December 14, British Columbia Public Interest Advocacy Centre Suite West Pender Street Vancouver, B.C. V6E 2N7

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1 Diane Roy Director, Regulatory Affairs - Gas FortisBC Energy Inc. B Fraser Highway Surrey, B.C. V4N 0E8 Tel: (604) Cell: (604) Fax: (604) diane.roy@fortisbc.com Regulatory Affairs Correspondence gas.regulatory.affairs@fortisbc.com British Columbia Public Interest Advocacy Centre Suite West Pender Street Vancouver, B.C. V6E 2N7 Attention: Ms. Leigha Worth, Executive Director Dear Ms. Worth: Re: FortisBC Energy Inc. ("FEI") Response to the British Columbia Public Interest Advocacy Centre on behalf of the British On September 24, 2012, FEI filed the Application as referenced above. In accordance with the British Columbia Utilities Commission Order No. G setting out the Revised Preliminary Regulatory Timetable for the review of the Application, FEI respectfully submits the attached response to BCPSO IR No. 1. If there are any questions regarding the attached, please contact the undersigned. Yours very truly, FORTISBC ENERGY INC. Original signed: Diane Roy Attachment cc ( only): Commission Secretary Registered Parties

2 Page Reference: Exhibit B-1, pages 5-6, Approvals Sought, General 1.1 Given the large increases in proposed sales volumes to the commercial LNG customers from the Mt. Hayes and Tilbury facilities along with the claim that the core market will not be adversely affected under the proposal, would it be unfair to suggest that the two named facilities have capacities significantly in excess of core market requirements both now and for the foreseeable future? Yes, it would be unfair to suggest that the facilities have capacities significantly in excess of core market requirements. As discussed in the response to BCUC IR 1.7.8, the proposed use of the Mt. Hayes and Tilbury facilities to support the Rate Schedule 16 market does not reduce or otherwise impact the need or availability of the facilities to meet system capacity and peaking gas requirements during cold weather events or supply disruptions. The use profile of LNG for Rate Schedule 16 customers and the use of the facilities by the core market for gas supply are very different and therefore are complementary. The full sendout capabilities and the vast majority of the storage capacity of the facilities continue to be available to serve the needs of the core market as and when required. The increase in sales volume results in an increase in the use of the liquefaction facilities when they are not otherwise required to refill inventory required to meet core market requirements. Please refer to section and of the Application for greater detail and the use of the facilities by the core market and Rate Schedule 16 customers. 1.2 Using the traditional economics definition of opportunity cost, i.e., value of the best foregone alternative, what is the opportunity cost of the proposed increases in commercial LNG volumes for each of the named facilities? The opportunity cost associated with the proposed increased in Rate Schedule 16 volumes is $0. In the Application, FEI is proposing to make additional use of assets that were built for and are required for core service. By doing so, FEI is generating $6.7 million per year in incremental benefits to FEI and FEVI customers as detailed in Section of the Application. To the best of FEI s knowledge there is no alternative use of these assets that would generate such returns.

