customers appliances than the calculated figure. The reason for this is that TGVI believes that the calculation based on REUS data may not be an accurate representation of customers current natural gas appliance efficiency levels due to many different factors including self reporting errors and sample size. For illustrative purposes, the table below outlines an analysis which calculates the average appliance efficiency of a typical TGVI residential customer, based on preliminary results of the REUS. Customer responses to the REUS have been categorized by the types of appliances in the dwelling then a weighted average efficiency of the appliance was calculated in each of those dwellings. The weighting was then applied using the relative consumption of each appliance. The overall average efficiency adjustment was calculated to be 60 per cent. As stated above, TGVI does not believe this is a reasonable representation of current TGVI customers. In addition, if the 60 per cent efficiency factor was used in comparing TGVI rates with BC Hydro residential rates, the result would be a substantially larger gap between rates for BC Hydro versus TGVI, with BC Hydro residential rates enjoying a much larger competitive advantage over TGVI residential rates. TGVI believes that the use of 75% continues to be appropriate.

3 Page 2 TGVI Customers - Weighted Average Appliance Efficiency Appliance Combinations Average Weighted Efficiency (%) Sample Size Furnace/Hot Water Tank/Fireplace Furnace/Hot Water Tank Furnace/Fireplace Furnace Hot Water Tank Hot Water Tank/Fireplace Fireplace Overall If the calculation is not available, please provide a calculation using the average efficiencies and average annual load for furnaces, hot water heaters and fireplaces. Please refer to the response to BCUC IR

4 Page Reference: TGVI TGI amalgamation Exhibit B-1, Part III, Section A, pp Exhibit B-4, BCUC IR Over time, assuming the adoption of postage stamp rates, the amalgamation would result in lower residential rates for TGVI that are more competitive as compared to electricity and a slight increase in rates for current TGI customers. 2.1 Assuming the data filed in the TGVI and TGI RRA Applications, without adjustment for the outcome of the TGU ROE Application, please provide forecast 2012 residential rates for TGVI and TGI. As requested in this IR, we have utilized the data filed in the TGI and TGVI RRAs. The 2012 residential delivery rate for TGI is assumed to be the same as the proposed 2011 delivery rate in the TGI RRA and therefore incorporates the assumption that the 2012 cost of service is unchanged from Consistent with the assumptions in the TGI RRA, the cost of gas and midstream rates applicable to TGI reflect the April 1, 2009 rates. For TGVI, the 2012 residential rates as presented below in the table are a high-level estimate based on recovering the estimated cost of service for 2012, which assumes no amortization of RSDA surplus, no royalty credits, base case cost of gas, and a payment of $20 million for the Federal/Provincial Repayable Contribution. The amalgamated rate has then been calculated incorporating the above two inputs. Please note that due to the lack of detailed budget data, the figures shown in the table below are for illustrative purposes only. Due to the inherent limitations in the forecast and the possibility of large fluctuations in commodity and other cost of service amounts included in the estimates, the results as displayed are of limited value and should not be considered an estimate of what actual 2012 amalgamated or stand alone rates would be Forecast Residential Rate* (in $/GJ) TGI TGVI Amalgamated Utility $ $ $ * forecast rate is only a high-level estimate. The rate shown above includes both fixed and the variable charge. As requested, the rates presented in the table above are based on the existing ROE and capital structure for TGI and TGVI. These rates would change based on changes in the ROE, capital structure, cost of gas, or any of the other estimates included in the underlying calculations.

5 Page Reference: Competitive Outlook BC Hydro Electricity Equivalents Confirmed. Exhibit No. B-4, BCUC IR 15.1 and Exhibit No. B-1, p. 49, Figure A Please confirm that the calculation presented in to response to BCUC IR 15.1 is illustrative of the method used to determine the trend line labeled as the BC Hydro Residential Inclining Block Step 2 rate on Figure A-3 of the Application. 3.2 Please confirm that this calculation, and the trend line on Figure A-3 of the Application, do not show the historical and forecast levels of the BC Hydro Residential Inclining Block Step 2 rate, but rather show the maximum price for the commodity cost of natural gas, above which the delivered cost of natural gas to TGVI s residential customers would no longer be competitive with electricity on a dollar per unit energy (i.e $ per GJ) basis. Confirmed. This calculation is a representation of the residual amount available from the BC Hydro residential electric rate to be equivalent to the commodity component of gas rates (i.e. the energy-based component of the electricity rate less the TGVI delivery charges). This calculated commodity component allows for a direct comparison of electric equivalent rates to AECO forward prices. 3.3 Please explain why the trend line on Figure A-3 of the Application is labeled as TGVI Revenue Requirement Electric Equivalent. What adjustments have been made to the commodity cost of gas? Figure A-3 of the Application shows three trend lines once BC Hydro's two-step Conservation Rate came into effect on October 1, One of these is labeled "TGVI Revenue Requirement Electric Equivalent". It is so labeled because the April 1, 2009 calculated value for this "TGVI Revenue Requirement Electric Equivalent" is based on the BC Hydro approved revenue requirement increases of 2.28% and 8.74% (per the Commission decision on the BC

6 Page 5 Hydro F2009/10 Revenue Requirements Application) and a 1% rate rider applied to the BC Hydro base rate of $0.0615/Kwh effective April 1, The other two electric equivalent trend lines are based on the BC Hydro Residential Inclining Block Step 1 and Step 2 rates. For subsequent years, for illustrative purposes, BC Hydro residential rate increases of 2% per year on all three electric equivalent trend lines have been assumed. While actual rate increases may be more or less than this, 2% has been used as an estimate closely equal to expected inflation. For all three electric equivalent trend lines (and as detailed in the response to BCUC IR ) the estimated BC Hydro rates have then been adjusted by a thermal efficiency factor of 90% for natural gas (as compared to 100% for electricity), the estimated TGVI delivery margin, estimated midstream costs, carbon tax and the estimated royalty revenue per unit credit to derive the residual component of the electric equivalent available to compare against the natural gas commodity prices. This then enables a direct comparison to the AECO commodity prices in evaluating TGVI's relative competitiveness with electricity rates on an operating cost basis. 3.4 Please restate Figure A-3 by presenting the commodity cost of natural gas adjusted for the Royalty Credit. In addition, please remove the Royalty Credit in the adjustment of the BC Hydro RIB Step 1 and Step 2 rates as presented in Figure A-3. The result of these changes should be a trend line for the BC Hydro RIB Step 1 and Step 2 rates that does not drop by $3.00 per GJ in Please comment on the appropriateness of this presentation of the comparison of natural gas and electricity commodity prices. Please refer to the chart below that represents a restated Figure A-3 from the Application which now includes the electric equivalents without the Royalty Credit adjustment of approximately $3/GJ when it expires on January 1, Although the Royalty Credit is no longer reflected in the electric equivalent lines of the graph, this $3/GJ credit has been be applied to the AECO forward curve to help illustrate the effect this credit has on the competitiveness of TGVI s cost of gas with forecast electricity pricing. Both the chart below and Figure A-3 from the Application provide the same message with respect to TGVI s competitiveness with electricity, but display it in a different manner. Therefore, neither graph is more appropriate than the other. Ultimately, TGVI s competitiveness challenge with electricity is evidenced in both graphs, namely when the Royalty Credit expires on January 1, 2012 TGVI s ability to be competitive with electricity, on an operating cost basis at least, is significantly affected.

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8 Page Reference: External Situational Context Ex. B-4, BCUC IR No and 17.1 Marketing: Energy Supply Source Selection - Price Expectations In making energy selection decisions, it is important that consumers concern themselves with the average price not the associated volatility in the natural gas price. This is due to the fact that natural gas is a commodity and like other commodities can experience significant price movements, but the causes for these price movements (volatility) may be different than the factors that will determine the average natural gas price in the long term. 4.1 Please explain which programs within the TGVI Sales Budget for each of 2010 and 2011 are dedicated to advancing consumer understanding and awareness of the average price of natural gas, how they do so, and what proportion of each year s budget they account for. TGVI does not split out the cost for, or dedicated to, advancing consumer understanding and awareness of the average price of natural gas. However, over the period of the RRA, TGVI will need to advance education in this area due to TGVI s expectation of setting rates in 2012 based on recovering cost of service. Interactions with customers and consumers by sales staff regularly involve discussion of natural gas commodity and delivery costs as these items are generally considered when making an energy decision. TGVI commercial and industrial customers often inquire as to the options for marketer delivered gas and the nature of the natural gas market. Lastly, we provide bill inserts as well as website information that helps to educate the customer on natural gas pricing.

9 Page Reference: External Situational Context Ex. B-4, BCUC IR No Marketing: Conversion Program 5.1 What proportion of the Conversion Program in the TGVI Sales Budget for each of 2010 and 2011, shown in response to IR No , is devoted to Terasen Gas Whistler? None of the costs for the Conversion Program included in the TGVI budget are intended for Terasen Gas Whistler. 5.2 What is the ratio of Conversion Program expenses to expected customers for 2010 and 2011? Conversion customer additions are not delineated from the aggregate customer additions forecast. For existing mains, approximately 50% of potential customers who could attach to the main have attached (also known as on main saturation). There is significant on main conversion potential to warrant the associated expenses to attempt to penetrate this potential, with a reasonable expectation of success. These focused efforts will be monitored, and adjustments made as required, contingent on the degree of success in this market.