3 Page Given the existing infrastructure, what are the maximum LNG volumes from each of the named facilities that could be provided to the commercial LNG market while still being able to satisfy the core market design day demand using FEI s existing facilities and without relying on any new peaking resources? Please consider both capacity and bottleneck constraints in providing a response. The assessment of the maximum LNG volumes that could be made available from each facility without impacting the peaking requirements of existing core customers is provide in Section 8 of the Application under two extreme scenarios. The Design Day case described in Section represents a gas year based on experiencing forecasted design peak day demand. The Much Colder than Normal Winter case discussed in Section was modelled to simulate a scenario where there are two extreme weather events in a single winter. As discussed in Section of the Application, based on FEI s existing infrastructure and peaking resources, in the Design Day case the maximum volumes that are available for Rate Schedule 16 customers while still satisfying core market demand are 3,200 GJ/d from Tilbury and 2,800 GJ/d from Mt. Hayes totalling 6,000 GJ/d. As discussed in Section 8.3.3, under the Much Colder Than Normal scenario, the maximum daily volumes that could be supplied to Rate Schedule 16 customers without impacting core market requirements equate to 3,500 GJ/d from Tilbury and 4,500 GJ/d from Mt. Hayes for a total of 8,000 GJ/d. The design day case volumes are illustrated in Table 8-2 and the colder than normal case volumes are illustrated in Table 8-3 of the Application. Under a normal winter scenario, no LNG is required from either Mt. Hayes or Tilbury since those loads are served by baseload and seasonal gas supply and third party storage facilities. As a result, the only limit to what theoretically could be made available to Rate Schedule 16 customers would be the maximum liquefaction capacity of the facilities (less what is required to replace the daily boil-off) to be used to maintain inventory levels. In all scenarios, the maximum sendout capacity from both facilities remains available to serve core customers. Therefore as forecast peak day increases due to customer growth over time, FEI may need to acquire additional peaking resources. However, this is not impacted by the proposed Rate Schedule 16 service. The summary table below provides a comparison of the volumes that could be available for Rate Schedule 16 under the different modelling scenarios including the potential annual revenue that could be earned to the benefit of all customers. In this Application, FEI is proposing to limit volumes available to Rate Schedule 16 customers to 6,000 GJ/d, consistent with the Design Day scenario.

4 Page 3 Scenario Design Day Case Much Colder Than Normal Case Normal Scenario Available Volumes (GJ/d): Tilbury 3,200 3,500 4,300 Mt. Hayes 2,800 4,500 6,900 Total Volumes 6,000 8,000 11,200 Maximum Available Volumes (GJs per year) 2,190,000 2,920,000 4,088,000 Rate Schedule 16 ($/GJ) $4.05 $4.05 $4.05 Maximum Annual Revenue ($Millions) $8.9 $11.8 $16.6 Please also refer to Table 8-1 in the Application which provides a summary of the operating and maintenance parameters and constraints used in the modelling of the availability of volumes for Rate Schedule 16 customers. 1.4 Please provide FEI s best estimate as to the year in which forecasted commercial LNG sales volumes are expected to grow to the maximum level referred to in the previous IR, 1.3. As described in section of the Application and listed in Table 8-2, the maximum level of LNG available to the Rate Schedule 16 market while also meeting Design Day requirements for core service is 3,200 GJ/day (22,400/wk) from Tilbury and 2,800 GJ/day (19,600/wk) from Mt. Hayes. These amounts are the capacity limits requested in the Application and total to 42,000 GJ/wk or 2.19 PJ/year. Under the original Rate Schedule 16 forecast FEI anticipated that this capacity would be sufficient to supply the projected Rate Schedule 16 demand from 2013 through Due to higher demand than forecast under the initial year of the NGT Incentive Program, FEI has updated its demand projections and believes that demand may exceed supply in Please refer to the response to BCUC IR

5 Page Please provide the expected remaining life of the Tilbury facility and identify any assumptions regarding any remedial maintenance, repair, or replacement activities and their forecasted costs that underpin the estimated remaining life. FEI expects the Tilbury facility to remain used and useful for the foreseeable future with no definitive expected remaining useful life. The Tilbury facility is consisted of many discrete components which age at different rates and which have been subject to periodic improvements since the facility was commissioned in To provide some general commentary, the key components can be considered to be the site, the storage tank, the send-out vaporization equipment, the liquefaction train, and the ancillary equipment and structures. Since initial operation in 1971, the Tilbury facility has been subject to ongoing sustainment capital improvement of the various components to ensure its fitness-for-service with the expectation of an overall service life which considerably exceeds the limited life of certain components. FEI has invested on average approximately $2 million per year from 1971 to 2011 to upgrade and replace equipment as required; this has included tank upgrades including secondary containment, a fourth vaporizer, and a cold box replacement in the liquefaction train. FEI notes that the liquefaction compressor is original equipment as are some of the ancillary equipment and structures and FEI expects to spend sustainment capital at Tilbury in the next 10 years to replace this older equipment. FEI is also assessing whether a more comprehensive replacement of the liquefaction train and ancillary equipment would be more cost effective than component replacement under the sustainment capital program.

6 Page Reference: Exhibit B-1, page 9, Forecasted Demand The referenced page states: The demand estimate of 2.1 million GJs in 2017 is based on the aggregate fuel consumption from the fleet of LNG powered vehicles that are expected to be introduced to the BC market under FEI s NGT Incentive Program. Although FEI s projection for LNG demand is linked to the NGT Incentive Program, other factors will also support forecasted demand growth. These factors include alternative government policies that encourage reduction of GHG emissions in British Columbia, the pricing advantages of using natural gas versus diesel as a transportation fuel and the availability of other LNG related service offerings, such as FEI s LNG fueling service offering. 2.1 Is it fair to conclude that FEI s forecasted demand to 2017 is likely an underestimate of actual demand or at least a plausible floor estimate given that it is based only on the vehicles put into the market under FEI s NGT Incentive Program and therefore does not include other LNG powered vehicles that may also be introduced into the market? Yes, FEI agrees it is fair to describe the forecast demand to 2017 as a floor estimate. FEI confirms its forecast is based only on vehicles stimulated by volumes through the NGT Incentive Program. Since non-incentive LNG projects (vehicles or otherwise) have not yet developed within FEI s service territory it is difficult to forecast such volumes with any degree of certainty. 2.2 Has FEI attempted to quantify the impacts on demand, under various scenarios, of the other factors referred to in the second excerpted paragraph? If so, please provide details; if not, would the presence of these other factors also generally serve to provide an indication that FEI s forecasted demand is conservative?

7 Page 6 No, FEI has not quantified the impact of other factors within the scope of this Application. FEI is presently assessing other potential LNG market demand. FEI agrees that the identification of significant other LNG demand may suggest that FEI s forecast demand is conservative.

8 Page Reference: Exhibit B-1, page 10, Impacts and Benefits of Proposed The referenced page states: Amendments on FEI s Natural Gas Service to Non-Rate Schedule 16 Customers The amendments to Rate Schedule 16 proposed in this Application will not disrupt the LNG capacity required for peak demand and emergency back-up service to the core market as discussed in section 8. That is, there will always be sufficient capacity and operational flexibility within the LNG storage facilities to ensure that the needs of the core market are met in the winter months during extreme weather conditions and during system emergencies. (Emphasis added.) 3.1 Please confirm that the core market guarantee applies to the existing LNG facilities and involves no material changes with respect to how core market peak demands are met; if unable to so confirm, please explain fully. Confirmed. FEI s ability to meet core demand under a variety of scenarios is discussed in Section 8 of the Application. The resources required to meet core market peaks are shown graphically in Figure 8-1. These resources include the existing LNG facilities.

9 Page Reference: Exhibit B-1, page 16, Economic Advantage of LNG The referenced page states: For 2012, the delivery charge component of Rate Schedule 16 has increased to $4.05/GJ and the Sumas Monthly Price for commodity in January 2012 was $3.32/GJ. Thus, the combined rate under Rate Schedule 16 for January, 2012 was $7.37GJ or $0.28/DLE. For comparative purposes, the Vancouver rack price for ultra-low sulphur diesel fuel on January 14, 2012 was $0.864/litre. In June 2012, the Sumas Monthly Index had dropped to $2.31/GJ, which resulted in a reduction of the Rate Schedule 16 price to $6.36/GJ or $0.25/DLE. Again for comparative purposes, the Vancouver rack price for ultra-low sulphur diesel on June 15, 2012 was $0.829/litre. Thus, as demonstrated above, LNG fuel currently enjoys a substantial competitive advantage over diesel fuel at the supply point as it is priced at approximately 30% of the diesel fuel price. This pricing advantage is further strengthened by a tax structure that favours the use of LNG. For example, LNG is presently not subject to certain provincial and federal motor fuel taxes, whereas diesel fuel is subject to motor fuel taxes. As a result, the pump price of diesel fuel in Vancouver is raised to approximately $1.359/litre. A comparable LNG price at the pump for a Vancouver based LNG customer would be approximately $0.57/litre. 4.1 Please provide comparative price differences between the fuels under the assumption that both fuels are subject to the same tax treatment. FEI is aware of two Provincial taxes which apply to diesel and natural gas fuel. These are: British Columbia Motor Fuel Tax ( MFT ) applies to clear gasoline and clear diesel sold for use or used to power internal combustion engines. Natural gas for use in vehicles is currently exempt. British Columbia Carbon Tax applies to the purchase or use of fuels, such as gasoline, diesel, natural gas, heating oil, propane, etc.