10 Page Reference: Gas Sales and Transportation Demand Ex. B-3, BC Hydro IR No.1 7.1, and Ex. B-6, BCOAPO IR No Marketing: Resource Costs vs. Revenue Impacts 6.1 The table provided in response to BCOAPO IR No shows that there has been a near doubling of marketing expenditures per FTE between 2003 and Does TGVI expect these added marketing expenditures to influence the number of accounts? If so, please explain how, and show that this is consistent with the results of the last three years (2006 through 2008). The question appears to incorrectly assume that the increase in marketing expenditures per FTE over the period is attributable to an increase in the expenditures. Marketing expenditures (as shown in the table below) have, on a real basis declined over the period. The reason for the increase in marketing expenditures per FTE is a result of a reduction in direct marketing staffing. The information demonstrating these facts is provided in the tables below. For the reasons set out later in this response, TGVI believes that marketing expenditures per FTE is not a good way to assess the reasonableness of marketing expenditures over time. Below are the total marketing dollars spent in the years from which the above referenced table was created: REVIEW OF HISTORICAL GROSS OPERATIONS & MAINTENANCE EXPENSES BY BUSINESS AREA ($000s) Actual Projection Department Gross Nominal O&M Marketing & Business Development Gross Real O&m Marketing & Business Development Notes: All amounts are in $ millions Gross O&M expenses are before removal of capitalized overheads and vehicle lease expenses. This table shows that on a real basis, spending in the marketing department actually declined over the period. The increase in expenditures per FTE in the Marketing department is a result of a decline in employees rather than an increase in spending. The table below shows the change in TGVI marketing FTE over the period:

11 Page 10 Terasen Gas (Vancouver Island) Inc. FTE Reconciliation TGVI Marketing The first decline in employees in the Marketing department (2006-7) is a result of the outsourcing of the customer care function to CWLP. Customer billing staff prior to 2007 were included in the Marketing headcount. After the transition to the outsourced model, staffing numbers were reduced, but customer care costs remained with payments made to the outsourced provider instead of internal staff. The second reduction in staff was due to a change in the sales structure of TGVI. TGVI re-allocated the budget for staffing these three staff to other TGVI sales programs. As the table below shows, the majority of costs incurred by the marketing department are either fixed, or tied to customer numbers or behaviour (not staffing costs). Approximately 64% of marketing costs are for the CWLP outsourced customer care contract that is based upon customer numbers, not staff numbers. Bad debt and historical DSM programs make up another 13-16% of marketing costs (note that post 2009, DSM/EEC costs will no longer be part of the O&M budget). A small portion is related to Communications. The remaining approximate 17-19% is related to sales programs and staffing costs which could vary if staffing numbers and sales activities change. MARKETING - TGVI O&M EXPENSE (GROSS NOMINAL) Year over Year change vs vs vs 08 O&M Expense $(000) Actual Actual Actual Projected Bad Debt Customer Care Contract Energy Efficiency Pgms Communication Sales Programs and Staffing Total Therefore the marketing expenditures per marketing FTE is not a reasonable measurement tool as the majority of costs are fixed. In fact, if there were no marketing staff, TGVI would still require a marketing budget of over $5 million in order to pay for the customer care and bad debt costs, thus making a cost per employee impossible to determine.

12 Page How are TGVI Marketing expenditures allocated between Residential, Commercial, and Transportation markets? What has been the return per dollar spent for each sector over the period 2003 through 2008? As shown in response to BCUC IR 2.6.1, the marketing expenditures include customer care costs (CWLP contract, bad debt), historical DSM programs, and sales programs and staffing costs such as sales, account management and community relations staff. The bulk of the expenditures for marketing relate to the CWLP contract, which is based upon the number of customers, as well as bad debt expenditures. DSM program costs will no longer be allocated to O&M (BCUC Order No. G-36-09). The remaining portion of costs are for sales related programs such as conversion programs as well as staffing in the following areas: Sales staff expenditures relate to costs for selling to developers and commercial customers. Account Management expenditures related to account management activities for commercial and transport customers. Staffing costs for Community Relations include government, First Nations and Community relations contact. Since many of these activities are not directly related to adding new customers, but to paying for customer care costs and keeping customers and existing load, an ROI is not directly related to spending. It is imperative that TGVI have staff devoted to both sales and account management to ensure that existing customer s needs are being addressed and new customers are being added to the system. One example of existing customers needs being met and the benefit of account management activities on TGVI is the increase in BC Hydro s firm capacity from 45TJ/day to 50TJ/day for delivery of gas to the Island Cogeneration Plant ( ICP ). The original long-term firm contract was negotiated by a number of TGVI staff, but the day-to-day management of the contract falls to the TGVI commercial and industrial Account Manager. This account manager spent time working with BC Hydro to ensure that TGVI was able to deliver the increased capacity and to ensure that the contractual issues were addressed. The result of these efforts was the successful increase in firm delivery. The ROI for the annual account management costs (staffing and expenses of one employee compared to the increase in firm revenue from ICP) is approximately 22 days. In other words, the costs for the account manager were paid for within 22 days.

13 Page 12 Sales staff are also integral in the advancement of the natural gas system. As noted in the Application, the Company believes that TGVI is an immature utility. Aggressive sales efforts are required to be able to attach new customers, which will make the system more efficient and keep delivery costs as low as possible in the long term. While customer attachments are greatly influenced by housing starts, in 2006 there were 585 customers added per TGVI sales staff, and in 2009 it is projected that 661 customers will be added per sales staff. What this demonstrates is that cost per customer addition has not changed over the period. In fact, as customer additions increase with an increase in housing starts, customer additions per sales staff will also increase. Further, as noted in the Application, sales staff require more time to be spent with each potential new customer, as these customers expectations have changed. Customers want more information on options for energy delivery, and, as such, sales staff require more time to evaluate customer needs and sell the customer on an optimal energy solution. Without sales and account management staff, TGVI will not be able to meet the needs of both new and existing customers.

14 Page Reference: Gas Sales and Transportation Demand Ex. B-4, BCUC IR No , and Ex. B-6, BCOAPO IR No and 15.2 Marketing: Energy Supply Source Selection Information TGVI does not have any information with regard to the difference in new or resale housing prices between houses with natural gas space heating and houses with electric baseboards. TGVI confirmed with Canadian Mortgage and Housing Corporation that they do not track this information either. [B-6, BCOAPO IR No ] Residential End-Use An end-use study is conducted on a periodic basis to garner information on how natural gas is used by residential customers, the characteristics of the residential dwellings surveyed and the energy related behaviours of our customers. The information is used to design energy efficiency and conservation programs, explain changes in demand and assist with the forecast of future demand. [B-6, BCOAPO IR No ] 7.1 Do TGVI Residential End Use Surveys include information that would allow the value of a respondent s home to be determined? If not, please explain why not, and whether TGVI intends to address this. TGVI Residential End Use Surveys do not currently include information that would allow for the value of a respondent s home to be determined. Although it is likely that the home value provides some indication of consumption levels, TGVI believes there are many other factors that provide better information with respect to profiling consumption patterns, and therefore home value has not been included. Additionally, if TGVI wished to include home value information, this would require home owners to know the value of their home. And although TGVI may ask for this information, it is questionable whether or not it will be received, and also whether or not it will be relevant. The decision regarding whether or not to include home value in future Residential End Use Surveys will be made after reviewing the final 2008 REUS to determine whether or not additional questions would provide better information from which to analyze consumption patterns/behaviours.

15 Page Please explain ways that TGVI Residential End Use Surveys have helped to explain changes in demand and list contributions to the demand forecasts for 2010 and 2011 used in the Application. TGVI Residential End Use Studies (REUS) have helped to explain changes in demand by enabling a greater understanding of its customers through estimating a wide variety of characteristics/behaviours, including: Housing mix; Size of homes; Length of residence; Thermal envelope; Levels of renovation activity; Use of setback thermometers; Average water use per person; Amount of draft proofing done; and, Use of window coverings. In addition, a conditional demand analysis has provided consumption estimates for the various end uses of natural gas, further enhancing TGVI s understanding of its residential customers. When considering these factors, together with recent historical consumption patterns, conclusions may be drawn regarding the causal factors behind changes in consumption levels. Although the 2008 REUS results were not available in time to contribute to the forecasts in this Application, the 2008 REUS will serve as a baseline for TGVI, which, together with future (and, as proposed, more frequent) REUS, will lead to the identification of trends that may be incorporated into future demand forecasts.

16 Page Reference: Competitive Outlook B.C. Government Goal BCUC IR.22, p.55 and IR 28, P The Gas Utility Act defines a gas utility as the following: means a person that owns and operates in British Columbia equipment or facilities for the production, generation, storage, transmission, sale, delivery or furnishing of gas for the production of light, heat, cold or power to or for the public or a corporation for compensation National Energy Board Act. Since the Gas Utility Act clearly defines the business model of a gas utility and parameters within which TGVI has a monopoly and expertise, why is it now appropriate to leverage that monopoly position to enter in the alternate energy competitive space to compete with unregulated businesses and take advantage a utility s lower cost of capital? In the case of TGVI, does not the pursuit of alternate energy projects distract attention from the utility s core business and result in poor performance for its core function and an overall higher risk profile for the utility as equipment breakdowns and cost overruns inevitably occur with unproven technology? This question contains elements from a number of earlier IRs, including BCUC IRs , , and , of the TGI RRA proceeding and TGVI IR This response contains components of all these previous responses. TGVI respectfully notes that there are a number of inaccurate statements in the question above, which TGVI will respond prior to responding to the last sentence in the question. First, the Gas Utility Act does not define the business model of a gas utility or the parameters within which TGVI has a monopoly and expertise. The Gas Utility Act does not speak to whether or not a "gas utility" can or cannot own and operate heat delivery services or become a provider of energy rather than natural gas alone. Therefore, TGVI s intention to own and operate the heat delivery service or to become a provider of energy rather than natural gas alone is compatible with the Gas Utility Act. Second, the question appears to cite competitive issues as a basis for opposing TGVI s initiatives in the area of alternative energy solutions. The Commission derives its jurisdiction over public utilities from the Utilities Commission Act, a provincial statute. The Commission has no jurisdiction over competition, which is a Federal mandate under the Constitution of Canada. The Commission would exceed its jurisdiction, and make an error in law, by seeking to preclude TGVI from pursuing alternative energy solutions on that basis. Third, leaving aside the legal issue regarding the Commission s lack of jurisdiction to regulate competition, there is an assumption imbedded in the question that TGVI will be able to leverage

17 Page 16 a lower cost of capital, and also that other entities engaged in alternative energy solutions have a higher cost of capital. These are not safe assumptions. As all providers of alternative energy solutions will be regulated by the Commission (discussed below), it will be the Commission that will set the return on equity and approve the debt rates incurred by the Company and all other providers. Moreover, the participants in the area of alternative energy solutions that would be competing for customers include significant players in the market such as Corix, EPCOR, Dalkia and Enbridge. Fourth, the question incorrectly assumes that other providers of alternative energy solutions would be unregulated. In fact, the provision of alternative energy solutions of the nature being pursued by TGVI, regardless of the entity that pursues them, will be regulated by the Commission. The definition of "public utility" is what defines the entities over which Commission's jurisdiction extends. The definition of "public utility" in the Act is, in part: "public utility" means a person, or the person's lessee, trustee, receiver or liquidator, who owns or operates in British Columbia, equipment or facilities for (a) the production, generation, storage, transmission, sale, delivery or provision of electricity, natural gas, steam or any other agent for the production of light, heat, cold or power to or for the public or a corporation for compensation " [Emphasis added.] The alternative energy solutions such as solar thermal, GSHP, and DES produce heat that is to be provided "to or for the public or a corporation for compensation. TGVI will own the equipment itself and sell heat to customers at a Commission-approved rate. Further, TGVI is entering into a market where primarily sophisticated industrial or commercial customers will agree to pay a rate to another entity (TGVI or another entity) for the provision of heat from a district energy, geothermal or solar thermal solution rather than invest themselves in the development of the necessary infrastructure to self-supply. In other words: TGVI is not proposing to become involved in the sale of or supply of equipment, nor does TGVI believe that the sale of alternative energy equipment and systems should be regulated by the BCUC. Customers purchasing such equipment self-supply their own heat or electricity and are not public utilities under the Utilities Commission Act. This ownership and operation of the facilities required to deliver energy to the end use customer also distinguishes the TGVI model for providing alternative energy solutions from that of the supplier of gas commodity to transportation customers. This question, like many other BCUC information requests issued in the TGI proceeding, reference the term monopoly. Neither the term "monopoly", nor "competition" appear anywhere in the Utilities Commission Act, and are not the concepts that determine whether an entity is subject to regulation by the Commission. While the Commission's jurisdiction is not defined by whether or not a service is subject to competition or whether it is a monopoly, the scope of the definition of "public utility" is consistent with protecting customers from the exercise of monopoly power by third party providers of energy. The owner or operator of an alternative energy

18 Page 17 system, who sells energy from that system to end users for compensation (as TGVI proposes to do), is appropriately captured by the definition of "public utility" because it is capable of exercising "monopoly" market power in respect of its customers. Put another way, although there is more than one company that could enter the market to install, own and operate geothermal, solar thermal and district energy systems, and charge a rate to other customers, one must consider the position of the customer once the equipment has been installed and the customer is dependent on that system and the third party provider for energy. The customers that receive services such as space and water heating from another entity will be effectively captive to the rates charged by the entity owning the infrastructure for the life of the contract and, likely, the life of the assets. With respect to district energy system serving a community, for example, TGI or another provider selected by the consumer would have an effective monopoly over the provision of heat to the customers in the community. Customers may come and go from the community, but each would be receiving energy from TGVI s installed district energy system. It is exactly this type of service that the Commission is bound to oversee in the public interest. In this sense, the customer that obtains heat energy from a third party owner of geothermal, solar thermal and district energy systems is in the same position as an electricity customer of BC Hydro, a gas customer of TGVI, a resident of Dockside Green (a regulated public utility providing heat energy produced from a district energy system similar to those being advanced by TGVI) or Gateway Village (a propane-based district energy system), or a customer of a host of other entities providing energy services in British Columbia. This point can be illustrated by example. British Columbians living in the service area of TGVI and BC Hydro, for instance, usually have a choice between gas and electricity for space heating. Gas and electricity compete for those customers. However, the existence of this competition for customers does not mean that BC Hydro and TGVI are not monopolies and should be unregulated. One reason is that once a customer has made a choice of electricity or gas for space and water heating, either BC Hydro or TGVI will have an effective monopoly on serving that requirement unless the customer elects to leave the system and incur capital costs to install another type of heating system 1. A municipality or hospital that obtains heat from a third party owner of its district energy system (such as Central Heat), but is still located within BC Hydro and TGVI's (gas) service area will still have the choice to switch from its district energy system to competing offerings such as gas or electricity, but there may be sufficient impediments to making that change to discourage leaving the district energy system even in the face of unjust or unreasonable rate increases. Regulation of the rate charged by district energy system is thus an important aspect of consumer protection. TGVI's proposal is to submit a negotiated contract to the Commission for approval as the terms and conditions of service by the utility. 1 It should be noted that switching to electric space heating from other energy sources is easier and much less expensive than converting from electric space heating to other energy sources such natural gas or alternative energy systems. For example, a natural gas-heated home can be partly or fully converted to electric space heat using portable plug-in heaters, electric plenum heaters or baseboard heaters. On the other hand retrofitting a building that is electrically space heated with ductwork or a hydronic system to facilitate using natural gas or alternative energy as a heat source is more complex and expensive.

19 Page 18 Rates in this case, the gas rates and the rates payable by alternative energy customers - must be just and reasonable and not unduly discriminatory. The Commission, in determining just and reasonable rates, must determine the appropriate allocation of costs as between gas customers and customers of the alternative energy solutions. The proposed economic tests are an efficient means of addressing cost allocation issues, modeled on the existing Main Extension (MX) test and previously accepted cost of service tests. The approval of economic tests will facilitate TGI negotiating just and reasonable alternative energy rates in the form of individual contracts entered into with individual customers and filed with the Commission. It is important to note, however, that with or without the economic tests for which approval is being sought, TGI believes that it would be possible for TGI to file individual contracts with customers for the provision of alternative energy solutions for approval as a rate. While this approach is equally valid and permissible under the Utilities Commission Act, it is a less efficient approach because it would be necessary for the Commission, intervenors and TGI to address cost allocation issues as between the new customer and other (gas) customer s classes each time a contract is filed. Fifth, TGVI also disagrees with the characterization of this technology as unproven technology. Both discrete and district energy systems can use technology that, while new and innovative, is not unproven. Geo-exchange and solar-thermal energy technologies are examples of known and proven technologies that can be employed in both discrete and district energy systems. District energy systems are not new and unproven by any stretch of the imagination as these are prevalent in Europe and are already seen in BC (for example Central Heat, Dockside Green and Lonsdale Energy Corp.). TGVI also respectfully suggests that even if the technology were unproven, which it is not, the statement that unproven technology inevitably results in breakdowns and cost overruns is a gross over-generalization. Having addressed the incorrect premises embedded in the question, TGVI will address the question of whether TGVI provision of alternative energy solutions will distract TGVI from its core business. TGVI does not believe that its decision to invest time in alternative energy solutions will distract from the core business. The vast majority of TGVI s resources and time will, for the foreseeable future, continue to be dedicated to its core business. For most of the Company this will be business as usual. For those areas of the business that are involved in the provision of alternative energy solutions, TGVI believes that rather than distract from its core business, providing alternative energy solutions will enhance its core business. By providing both gas and alternative energy solutions, TGVI is better able to meet the needs of customers and as such will have more of an opportunity to influence and encourage the use of gas in the right application. As such, providing alternative energy services will help to add natural gas load, that would not have otherwise occurred, rather than reduce natural gas load and as such this offering will not detract from the utilities core business.

20 Page Reference: Customer Care Activities Billing Accuracy Exhibit B-1, Part III, Section A, p. 81, par.4 Exhibit B-4, BCUC IR Customers can take their own readings on a monthly, weekly, daily or hourly basis and record these for their own analysis. 9.1 Are actual readings done on the start and end of service? Are estimates used and if so, what is the maximum number of days usage that is estimated. TGVI does not provide on-demand manual move-in or move-out readings when a new customer begins or ends service at a particular location. If the service start or end date coincides with a scheduled manual read, that read will be used. TGVI also accepts customerprovided readings when starting or ending service. In cases where a manual or customer meter reading is not available, TGVI will estimate the start or end reading from the last available actual meter reading using the prior consumption history for the location. Actual reads are scheduled every second month and typically, the maximum number of days that would be estimated if an estimate is required is 60 days. 9.2 Does Terasen allow customers to read their own meters and provide this data to Terasen for use in the billing process? Yes. All Terasen Utilities, including TGVI, allow customers to provide meter readings for use in the billing process. For those customers who desire to read their meters each month, meter reading schedules are provided.

21 Page What manual meter reading schedule will Terasen use when the current arrangement including BC Hydro ends? The Company is evaluating potential options related to meter reading, including manual and automated alternatives, for when the current joint manual meter reading arrangement ends. TGVI is aware of the legislative requirement faced by BC Hydro to implement advanced metering before the end of TGVI anticipates any change to the current manual meter reading arrangement would occur after the 2010/2011 period considered in this Revenue Requirement Application.

22 Page Reference: Aboriginal Rights - Complexities Ex. B-4, BCUC IR No First Nations in TGVI Service Area 10.1 The list of First Nations, Bands, and Councils provided in response to IR# has several names underlined. What is the significance of the underlined names? There is no significance to the underlined names in the list. The underlining was a formatting error.

23 Page Reference: Energy Efficiency and Conservation and Alternative Energy Solutions Exhibit B-4, BCUC IR Alternative Energy Services Costs BCUC TGI IR , 44.0, 52.0, In BCUC 66.0, TGVI indicates that The only costs expensed and charged to rates for alternative energy services to date relate to high level strategy and business planning by senior TVGI employees and the costs associated with this Application The original IR question refers to the costs associated with the above TGVI statement. Please identify and breakdown the costs expensed to date (i.e. engineering studies, feasibility studies, market / customer research, etc.) and discuss whether these costs (relating to Alternative Energy Services) should be included in Account 172. The original questions do not refer to future / potential costs associated with Alternative Energy Services. This question is identical to TGI RRA BCUC IR This response is similar to the TGI response to that IR; however some minor differences were necessary in order to respond appropriately for TGVI. The definition for Account 172 is as follows: All expenditures for preliminary surveys, plans, investigations, etc., made for the purpose of determining the feasibility of projects for gas services, and with the costs associated with applications for certificates of public convenience and necessity, board hearings, the acquisition of options to purchase land or land rights to provide a future supply of natural gas, easements and similar items for use in contemplated projects, unless these costs are being tracked separately in another deferral account. The only costs to date spent on market/customer research are those studies that were subsequently presented as supporting evidence to IRs asked in the TGI RRA proceeding. Two studies were provided in response to TGI RRA BCUC IR and the study provided in response to TGI RRA BCUC IR The total cost for these studies is $28,812 including tax. TGVI would receive its share (approximately $2,800) of the costs for these studies through the provisions of the shared services agreements. In TGVI s view, account 172 is intended to capture the engineering/technical side of surveys, plans and investigations into providing gas service. As the nature of the studies undertaken by

24 Page 23 TGI are related to general research of other companies approaches to alternative energy, and research on customer knowledge levels and opinions regarding alternative energy, and are not associated with engineering/technical surveys etc or specific projects, TGVI does not believe that these costs should be included in Account Section 60, item (II) of the Utilities Commission Act requires the Commission, in setting rates, to have due regard to a rate that: encourage public utilities to increase efficiency, reduce costs and enhance performance Is it not the primary mandate of the Commission to maintain the lowest utility rates possible while the Commission must only consider the government s energy objectives and the most recent long term resource plan filed by the utility when it considers applications under section 46 and 71 of the Utilities Commission Act? This question is identical to TGI RRA BCUC IR This response is similar to the TGI response to that IR; however some minor differences were necessary in order to respond appropriately for TGVI. Two cross-referenced IR responses from the TGI RRA proceeding, not otherwise on the record in this proceeding, are appended to this response for completeness. There are two assertions made in the question, and the Company will respond to each, in turn. The first assertion is that the primary mandate of the Commission is "to maintain the lowest utility rates possible". TGVI disagrees with this assertion for the reasons addressed in TGI RRA BCUC IR (appended below). Just and reasonable rates require the Commission to consider all of the factors identified in the UCA, and "the lowest utility rates possible" is not one of those factors expressly or implied. The second assertion is that the Commission must only consider the government's energy objectives and the most recent long-term resource plan filed by the utility when it considers applications under sections 46 and 71 of the Utilities Commission Act. The emphasis on "consider" in the question is accurate, as TGI stated in the response to TGI RRA BCUC IR (extract attached below). TGI noted in that response that other factors such as the impact on customer rates will also be relevant considerations. We believe that the requirement to consider the government s energy objectives means that serious attention is to be given to the issues. TGVI notes, however, that the question does not cite all of the sections to which government's energy objectives apply. The requirement to consider government's energy objectives applies in respect of the CPCN provision (sections 45 and 46), the expenditure schedule provision (section 44.1), the long term resource plan (section 44.2) and the supply