10 Page 9 According to the Ministry of Finance Tax Bulletin (MFT-CT 005), the amounts for each fuel type are summarized in the table below, in diesel litres and GJ. 1 Fuel Motor Fuel Tax Carbon Tax $/Litre $ Per GJ $/Litre $ Per GJ Diesel Natural Gas The question appears to seek a comparative price analysis if natural gas had the same tax treatment as diesel. For the purposes of this response, FEI has assumed natural gas to have the same MFT as diesel at 24 cents per diesel litre. For comparison, FEI has used the same LNG delivery, commodity and rack prices provided in the response to BCUC IR 1.4.1, current as of November 27, Fuel Motor Fuel Tax Carbon Tax LNG Charges Diesel rack Total price $ Per GJ $ Per GJ Delivery ($/GJ) Commodity ($/GJ) $ Per GJ $ Per GJ Diesel $ 6.21 $ 1.98 N/A N/A $ $ Natural Gas $ 6.21 $ 1.49 $ 4.05 $ 3.72 N/A $ Based on this analysis, LNG still maintains a price advantage of 45% over diesel fuel. This price advantage still provides a significant benefit for customers contemplating a switch to natural gas. FEI understands the Province does not plan to implement a MFT applicable to natural gas until market adoption of natural gas reaches a significant level and no longer requires economic incentives to encourage adoption. 1 Motor Fuel Tax in South Coast British Columbia Transportation Service Region as of July 1, Carbon Tax as of July 1, Diesel rack on November 27, 2012 was $0.773 per litre, equivalent to $20.00 per GJ

11 Page Reference: Exhibit B-1, page 22, Incentive Programs under GGRR and Projected Market Growth to Does FEI agree that if the actual amount of fuel per truck is greater than the estimated fuel per truck, e.g., due to actual mileage being greater than estimated, then the LNG demand will similarly be underestimated, 1:1, ceteris paribus? FEI has updated its LNG consumption estimate for the NGT Incentive Program in part based on an updated estimate of the fuel consumption per truck. Please refer to Exhibit B-2, p. 4 in the GGRR proceeding. This does not affect the merits of the present Application. It just means that FEI s supply may be sold out earlier than projected and that the requested capacity limits may not be sufficient to supply all projected demand under the NGT Incentive Program. Hence FEI may not place all incentive monies authorized under the program. The GGRR is a voluntary undertaking by FEI. There is no obligation to place all of the incentive money available. If use per truck continues to be high FEI will generate GHG reductions in excess of those projected under the GGRR application while using less incentive money.

12 Page Reference: Exhibit B-1, page 35, Design Day Case 6.1 Please provide details regarding the assumptions and methodological details underpinning the Extreme Value Analysis, including data sources, frequency (e.g., daily, weekly, etc.,) and period (e.g., 20 years) of data used, peak day HDDs, core load growth, when last updated, etc. The coldest day planned for, also referred to as the design day, represents the coldest day that is expected to occur once every 20 years, determined through Extreme Value Analysis. The return period of once every twenty years is used as it is consistent with past practices and provides a reasonable timeframe compared against those used by other utilities. Extreme Value Analysis is a statistical technique used to model observed data extremes in order to allow for generalizations about the likely recurrences of those events. This type of analysis is the accepted standard in Canada and is approved by the Atmospheric Environment Service of Environment Canada. The data inputs are the coldest temperature experienced in each year, and the objective is to identify the coldest temperature that would be expected to reoccur once every twenty years. To achieve the objective, historical weather data (the coldest day in each year) is collected from Environment Canada from regional airports and modeled using a non-linear regression approach following the functional form: ( ) ( ) Where: r(t) = the predicted return period as a function of the temperature; Sigma, Mu = constants determined from the regression analysis; t = the temperature, in degrees Celsius; The regression determines values for Sigma and Mu such that the sum of squares of error is minimized (Least Square Method), using the above formula. Once the equation has been solved, the extreme value temperature can then be determined for a given return period using the following formula: ( ( ( ) ))

13 Minimum Temperature: Degrees Celsius Page 12 Where: t = the extreme value temperature; ln = the natural logarithm function; r = the return period; and, Mu and Sigma are the coefficients solved using the Least Square method in the above model. In the following chart for the Lower Mainland, the coldest temperature each year for 60 years is plotted using the methodology outline above. Entering the chart at the 20 year return period intersects the plot at -12.8C, the design day temperature for the Lower Mainland. Peak, , - x, , Peak, , Peak, Peak, , , x, , Peak, , x, , x, , Peak, 7.500, , x, x, 8.571, , Peak, x, x, 6.667, 7.500, 4.286, 4.615, 5.000, , 6.000, 6.667, Peak, Peak, x, x, x, 5.000, 5.455, 6.000, 3.158, 3.333, 3.529, 3.750, 4.000, Peak, Peak, , 2.727, 2.857, 3.000, x, 4.000, 4.286, 4.615, , 2.400, 2.500, Peak, , x, 3.158, 3.333, 3.529, 3.750, x, 2.500, 2.609, 2.727, 2.857, 3.000, , Peak, Peak, x, 2.069, 2.143, 2.222, 2.308, 2.400, , 2.069, , x, 1.765, 1.818, 1.875, 1.935, 2.000, , 1.818, 1.875, x, 1.500, 1.538, 1.579, 1.622, 1.667, 1.714, , 1.714, Peak, 1.538, 1.579, , 1.429, 1.463, 1.500, 1.622, x, 1.333, 1.364, 1.395, 1.429, 1.463, x, 1.200, 1.224, 1.250, 1.277, 1.304, , 1.364, Peak, Peak, , 1.176, 1.200, 1.224, 1.250, 1.277, 1.304, x, 1.111, 1.132, 1.154, 1.176, x, 1.053, 1.071, 1.091, Peak, , 1.111, 1.132, x, x, 1.017, 1.034, Peak, , 1.053, 1.071, - x, Peak, 1.000, 1.017, Peak, 1.000, x, , Peak, , Return Period: Years Applying the Extreme Value methodology to other regions results in the following design day temperatures and corresponding HDD values.

14 Page 13 Region 1:20 Design Day Temp (⁰C) 1:20 HDD Lower Mainland Inland Columbia Fort Nelson Vancouver Island Once the design day temperatures are derived for each region, the design day demand is estimated using a regression approach for a given gas year which spans from November to October. This analysis is updated annually. Core load growths are applied to the base year design day demand to arrive at the forecast design demand.