25 Page 24 contracts provision (section 71). In the absence of a streamlined regulatory process proposed in the Application, biogas upgrading facilities would be governed by the CPCN provision. The energy supply contracts would be governed by section 71. Thus, the Commission must consider government's energy objectives, even where the biogas supply is more expensive than traditional gas supply. TGVI is currently developing a green rate and, when in place, TGVI expects that it will recover 100% of the costs. Thus, the green rate will result in the recovery of cost of service from consumers of biogas, further reinforcing the fairness of the rates. TGI RRA BCUC IR (Exhibit B-12, pages ) 70.0 Reference: Energy Efficiency and Conservation and Alternative Energy Solutions Exhibit B-4, BCUC , p.100 Definition of Core Business Service TGI states that: As noted in response to BCUC , the Utilities Commission Act does not prohibit TGI from providing alternative energy solutions, nor does it give the Commission jurisdiction to prohibit this activity Section 60, item (III) of the Utilities Commission Act requires the Commission, in setting rates, to have due regard to a rate that: encourages public utilities to increase efficiency, reduce costs and enhance performance. Why does the Utilities Commission Act not give authority to the Commission to prohibit TGI from providing alternate energy solutions as it is the Commission s mandate to apply regulation to ensure safe, efficient and reliable service at the lowest cost? TGI respectfully disagrees that section 60(1)(iii), or any section in the Utilities Commission Act, requires the Commission to ensure service is provided "at the lowest cost". The Utilities Commission Act does not expressly or implicitly require rates to be set "at the lowest cost". Section 60(1)(iii), cited in the preamble of this information request, is not the only factor that the Commission must consider in setting rates Section 60(1) states: Section 60(1) In setting a rate under this Act or the regulations (a) the commission must consider all matters that it considers proper and relevant affecting the rate,

26 Page 25 (b) the commission must have due regard to the setting of a rate that (i) is not unjust or unreasonable within the meaning of section 59, (ii) provides to the public utility for which the rate is set a fair and reasonable return on any expenditure made by it to reduce energy demands, and (iii) encourages public utilities to increase efficiency, reduce costs and enhance performance. Section 59(5) provides further explanation for what "unjust" and "unreasonable" mean: Section 59(5) In this section, a rate is "unjust" or "unreasonable" if the rate is (a) more than a fair and reasonable charge for service of the nature and quality provided by the utility, (b) insufficient to yield a fair and reasonable compensation for the service provided by the utility, or a fair and reasonable return on the appraised value of its property, or (c) unjust and unreasonable for any other reason. A lowest cost approach to interpreting the Commission s jurisdiction under these provisions of the Utilities Commission Act is inconsistent both with the Commission s previous determinations in carrying out its mandate and guidance from the Courts. As stated in the Commission s Decision dated March 2, 2006 in the Matter of TGI and TGVI s Application to Determine the Appropriate Return on Equity and Capital Structure and to Review and Revise the Automatic Adjustment Mechanism (the ROE Decision ) (at page 7): The Commission s mandate is to ensure that ratepayers receive safe, reliable and non-discriminatory energy services at fair rates from the public utilities it regulates, and that shareholders of those public utilities are afforded a reasonable opportunity to earn a fair return on their invested capital. The process to establish a fair return and just and reasonable rates is enshrined in the UCA where the commission must consider all matters that it considers proper and relevant affecting the rate and in doing so it must have due regard to the setting of a rate that is not unjust or unreasonable within the meaning of section 59 (of the Act) [UCA, s.60 (1)(a) and (b)(i)].

27 Page 26 In the ROE Decision, the Commission rejected (at page 8) the argument that lowest possible was the appropriate test for the Commission to apply. The ROE Decision quotes Martland J. of the Supreme Court of Canada in B.C. Electric Railway Co. Ltd. v. Public Utilities Commission of B.C. et al [1960] S.C.R. 837, who stated: The rate to be imposed shall be neither excessive for the service nor insufficient to provide a fair return on the rate base. As a final example, in the context of sections 45 and 46 of the Utilities Commission Act, the Commission has stated: The task is not to select the least cost project, but to select the most cost-effective project. (Decision dated July 7, 2006 on BCTC s Application for a Certificate of Public Convenience and Necessity for the Vancouver Island Transmission Reinforcement Project, at page 15.) While the Commission was not addressing rates specifically, the project costs approved as part of a CPCN application ultimately get recovered in rates and thus the same analysis logically applies to rate setting. TGI believes that the pursuit of alternative energy solutions will result in the existing assets being used more efficiently and can reduce costs for existing gas customers in the long term. (Please see TGI s responses to BCUC IRs and ) The pursuit of alternative energy solutions also provides a contribution to overhead, advances environmental objectives and the government s energy objectives set out in the Utilities Commission Act. TGI believes that these are "proper and relevant" factors to consider in establishing just and reasonable rates. Under TGI s proposal, alternative energy contracts will be filed and approved by the Commission as rates, and those rates will each recognize the cost of providing the alternative energy service to the particular customer. At the same time, gas rates set by the Commission will continue to recognize the cost of providing core gas service to gas customers. As such, TGI believes the rates for its alternative energy solutions will be fair and non-discriminatory. In sum, TGI believes that the pursuit of alternative energy solutions is in the interest of present and future customers and intends to pursue safe and reliable alternative energy solutions in furtherance of that objective. Existing and future customers benefit from the Commission's approval of just and reasonable rates for gas service and for the provision of alternative energy. The proposed economic tests for alternative energy solutions will simply make the approval of contracts administratively more efficient.

28 Page 27 Extract from TGI RRA BCUC IR (TGI RRA Exhibit B-4, pages 62 and 63) This focus on utilities playing an integral role in the delivery of alternative energy solutions is reemphasized in the inclusion of government s energy objectives in the Utilities Commission Act. Biogas upgrading projects advanced by TGI would normally be subject to obtaining a CPCN (although the capital cost of individual biogas projects is expected to be below the proposed CPCN threshold and TGI is proposing an economic test to encourage administrative and regulatory efficiency), and government s energy objectives must be considered by the Commission with such projects. The government s energy objectives include two objectives that directly support a public utility like TGI advancing biogas upgrading: (i) to encourage public utilities to use innovative energy technologies that support energy conservation or efficiency or the use of clean or renewable sources of energy, and (ii) to encourage public utilities to reduce greenhouse gas emissions. Biomethane is a clean and renewable source of energy provided through the development of innovative technology, and its use will encourage public utilities to reduce greenhouse gas emissions. TGI therefore believes that the Commission, through its regulation of TGI in the manner proposed in this Application, should be encouraging TGI to pursue it. While government s energy objectives must be considered in conjunction with other factors, such as the impact on customer rates, TGI believes that it has appropriately addressed rate impact in its proposal. Some investment is required at the pilot phase, but the limited scope of the pilot means that the rate impact is negligible. At the same time, existing and future gas customers stand to benefit from a successful pilot. TGI has stated in the Application that its intention is to develop a green rate that recovers the incremental cost from customers with a desire to purchase biomethane. The availability of this green service has the potential to retain and attract customers that will contribute to the overall system costs for the benefit of all customers. Thus, TGI believes in the circumstances that it has an important role in advancing the development of biogas and biogas upgrading as a resource in BC, and the proposal in the Application will help to advance that government-sanctioned objective Will TGVI be tracking the sales efforts, account management, market development costs, and revenues for Alternative Energy and reporting them separately? If not, how will TGVI know the appropriate overhead allowance is sufficient?

29 Page 28 This question is identical to TGI RRA BCUC IR This response is similar to the TGI response to that IR; however some differences were necessary in order to respond appropriately for TGVI. Please see TGVI s response to BCUC IR and the response to TGI RRA BCUC IR (appended below). As noted in the Application TGVI will be tracking revenues from alternative energy as these will be captured in the deferral accounts. TGVI is proposing to use an initial overhead allocation of 5%. TGVI will be tracking sales efforts, account management and market development costs so that TGVI can better understand all costing regarding alternative energy and therefore arrive at appropriate overhead allocations. TGVI proposes to review the allocation as it gains more experience in alternative energy systems for the purposes of considering whether or not the percentage should be changed. Response to TGI RRA BCUC IR Reference: EEC and Alternative Energy Exhibit B-4, BCUC Utility System Extension Test Guidelines Rates and Economic Test Therefore, the Commission recommends that the Utilities develop a DCF based system extension test and submit it to the Commission. The Commission also recommends that, insofar as is practical, the analysis of system extensions be based on full incremental costs and benefits. Moreover, in reviewing system extension filings, the Commission will consider the time period of the analyses and the extent to which the costs of a system extension are allocated to those customers who cause them. (Utility System Extension Test Guidelines, p. 12) Also, TGI believes that the sales and marketing expenditures included in the Application related to developing the alternative energy business are more general in nature than the preliminary investigation costs contemplated for Account 172. (Exhibit B-4, BCUC 21.2) 40.1 Has TGI performed a study to determine the full incremental costs of providing service to alternative energy customers?

30 Page 29 TGI has not performed a study to determine the full incremental cost of providing service to alternative energy customers. TGI has noted in its response to BCUC IR that alternative energy projects will be characterized by a high degree of uniqueness. There will be differing energy sources (such as geoexchange, solar thermal, biomass, etc. with natural gas backup) in various combinations and a variety of end users (residential, commercial, institutional, industrial, etc.) that are also unique to a particular alternative energy development. The configuration of alternative energy projects will therefore be customized to the particular local requirements. As such it is very difficult to assess through a study what the incremental costs are for such service. The overall costs of such service will be limited by what customers are willing to pay for the benefit they are receiving from the service. However, until TGI has had time to evaluate the incremental costs associated with providing alternative energy service, TGI proposes to use an overhead allowance of 5% of the capital cost of the alternative energy solution included in the COS (similar to that proposed for the NGV CS Test). For example a DES system with a capital cost of $15 million would have $0.75 million overhead added. If TGI were to get four projects of this size per year, the overhead allowance would exceed the $3 million request for incremental funding for sales, market development and account management activities. TGI proposes review the allocation as it gains more experience in alternative energy systems for the purposes of considering whether or not the percentage should be changed Please explain if it is not appropriate to track all costs associated with the development of alternative energy projects for recovery through rates specific to those projects. This question is identical to TGI RRA, BCUC IR This response is similar to the TGI response to that IR; however some differences were necessary in order to respond appropriately for TGVI.

31 Page 30 TGVI believes that it is unnecessary and impractical to track all costs as separate costs as suggested in the question. As noted in the response to BCUC IR , TGVI does not at this time know the percentage of certain costs, such as marketing and sales costs (which come into the TGVI cost of service through the shared services fee), that will be attributable to alternative energy projects. Going forward, TGVI will be offering both natural gas solutions, alternative energy solutions and solutions that include both applications. As part of the selling process for these solutions, there will be projects in which TGVI is successful and those in which it fails. As such there will be costs that are not attributable to any specific project, i.e., those for projects that do not go forward. There will also be costs in which, due to the involvement of gas in the solution, it will be very difficult to determine what portion of time was spent on the alternative energy part of the solution. Lastly, for existing gas customers, TGVI does not track sales, account management and market development costs associated with specific services or projects and does not charge natural gas customers different rates based upon these costs. Rather, TGVI believes that the most appropriate means of addressing common costs is to use an initial overhead allocation of 5% of the value of alternative energy projects. Additionally TGVI will perform an allocation exercise for each alternative energy project as it does for natural gas services today. This will result in tracking of overhead allowances from which TGVI can better understand the true overhead allocation for alternative energy projects. As TGVI gains more experience in alternative energy systems and as it better understands the allocation of overheads, it may change the overhead allocation percentage. Note that once a project is fully defined and it has been determined that it will move ahead then project development costs can and will be tracked for discrete alternative energy projects, such as District Energy Systems, and those costs will be charged against that project. The means by which common costs are proposed to be addressed in this Application is appropriate and sufficient to ensure that rates for both gas and alternative energy customers are just and reasonable.

32 Page Reference: EEC and Alternative Energy Exhibit No. B-4, BCUC IR 69, pp Incentives promoting the adoption of innovative technologies 12.1 The table presented as part of the response to BCUC IR 69.5 shows TRC s for each of the innovative technologies for which TGVI proposes offering incentives. All of these TRC s are considerably below 1.0 in both 2010 and Also in the response, it states that: Although the TRC of some of the technologies in this program area is not favourable today, these future environmental benefits must be considered. As with all new technologies, initial costs are prohibitive to most consumers. However over time market share for these new technologies increases and costs for them come down How many years of providing incentives for each of the identified technologies (at the requested level of funding) does TGVI expect will be required before the TRC ratios associated with these incentives approach 1.0? TGVI cannot presently provide an answer to this question. Any attempt to provide this forecast without the ability to analyze and evaluate real data would be speculative on our part. TGVI proposes the Innovative Technologies programs be run as pilots, in order to obtain data that would allow the Company to forecast such information as outlined in this request At the level of incentives proposed, by what percentage must the material and installation costs for each of the identified technologies be reduced by before the resulting TRC ratios equal 1.0? At the proposed incentive levels the material and installation costs for each of the identified technologies must be reduced by the following percentages to achieve a TRC ratio of 1.0. Hydronic baseboard systems the material and installation costs require a 73% reduction. For example: Hydronic baseboard costs must be reduced from a total of $2053 (participant cost $1500 & Utility incentive $553) to $653 (participant cost $100 & Utility incentive $553). Hydronic underfloor Systems reduced material and installation costs will never achieve a TRC of 1.0 while maintaining the current proposed incentive level.

33 Page 32 Combination Systems reduced material and installation costs will never achieve a TRC of 1.0 while maintaining the current proposed incentive level. Ground Source Heat Pump the material and installation costs require an 89% reduction. Solar thermal hot water the material and installation costs require an 81% reduction. Although the TRC for the technologies in these pilot program areas is not favourable today, the current and future environmental benefits must be considered. TGVI believes that by providing incentives for these technologies, we are promoting future proofing of buildings with space and water heating systems that enabled the integration of these in-building systems with District Energy or other energy sources as they become available. The systems are easily adapted to be combined with one or more other energy sources to create a hybrid system. An example is adding a solar thermal pre-heat system for domestic hot water to an exiting building heated by a hydronic underfloor system. This combination of technologies can be integrated with the addition of a large water storage tank (thermal mass tank). During the summer the hybrid system would then be able to store excess heat created by the solar thermal system in the thermal mass tank. This stored heat would supplement the hydronic underfloor system space heating needs during the winter months. The solar thermal aspect of this system will also continue to provide some energy to the thermal mass storage tank through the winter months. The next phase of integration of this type of system would be to tie the thermal mass tank into a district energy system. The solar thermal component would supply excess heat not only to the thermal mass tank, but to the entire district system, helping to minimizing the need for energy from non-renewable sources. This type of integration would not be possible in buildings that do not utilize hydronic systems Please provide a 10 year forecast of the TRC ratio associated with the overall innovative technology program area along with all of the assumptions used to develop the forecast. TGVI cannot presently provide the information sought. Any attempt to provide this forecast without the ability to analyze and evaluate real data would be speculative on our part. TGVI proposes the Innovative Technologies programs be run as pilots, in order to obtain data that would allow the Company to forecast such information as outlined in this request.

34 Page On page 165 it states: As with all Energy Efficiency and Conservation programs, we will closely monitor incentive levels and adjust accordingly while also evaluating the TRC levels to ensure that there is customer uptake and the overall aggregate TRC levels meet the aggregate threshold Please provide details regarding steps that TGVI has taken, or is planning, to assess and monitor the actual TRC ratios associated with each of the innovative technologies for which TGVI is proposing incentives throughout 2010 and Please provide examples of the metrics and reporting formats that TGVI will be relying upon to: i. Assess the resulting energy savings; ii. Provide ongoing feedback, and corrective and constructive guidance regarding the implementation of programs in order that they can be improved; and iii. Assess whether there is a continuing need for the programs, and justify the assessment. TGI believes that appropriate metrics and monitoring will be in place. This response first addresses metrics, followed by a discussion of monitoring and evaluation. Metrics: In the case of retrofit installations of innovative technologies, it is TGVI s intention to compare consumption data pre- and post-installation of the new technologies. In the case of new construction, energy consumption would be compared to like buildings within the same geographical area to assess the resulting energy savings. Monitoring, reporting and evaluation: During the pilot phase, TGVI will monitor program up-take and make necessary adjustments to ensure the programs are achieving the desired response. Both program participants and Innovative Technology providers will be surveyed to assess the performance of the programs and make necessary changes to ensure the programs remain on track. A system will be in place for participants and Innovative Technology providers to provide immediate feedback to TGVI. Based upon feedback and surveys received from the market during the pilot phase, we will be able to make adjustments to the programs, and use lessons learned in successful pilot programs in the design phase of full programs prior to launching them into the general market.

35 Page 34 Staff will also use the results of the pilot programs to determine if the data shows a pilot program should be ended and not launched into the general market. Staff will use the results of the pilot programs to determine if there is justification for going forward with the program taking into consideration such measures as level of market transformation, level of energy savings, changes to the total resource cost ratio resulting from decreasing capital and installation cost of the technology, and the size of the potential market. In terms of reporting, the Terasen Utilities are implementing a Demand Side Management System (DSMS) which will provide a central point for data collection and integration with the Terasen Utilities financial system reporting for 2010 and beyond. Staff will input the Innovative Technologies pilot program activity into DSMS to track and monitor program activity and utilize DSMS reports extracted from the system to analyze program performance. At this point, the Terasen Utilities anticipate that reports will be exported from the DSMS in Excel format Under what conditions would TGVI consider increasing its expenditure on these incentives? TGVI believes the requested budgets for innovative technologies as well as the incentive levels to be sufficient to ensure expected participation level is reached. TGVI would consider increasing an incentive over the amount set out in the Application for under-participated Innovative Technologies programs, but would only do so following an assessment of the following considerations: The innovative technology associated with any underperforming program would be reexamined by TGVI technical experts and (as necessary) external technical consultants to assess the potential for long term savings and energy reduction of that technology or technologies in the current marketplace. External factors beyond the control of TGVI would be taken into consideration (e.g. global financial downturn, uncharacteristically low natural gas and/or electricity prices, diminished housing starts, etc.).

36 Page Under what conditions would TGVI consider reducing or eliminating its expenditure on these incentives? TGVI believes that the requested budgets for innovative technologies as well as the incentive levels are sufficient to ensure the expected participation levels are reached. TGVI would consider reducing its expenditures on Innovative Technologies programs in the following circumstances: TGVI has determined that the innovative technology has sufficiently proven itself in the current marketplace (market transformation has occurred) and that further monetary incentives would only be taken up by free riders. There are no temporary external factors that, once expired, would jeopardize the advancement of the affected new technology in the marketplace if the in-place incentive were to be removed. A Federal or Provincial Government mandate to use the technology may eliminate the need for the TGVI incentive. The technologies showed no sign of becoming cost effective, or the technology becomes obsolete due to new technologies entering into the market Please indicate whether TGVI currently has the necessary in-house human resources to design and implement an evaluation, measurement, and verification process of the proposed innovative technology incentive program. This question is identical to TGI RRA BCUC IR This response is similar to the TGI response to that IR, however some minor differences were necessary in order to respond appropriately for TGVI. The Company recognizes the importance of evaluation in considering the effectiveness of EEC programs, and is aware that the increase in EEC budgets with Decision G will result in an attendant increase in focus from the Commission and Intervenors on evaluation. Staff development and training on all aspects of EEC, including evaluation, measurement and verification, will be a major focus for the new EEC staffing structure. The hiring process for the new EEC staffing structure was completed in August 2009, and a two and a half day DSM 101

37 Page 36 seminar, which included a module on evaluation, was presented to new and existing EEC staff. There are a number of other resources on which the Company intends to draw in the development and training of EEC staff on all aspects of DSM, such as energy efficiency industry conferences, brown bag lunches, webinars and discussions and collaborations with other utilities. There is a conference dedicated to program evaluations, the International Energy Program Evaluation Conference ( that will likely be a good resource for the development of program evaluation skills. The responsibility for developing the program evaluation process at the time of program development will rest with the Residential, Commercial and Low Income Housing Program Managers, and the plan for program evaluation will form part of the overall program plan that is presented to Senior Management for their review and approval. Terasen has used outside consultants to conduct major evaluations, and TGVI expects to do so in the immediate future. The initial evaluation projects will be structured such that TGVI staff will work along side of the consultants in order to obtain a transfer of skills. Some programs will be conducted in conjunction with other utilities on a joint basis. In the case of these programs, one evaluation would be undertaken for the program on behalf of all the participating utilities, and a decision would be made between the partners who would lead the evaluation, with support in terms of data and funding from the partners. The Company anticipates that this will also result in a transfer of skills between utilities. Thus TGVI anticipates that Terasen Utility staff will develop in-house capabilities to design and implement an evaluation, measurement and verification process.

38 Page Reference: EEC and Alternative Energy Exhibit No. B-4, BCUC IR 69.5, pp Incentives promoting the adoption of innovative technologies 13.1 Would TGVI agree that the recipients of incentives offered by TGVI for the adoption of the innovative technologies identified in the table on page 167 of Exhibit B-4 are early adopters of these technologies who are motivated by considerations other than cost (such as environmental considerations)? TGVI agrees that factors such as environmental considerations, future energy savings, and government policies are spurring early adoption of emerging technologies. We believe a number of early adopters may invest in technologies despite incentives, if they have the financial means available to them. Further, in response to BCUC IR , the Ipsos Reid study demonstrated that customers would be willing to pay more for alternative energy. However, TGVI believes incentives must still be offered to those who cannot afford technologies and thus rely on financial assistance to obtain these technologies. Free ridership was not factored in to the Innovative Technologies TRC calculation represented in the table on page 167 of Exhibit B-4. Since these are pilot programs and not open to the greater market, TGVI believe free ridership will be minimized. TGVI will be able to closely monitor applicants and limit who will be accepted to participate in the pilot programs. We also believe that the majority of early adopters will have invested in these technologies prior to TGVI implementation of the pilot programs and that, therefore, the applicants wishing to participate in the pilot programs will be motivated by the opportunity to participate and the incentive we are offering If the answer to the previous question is yes then would TGVI expect a higher free ridership rate associated with these incentive programs as compared to various energy efficiency programs implemented since 2005? Please see the response to BCUC IR

39 Page How will TGVI assess the free ridership rate associated with offering incentives promoting the adoption of innovative technologies? Free rider rates are challenging to determine with any accuracy and TGVI uses several different approaches to ensure that the rates used reflect as closely as possible the actual ratio of participants who are free riders. In cases where TGVI has operated a program which has been evaluated (such as our Energy Star Heating Upgrade Program which was evaluated for the program years by Sampson Research in 2008) the free ridership rate from the Sampson evaluation has been used. In the evaluations, the free riders rate has typically been determined by a combination of information from: a customer survey; a trade ally survey; and in some cases by discrete choice analysis modeling using participant and non-participant data.

40 Page Reference: EEC and Alternative Energy Exhibit No. B-4, BCUC IR 69.5, pp Incentives promoting the adoption of ground source heat pumps 14.1 Does the calculation of the TRC ratio associated with incentives provided for the adoption of ground source heat pumps reflect the cost of the additional electricity consumed by this system, as compared to by a traditional natural gas furnace? If so, do the costs reflect the carbon content of electricity generation as provided by BC Hydro? No, the additional electrical consumption was not factored in the initial version presented in the TGI and TGVI Information Requests. This was an oversight on the part of the Terasen Utilities. The calculation has been performed again, factoring the additional electricity consumed by a GSHP system, resulting in a change to the TRC from 0.1 to 0.0. Although generated electricity has 0.03 kg/kwh of C02e 2, had the electricity consumed by this system been factored into the TRC calculation, there would not be any additional cost related to the carbon content of generated electricity. Although at least 15 per cent of electricity consumed in BC is imported from coal and gas fired power generation 3 plants, it is not subject to the same Carbon Tax that applies to the end users of natural gas. As more and more heating systems are installed with electricity as either the primary or backup source of energy, smart grid management will be difficult to introduce and manage without having systems on the grid that have the ability to utilize other energy sources such as natural gas during peak capacity times. Without this ability to switch based on grid capacity, BC Hydro will have no other option but to import more electricity from inefficient coal and gas fired plants. Factoring transmission losses and generation plant efficiencies, importing power to provide backup for such technologies as GSHP is not the optimal solution for British Columbians If the answer to the previous question is no then please explain why. Please see the response to BCUC IR According to: BC Hydro Climate Change Progress Report, September 2000, page According to BC Hydro

41 Page Reference: EEC and Alternative Energy Exhibit No. B-4, BCUC IR 67.2, pp TGI IR 2.57, p. 33 Economic benefit of EEC expenditures 15.1 On page 159 it states: Note that the total resource analysis approach measures the net impacts to an energy system as a whole from undertaking a demand side activity. In other words, the benefits that will accrue as a result of the Terasen Utilities EEC activity will accrue to the energy system in British Columbia as a whole, not just to TGVI as is stated in the Information Request. The benefits will start to accrue once the programs contemplated in the EEC Application start to roll out, which is anticipated to commence in Q Please explain how each of the energy efficiency programs that are contemplated for 2010 and 2011 will be evaluated by providing a description of the framework and details of both the key individual metrics that will be measured or evaluated, and the processes that will be used to monitor and report the activities and outcomes associated with each of the energy efficiency programs. This question is identical to TGI RRA BCUC IR This response is identical to the TGI response to that IR, with the exception of the name change to TGVI. Evaluation of energy efficiency programs was discussed extensively during the EEC proceeding, which approved the energy efficiency expenditures for It was discussed throughout the initial Application, as well as in numerous responses to information requests. The key metric that will be measured is the cost-effectiveness of EEC programs. This will be done on a portfolio basis and the overall EEC portfolio must have a TRC ratio of 1.0 or higher. This is consistent with the approach approved by the Commission in the EEC Decision earlier this year. Program evaluations will be designed in two stages. During the program design phase the program evaluation concept is determined. The primary purpose of this is to understand the data that will be required for the evaluation, and to determine how much of this can be collected during program operation, for example, as part of the incentive application. By doing this development prior to program launch, better quality data can be collected and at a lower cost than if evaluation design is left until the time for the evaluation.

42 Page 41 Once the program has operated for a sufficient period of time 4, an impact evaluation can be undertaken, and the detailed evaluation will be developed. In the past, TGVI evaluations have been conducted by outside consultants who have been selected based on relevant experience and cost. Once selected, the consultant then develops the detailed evaluation plan for review and discussion with TGVI. When the plan has been approved, the consultant typically develops any necessary market research (for example with participants and with the relevant trade allies), conducts the analysis and develops a report. Program Monitoring is the ongoing tracking of program activities, costs and impacts. TGVI is currently implementing an integrated Demand Side Management System (DSMS) to provide a central point for data collection, integration with the TGI financial system, and reporting. Reports on DSM activities and results will be extracted from this system and made annually to the BCUC Please describe in detail the extent to which TGVI will be following the methodology set out in the California Standards Practice Manual to assess the impact of TGVI s energy efficiency programs. What, if any, variations, additions, or omissions to those standards will TGVI be relying upon? This question is identical to TGI RRA BCUC IR This response is similar to the TGI response to that IR, however some minor differences were necessary in order to respond appropriately for TGVI. Please refer also to the response to TGVI BCUC IR above. The California Standard Practice Manual contains information on the Economic Analysis of Demand Side Programs and Projects, commonly known as the California Standards Practice tests. TGVI will be calculating the tests in accordance with these standards with the exception that TGVI will include the BC Carbon Tax as a participant benefit as approved by the BCUC (EEC Decision - Section 3.5 (pp )). For the purposes of assessing the impact of TGVI s energy efficiency programs, which the Company interprets as meaning program evaluation rather than focusing solely on the DSM Economic Tests, the Company will be more closely following the findings from the Final Report of Measurement, Analysis and Reporting Task Force ( MARTF ) of the British Columbia 4 This will vary with the program. For programs that involve heating, it is necessary to have at least one year of post installation experience for an adequate number of participants. In the EEC plan, most impact evaluations are planned for the third year.

43 Page 42 Partnership for Energy Conservation and Efficiency, of which the Commission is a member. At the time of writing, the MARTF report is not finalized for public release, however much of it is based upon the California Energy Efficiency Evaluation Protocols: Technical, Methodological, and Reporting Requirements for Evaluation Professionals (California Public Utilities Commission (CPUC) April 2006). The California document was intended to... guide the efforts associated with conducting evaluations of California s energy efficiency programs and program portfolios... (CPUC, p1), and it is included in Attachment 57.2 in response to TGI RRA BCUC IR As such, it summarizes best practices for program evaluations. For most evaluation areas, the protocols are classed as Basic, Standard and Enhanced. As evaluations move up the scale from Basic to Enhanced, the level of rigor increases, and so does the cost of the evaluation. Once the MARTF report is finalized, the Company will file it under separate cover, however one of the primary questions addressed by the MARTF is the question of the level of evaluation required. The draft MARTF report suggests five guidelines for ex post evaluations to determine the level of rigor, and hence cost, that is appropriate to invest in a specific program evaluation. These are: The program size (in terms of estimated savings or budget) and resulting portfolio risk if size and risk are large, evaluation should be more rigorous. The likelihood of similar programs in the future if more of such programs are expected in future, evaluation should be more rigorous The amount and quality of evaluations for similar programs in BC and other jurisdictions new types of programs, programs with little evaluation data, and programs operating in a new environment (e.g. higher energy prices) should undergo greater evaluation. The level of uncertainty of program savings if larger uncertainty is inherent, evaluation should be more rigorous Cost of evaluation relative to total program operation costs resources will be a constraining factor on the level of rigour. It is the Company s intent to develop evaluation plans and budgets for each EEC program at the same time as the program designs are completed. Evaluation plans will vary by program, depending on such factors as the overall program budgets and projected savings, program complexity, market maturity and others.

44 Page Depending on the answer of the foregoing questions, please indicate whether TGVI has a formulated Evaluation Plan in place or plans to develop one which would: i. Measure energy efficiency program effects as individual and summative evaluations; ii. Assess the source of the effects, and show how the program can be improved by way of a formative or process evaluation; iii. Measure the level of natural gas savings achieved; iv. Measure benefit: cost effectiveness; v. Provide audited evaluation reports; vi. Provide ongoing feedback, and corrective and constructive guidance regarding the implementation of programs; and vii. Serve as assessment tools to determine the continuing need for the programs. This question is identical to TGI RRA BCUC IR This response is identical to the TGI response to that IR, other than the cross references. Please see the responses to BCUC IR and At the time of program design, an evaluation process appropriate to the program will be developed and budgeted for. The Company will report on evaluation processes for new EEC programs in its Annual EEC Report, to be filed prior to the end of Q for 2009 activity As it relates to the evaluation of energy efficiency programs, please provide a budget indicating how much TGVI will be spending in 2009, 2010 and 2011 on developing, implementing, and assessing the impact of its energy efficiency programs. This question is identical to TGI RRA BCUC IR This response is similar to the TGI response to that IR, however some minor differences were necessary in order to respond appropriately for TGVI.

45 Page 44 The budget for program evaluation for TGVI is as follows: $163, $189,000 There is no budget allocated for evaluation for EEC Programs for TGVI in 2009 as EEC programs were only made available to TGVI customers upon receipt of Decision G on April 16, EEC programs on TGVI have not been running long enough in CY2009 to accumulate adequate data for evaluation, therefore no evaluation budget has been allocated for CY2009 for EEC programs for TGVI. It must be noted that this is the Company s best estimate of evaluation amounts, and that as programs become more developed, program-specific amounts for evaluation will be derived. The Company will report in more detail upon budget amounts for evaluation in its Annual EEC Report, to be completed before the end of Q for programs currently under development. While these evaluation budget amounts are amounts that would be allocated to TGVI, there will be one evaluation conducted per program that will capture information for TGI and TGVI. That is, for those programs that run across TGI and TGVI, there will not be separate program evaluations conducted for TGI and TGVI.

46 Page Reference: EEC and Alternative Energy Exhibit B-1, Part 111 (Application), Section C, Tab 3, pp Natural Gas Vehicle Compression and Refueling Service, BCUC IR , p TGVI states that: TGVI expects that by the end of the RRA period, it will a have a better understanding of the TGVI market and will be better able to determine future market growth. If TGVI is unable to understand the TGVI market until after the end of the RRA period why should the Commission not put the application for Natural Gas Vehicle Compression and Refueling Service in abeyance until TGVI has had sufficient time to study the market and formulate a business plan? The quote referenced speaks to TGVI s ability to determine further market growth beyond our current understanding of the customer demand. TGVI believes that a market exists currently based on discussions with potential customers. TGVI already has interest from customers on Vancouver Island. Customers in the transportation sector are asking TGVI for NGV service because TGVI has the skill sets in house to provide NGV service. It is important to provide a solution for these customers presently to ensure that we realize opportunities to increase load in the TGVI service area. TGVI s expectation, as indicated in the quoted sentence, is that its understanding of the potential of that market to grow will develop over the period of the RRA. The Natural Gas Vehicle program for TGVI will be based on the knowledge and experience of TGI and will essentially be an extension of the TGI program. TGI has a business plan in place and is already working with customers to provide a compression NGV solution. Over the period of the RRA, TGVI will concurrently sell NGV compression solutions to customers and modify the TGI business plan based upon TGVI gained knowledge. However, it is important to note that while overall prices in the TGVI service area will be different than on TGI, the TGVI market for NGV is very similar to the TGI market because TGVI customers are facing the same challenges to reduce greenhouse gas emissions and reduce fuel costs. Therefore, by leveraging TGI s success in growing the NGV market, the Company believes this momentum will carry over to TGVI where similar customers in the transportation sector are facing the same challenges in terms of reducing greenhouse gas emissions and vehicle operating costs.

47 Page Reference: EEC and Alternative Energy Exhibit B-1, Part 111 (Application), Section C, Tab 3, pp BCUC IR.76.2, p TGVI states that it believes that it must develop a biomethane resource portfolio of reasonable size in order to have enough biomethane to supply interested customers. What is a reasonable size? Is this a normal method of constructing a business strategy and developing a business plan considering that the size of the market is unknown, the technology is unproven, the number of projects is still being investigated and cost of the projects are uncertain? The first part of the question addresses the size of the resource portfolio. As stated on pages 240 and 241 of the Application, TGVI believes that the biomethane resource portfolio should involve diversity of supply. This would involve multiple suppliers and, if possible, more than one underlying source of raw biogas (i.e., waste water treatment plants, landfills, agricultural waste). Diversity of supply will serve to stabilize the average cost of biomethane and reduce the risk of supply shortfalls once the green product is being sold to interested customers. TGVI is seeking approval for a pilot phase with a limit of 0.1 PJ of annual biomethane supply. This volume limit would allow several smaller volume biomethane supply sources in the range of 20 TJ - 30 TJ per year to be developed which would serve the supply diversity objective. On the other hand, one larger volume project could provide the full 100 TJ per year and therefore limit the potential for supply diversity. TGVI sees the 0.1 PJ per year limit as being at the low end of what would constitute a supply portfolio of reasonable size; however, balancing this against the potential customer impacts of seeking a larger volume limit for the pilot phase before the green rate offering is finalized led TGVI to the conclusion that the 0.1 PJ per year limit is reasonable. The second part of the question addresses the use of the pilot approach. Pilot programs can be a useful tool for public utilities as a means of allowing the utility to pursue initiatives that will ultimately benefit customers. The use of pilot programs is a common strategy for utilities in the launching of new programs and in the testing of new technologies. For instance, the Commission recently approved a pilot for Liquefied Natural Gas Sales and Dispensing Service at the Tilbury Facility. Pilots are also used extensively in Energy Efficiency and Conservation ( EEC ) programs where pilots test the market for an EEC program to see if incentive levels and promotional and delivery tactics for the program will attract participants to the program. EEC pilots are typically done in a limited geographic area and for a limited time frame. A recent example of an EEC pilot would be the Spray and Save program that ran in the Okanagan during the summer of This was a pilot to test a program to directly install efficient prerinse spray valves in food service establishments. The results of the pilot will allow the Company to verify its assumptions around the energy savings from the program to ensure that it will be cost-effective prior to rolling it out to the Terasen Utilities service territory as a whole

48 Page 47 TGVI similarly believes that commencing the development of a new renewable supply resource such as biomethane with a limited pilot phase is a prudent approach for the reasons identified in the Application 5. One of those reasons is that the pilot will provide TGVI with more reliable information to use in market testing (as the parameters of a green offering will affect market scope). The question might be taken to suggest that the uncertainty in project cost represents a reason not to pursue a pilot program. Although the potential variety of project configurations will mean that capital investments will vary from one project to the next, TGVI has appropriately addressed rate impact in its proposal both by limiting the scope of the pilot and by placing a $15 / GJ limit on the cost of biomethane. TGVI disagrees with the characterization of the technology as unproven since it has been deployed successfully in other places although not in BC as yet. Existing and future gas customers stand to benefit from a successful pilot for two reasons. First, TGVI has stated in the Application that its intention is to develop a green rate that recovers the incremental cost from customers with a desire to purchase biomethane. The availability of this green service has the potential to retain and attract customers that will contribute to the overall system costs for the benefit of all customers. Given the scope of the pilot there is every expectation that the demand exists at least to the extent that the biomethane supply will be absorbed. While the pilot project is ongoing, TGVI will be undertaking further market testing to determine the future market potential based on information learned during the pilot. Second, the pursuit of biogas opportunities by public utilities like TGVI is also consistent with provincial policy as expressed in the Energy Plan and the legislated government s energy objectives. The government s energy objectives include two objectives that directly support a public utility like TGVI advancing biogas upgrading: (i) to encourage public utilities to use innovative energy technologies that support energy conservation or efficiency or the use of clean or renewable sources of energy, and (ii) to encourage public utilities to reduce greenhouse gas emissions. Biomethane is a clean and renewable source of energy provided through the development of innovative technology, and its use will encourage public utilities to reduce greenhouse gas emissions. TGVI therefore believes that the Commission, through its regulation of TGVI in the manner proposed in this Application, should be encouraging TGVI to pursue it. 5 Exhibit B-1 Application, pages , and Exhibit B-4, BCUC IRs and , pages

49 Page Reference: EEC and Alternative Energy Exhibit B-1, Part III, Section C, Tab 3, p. 243 Exhibit B-4, BCUC IR Recognizing the question is identical to TGI RRA BCUC , will TGVI provide a response adjusting for the minor differences? The full response to BCUC IR was inadvertently excluded from the filing of the responses to BCUC IR No. 1 (Exhibit B-4). The full response to this question is found below. Response to BCUC IR Reference: EEC and Alternative Energy Exhibit B-1, Part III (Application), Section C, Tab 3, pp. 243 Financial treatment of biogas projects during the Pilot Phase 78.1 TGVI indicates that the company's investment in biogas upgrading equipment as well as O&M and other costs will be tracked in separate accounts. Should not all costs including TGVI staff time spent on promoting and developing these projects be tracked and assigned to these separate accounts as well? This question is identical to TGI RRA, BCUC IR This response is similar to the TGI response to that IR; however some minor differences were necessary in order to respond appropriately for TGVI. There are two aspects to the staff time used for the development of biogas projects and supply, which will be discussed separately. The first is identification of potential projects, their evaluation and investigations required to determine if the project or supply should be undertaken or acquired. These costs are marketing and sales costs related to providing customers with the service they request (which include both conventional gas and alternative energy) and, in addition, providing energy efficiency education and information. As such, these costs are no different than any other sales, marketing, and development costs that are spread across all customers and as such these costs should not be segregated.

50 Page 49 The second aspect is project development. Once a specific biogas project has been identified and has received spending approval from TGVI s capital planning committee (the Utility Operating Committee Capital Group) staff resources will be assigned to the project and tracked in the same way that other TGVI projects are tracked. The tracking of these costs will allow them to be included in the project costs which, during the pilot phase, TGVI proposes to include in the gas costs and GCVA as described on page 244 of the Application. If the pilot phase of TGVI s biogas initiative were to indicate that fewer biogas projects are available than initial indications suggest, these staff resources would be directed to other TGVI projects or initiatives.

51 Page Reference: Alternative Energy Solutions Exhibit B-4, BCUC Economic Assessment BCUC TGI IR Preparing a separate rate category and accounting for cost if service protects customers that are not being served by the alternative energy project from being unduly impacted by costs 19.1 Please explain the treatment of these sunk capital costs if alternative energy customers leave the system before the end of their contract term. What is the proposed treatment of these potential stranded costs? This question is identical to TGI RRA BCUC IR This response is similar to the TGI response to that IR; however some minor differences were necessary in order to respond appropriately for TGVI. It is unlikely that customers will leave the system before the end of the contract term as TGVI envisions that these customers will be end use owners of buildings or suites that will have an ongoing requirement for heat. The only way that they would leave the system is if the building no longer required heat. However, some customers may be required to sign contracts that could include provisions for a payment for undepreciated assets (similar to the language in TGI Bypass Agreements), whereby a customer or customers will have to make a payment should they leave the system, or be required to pay the difference between forecast consumption and actual consumption similar to Section 5.2 in Compression and Refuelling Service Rate Schedule (see Appendix J-5 of the Application)..

52 Page Reference: Gas Sales and Transportation Demand Ex. B-1, Energy Forecast Methodology, p. 255, and Ex. B-4, BCUC IR No , and Ex. B-6, BCOAPO IR No Demand Forecast: Price Elasticity TGVI confirms that, consistent with the Mt. Hayes response above, the demand estimates in the Application do not incorporate any price elasticity adjustment. (B-4, BCUC IR No ) Overall, TGVI does estimate the elasticity of demand with respect to price for natural gas to be approximately.21 for residential customers. (B-6, BCOAPO IR No.1 6.8) 20.1 Please clarify whether any price elasticity adjustment was used to arrive at the demand figures in the Application. TGVI confirms that no price elasticity adjustment was used to arrive at the demand figures included in the Application Please confirm that the elasticity figure stated in response to BCOAPO IR#1 6.8 means that a 1 percent increase in the delivered price of natural gas is expected to lead to a 0.21 decrease in consumption by residential customers. If not confirmed, please describe the correct interpretation. TGVI confirms that the elasticity figure stated in the response to BCOAPO IR means that a 1 percent increase in the delivered price of natural gas is expected to lead to a 0.21 percent decrease in consumption by residential customers It appears that, given the TGVI elasticity estimate for residential customers stated in response to BCOAPO IR No.1 6.8, the proposal to maintain existing rates, and the recent increase in retail electricity rates, residential demand in the

53 Page 52 Application may be underestimated. Please explain why this conclusion should not be reached. Please note that the demand response to an increase in electricity rates (while the delivered price of natural gas remains constant) is not related to TGVI s response to BCOAPO IR 1.6.8, which discusses the price elasticity of demand with respect to the price for natural gas. That is, for a change in the delivered price of natural gas (not electricity), the price elasticity (0.21, as per BCOAPO 1.6.8) estimates the resulting change in demand. TGVI believes residential demand has been properly estimated in the Application. Although the proposal to maintain existing rates, when combined with the recent increase in retail electricity rates, will lead to a more favourable operating advantage for natural gas, this is not likely to change the current trends in usage. The likely actions taken in response to a narrowing of the operating advantage for natural gas would result in both temporary (i.e. the purchase of plug-in baseboard heaters) and permanent (i.e. the purchase of new appliances) reductions in consumption. However, an increase in the operating advantage for natural gas would not necessarily have the same impact, since replacing existing appliances with natural gas equipment may be cost prohibitive from a capital cost point of view. Given that, it is reasonable to assume the demand response to a narrowing of the operating advantage for natural gas is greater than that for an increase in the operating advantage for natural gas.

54 Page Reference: Gas Sales and Transportation Demand Ex. B-4, BCUC IR No and Attachment 84.1 Demand Forecast: Household Formations 21.1 The information in Attachment 84.1 appears to be a total population forecast. Does TGVI use total population or household formations to as the basis for demand estimates? The information in Attachment 84.1 is the Household Formations forecast from BC Stats, and illustrates the total estimated number of households in the province, by Local Health Area, on an annual basis. TGVI confirms it uses household formations as the basis for its net customer additions forecast, which is one of the key components of the demand forecast in addition to use per customer rates and the industrial demand forecast Please confirm that the information provided in Attachment 84.1 is an excerpt from BC Stats document PEOPLE 33. If the more recent PEOPLE 34 forecast was used, how would that affect the Application? TGVI confirms that the information provided in Attachment 84.1 is an excerpt from BC Stats document PEOPLE 33. In comparing the household formation forecast based on the PEOPLE 33 model to that based on the PEOPLE 34 model, for those local health areas in which TGVI provides natural gas service, the difference is not significant enough to have a material impact on the figures presented in the Application. As illustrated in the table below, the more recent forecast from BC Stats indicates that the total number of household formations is only expected to be 1%, 0.9%, and 0.8% lower than the prior forecast version. HHF Forecast - In TGVI Service Territories Version PEOPLE , , ,561 PEOPLE , , ,495 Difference -3,526-3,311-3,066 Difference (%) -1.0% -0.9% -0.8% TGVI continues to believe that the figures used in the Application remain appropriate.

55 Page Reference: Customer Usage Rates Ex. B-4, BCUC IR No In TGVI BCUC IR response 87.0, TGVI indicated that annual data for new customers is largely incomparable due to partial periods and new customers that remain dormant during the test period Please provide the average customer usage rate, in GJ, for new customers, by month, for 2007 and When preparing this calculation, please exclude customers with zero usage for that month, but disclose the total customers excluded by month in the calculation. Please use the table below, expanded to include all relevant monthly data available. Customers: (Year added) Average GJ: First month data is available-07 Ave GJ 07 Ave GJ Dec-07 Ave GJ Jan- 08 Ave GJ Feb- 08 Ave GJ 08 Ave GJ Dec Number of zero customers adds 2008 N/A N/A N/A Number of zero customers adds N/A N/A N/A The following table illustrates the total number of new customers, number of customers excluded (due to having zero consumption in that month, or due to being added in that month and therefore not having a full month s consumption), and the monthly use per customer rate for those customers added in Please note that those customers added in January 2007 are included in each subsequent month (through December 2008), as this is a cumulative total for new customers.

56 Page 55 Jan07 Feb07 Mar07 Apr07 May07 Jun07 Total Number of New Customers in ,142 1,419 Number of New Customers Excluded Use Per Customer Rate (GJ/Month) Jul07 Aug07 Sep07 Oct07 Nov07 Dec07 Total Number of New Customers in ,604 1,852 2,116 2,409 2,777 3,022 Number of New Customers Excluded Use Per Customer Rate (GJ/Month) Jan08 Feb08 Mar08 Apr08 May08 Jun08 Total Number of New Customers in ,024 3,021 3,021 3,016 2,997 3,020 Number of New Customers Excluded Use Per Customer Rate (GJ/Month) Jul08 Aug08 Sep08 Oct08 Nov08 Dec08 Total Number of New Customers in ,009 2,979 2,974 2,981 2,970 3,018 Number of New Customers Excluded Use Per Customer Rate (GJ/Month) The following table illustrates the total number of new customers, number of customers excluded (due to having zero consumption in that month, or due to being added in that month and therefore not having a full month s consumption), and the monthly use per customer rate for those customers added in Please note that those customers added in January 2008 are included in each subsequent month (through December 2008), as this is a cumulative total for new customers. Jan08 Feb08 Mar08 Apr08 May08 Jun08 Total Number of New Customers in ,233 1,422 Number of New Customers Excluded Use Per Customer Rate (GJ/Month) Jul08 Aug08 Sep08 Oct08 Nov08 Dec08 Total Number of New Customers in ,587 1,731 1,981 2,406 2,690 2,859 Number of New Customers Excluded Use Per Customer Rate (GJ/Month) There are timing differences in the reporting of data between the detailed consumption reports used to derive the above information and the monthly consumption reports (which also contain customer counts). Therefore, the figures presented above do not reconcile to the historical customer additions figures presented in the Application.

57 Page Please describe if new customers are asked to declare their expected usage rates at time of installation of services. If so, explain how such a declaration of estimated usage rate impacts customer rates including charges for installation fees. Also describe if TGVI verifies this estimated usage against actual usage rates and the impact/penalty to new customers when actual usage is less then estimated usage at installation. At the time of application for new service, customers are asked to declare their expected usage rates through providing various characteristics about their home and energy requirements, including the floor area and appliances expected to be installed. There is no material impact to the installation fees if the estimated usage rate differs from the actual usage rate, and with TGVI s rates being tied to electric equivalents, there is no real impact to rates either. It is important, however, to note that as public policies that promote energy conservation incent all of TGVI s customers to reduce consumption over time, and therefore the resulting decline in throughput would have the same impact as new customers consuming less natural gas than expected. And although there is no impact/penalty to new customers when actual usage is less than estimated usage at the time of installation, TGVI does verify the estimated usage against actual usage rates for all services where a main extension was required to provide them with service. Furthermore, TGVI s average actual PI, based upon its review of main extensions, indicates that new customers are economical and not causing incremental costs to existing customers Please provide TGVI s estimate usage for new client s for 2006, 2007 and 2008, by categories. The ability to distinguish between customers new to the system and customers that simply moved premises was only gained when the CAFÉ (Customer Attraction Front End) Reporting tool was implemented in Given that, TGVI has identified customers new to the system in 2007 & 2008 and estimated their normal annual average use per customer as illustrated in the below table across various rate classes. The following tables below illustrate the customers added in 2007 (and 2008) along with their corresponding use per customer rate for those years. Please note that the figures incorporate all customers added in each year, and therefore the results include customers with consumption over only part of each year.

58 Page 57 Annual Normal Avg UPC (GJ) Customers added in year Rate Class LCS LCS SCS RGS SCS Annual Normal Avg UPC(GJ) Customers added in year Rate Class LCS1 n/a SCS1 n/a RGS n/a 10.9 SCS2 n/a 122.4

59 Page Reference: Rate Design Ex. B-4, BCUC IR No and Proposed Rates: Application Fee Revenue Impact 23.1 What is the expected net revenue impact of changing the Application fee from $85 to $25 in each of 2010 and 2011? TGVI estimates that, as a result of changing the Application fee from $85 to $25 in each of 2010 and 2011, the net revenue impact will be a decrease of approximately $150,000 in 2010 and $157,000 in Despite the impact to net revenue, the proposed reduction in Application Fees is appropriate, as the results of TGVI s analysis indicate a $25 Application Fee is more reflective of actual costs than is the current $85 Application Fee.

60 Page Reference: Rate Design Ex. B-4, BCUC IR No and 16.1 Proposed Rates: Application Fee - Implications Although TGVI expects the proposed reduction to have a positive impact on the number of new accounts in 2010 and 2011, given this reduction would reduce the cost to new customers attaching to its system, the impact is not readily quantifiable. There are many variables potential customers would consider when deciding on the energy source to meet their needs, and the application fees are only one of those Given the above statement, and assuming that developers may not be swayed by a fee reduction, nor necessarily pass it on to final consumers, why would approval of the proposed Application Fee reduction not merely shift the costs of new services to existing customers and away from new customers and/or developers? The Company is proposing a reduction in the Application Fee so that it more accurately reflects the cost of creating a new customer account. The fee is currently higher than the cost of creating a new customer account. TGVI believes that it is appropriate to reduce this Fee to more closely reflect the cost of creating a new customer account (cost causation), and does not consider this to be an exercise of shifting costs. In terms of the effect on existing customers, additional considerations are in play in cases where the MX Test applies (as opposed to an individual customer connecting in accordance with Section 6 Service Lines in the Tariff). In cases where a MX Test is required, new customers may be required to pay a higher contribution in aid of construction (CIAC) as a result of the proposed lower Application Fee. The proposed reduction in the Application Fee of $60 ($85 minus $25) will result in lower forecast revenues in the MX Test. This will further result in a lower Profitability Index and a higher CIAC (when a contribution is required). This serves to offset the effect existing customers will see from the reduction in the Application Fee, while remaining consistent with cost causality.

61 Page Reference: Property Tax Forecast Exhibit B-4, BCUC The corporate revenue component of property tax consists of corporate revenues from gas consumed, times 1 percent. Based on the information provided in Exhibit B-4, BCUC as summarized below the company has projected an increase of 14% in year 2009 which is significantly greater than increase experienced or expected in other year. Please provide an explanation for the larger increase in the projected corporate revenue component of property tax in The table above displays numbers rounded to the nearest hundred thousand. When the unrounded figures are used, the increase from 2008 to 2009 is lower, at about 11.5 per cent, and represents a minimal increase of approximately $160,000. Therefore, this is not a significantly larger increase than the other years. However, we have provided below an analysis of this change. There are a number of factors that drive the corporate revenue component of property tax. The one with the largest impact and the primary reason for the slightly larger increase in 2009 than in the other years is the level of corporate revenues. The corporate revenue component of property tax in the above table is calculated based on actual municipal revenues from two years prior. That is, the values in the above table for 2008 and 2009 are based on actual municipal revenues earned from gas consumed from 2006 and 2007, respectively. A comparison of 2007 revenue to 2006 revenue shows an increase of approximately 10 per cent, which compares to an increase of approximately 7 per cent for 2008, and no increase for As discussed on page 161 of the Application, the increase in 2007 is primarily due to customer growth in the residential rate class resulting in higher volumes, increasing use rates and higher rates in the commercial classes, and higher BC Hydro and Joint Venture interruptible tolls.