15 Page Reference: Exhibit B-1, pages 46 and 58, Storage Allocations 7.1 Please explain how the minimum of 2 weeks supply for commercial LNG was determined in calculating the Rate ,000 GJ storage space allocation. In order to develop the LNG market in transportation applications, FEI needs to provide prospective customers with a service offering that gives them confidence that their LNG supply needs will be met. Part of this confidence comes from knowing that FEI has allocated a reasonable amount of storage capacity to meet their present and projected needs for a reasonable period. In a well developed market with many supply points and many points where inventory is maintained, smaller levels of storage can be maintained. In a thin emerging market, however, customers generally require higher levels of storage capacity in their local market area to consider making purchase commitments. This is especially true when they have to make major investments and commitments to transform their operations to adopt the new product. In a mature industry, the amount of inventory and storage capacity required would theoretically be determined through a quantitative analysis of such factors as: Desired service level e.g. 99% probability in being able to supply product Consequences of a stock out Costs and availability of replacement supply Production rate and economic production run size Probability of variations in production Probability of variations in demand Length of the supply chain Time frame for delivery to market Costs associated with storage Inventory holding costs Obsolescence costs and risks The LNG market in B.C., however, is not sufficiently developed to permit a quantitative analysis of these factors. In determining the appropriate storage capacity, FEI discussed storage levels with potential customers such as BC Ferries and Vedder Transport. In the course of these discussions it was determined that 2 weeks was an appropriate safety stock level of supply to provide the industry with sufficient confidence that product would be available for their needs.

16 Page 15 FEI assessed whether 2 weeks supply could be allocated without impairing the ability to serve core needs. As discussed in section 8 of the Application, the assessment was that 2 weeks supply could be allocated. FEI also considered the cost to Rate Schedule 16 customers of allocating this amount of storage to the emerging market and determined that the costs could be accommodated within a reasonable rate structure that would permit market adoption. In this Application FEI is requesting authorization to provide up to 2.19 PJ/yr to the Rate Schedule 16 market, with 1.17 coming from Tilbury and 1.02 PJ coming from Mt. Hayes. The actual amounts requested (50,000 GJ at each facility) are somewhat higher than a 2 week supply at maximum capacity. The actual 2 week calculations would be 45,000 GJ at Tilbury and 39,000 GJ at Mt. Hayes. FEI requested the somewhat higher levels to have an easy to communicate storage allotment to communicate to the market that demonstrates FEI s commitment to the Rate Schedule 16 service and because the additional amount is not material to the core service. Additional storage at Mt. Hayes is also prudent given that it is more remote from the largest part of the market. All else equal, when the supply chain is longer and involves multi-modal transport it is prudent to have a higher inventory level in order to provide a buffer for changes in demand. 7.2 Please explain how the deliverability requirements and costs associated with storage, i.e., injection and withdrawal costs, have been allocated to Rate 16 customers and to non-rate 16 customers. Please see section on pages 57 through 59. In summary it is as follows: Deliverability requirements are interpreted to mean send-out for core service. No changes are contemplated to send-out capabilities. Both facilities will continue to be able to send out up to 164 TJ per day on demand. Costs associated with send-out (i.e. vaporization costs) are allocated to the core service. These assets are not used by Rate Schedule 16 service Costs associated with storage are allocated to the service that has call on the storage. The core service requires the large storage facilities, retains use of the large majority of those assets and will continue to pay the costs associated with those assets. Rate Schedule 16 service picks up a proportionate share of the storage related costs for the portion of the tanks that is allocated to Rate Schedule 16 service.

17 Page 16 Injection (i.e. production) costs are allocated on the basis of the volume produced for each service. 7.3 Please provide the number of times annually that FEI forecasts that (i) the storage space allocated to core or non-rate 16 customers will be cycled, and (ii) the storage space allocated to commercial LNG customers will be cycled, under the various load growth scenarios, for each year, FEI has provided the number of cycles as requested in two tables below, based on the four scenarios described on Page 52 of the Application. As these scenarios were not contemplated over a specific time period, FEI has not provided an annual breakdown of amounts. FEI s core and non-rate Schedule 16 volumes are not forecast over the timeframe, and the commercial LNG demand in Scenario 4 arrives at roughly the same value by 2017 (2.1 PJ). The table below shows (i) the number of annual cycles based on storage space allocated to core or non-rate Schedule 16 customers under each of the four scenarios. Scenario Send-outs (GJ) Useable Storage (less 50 TJ per) Number of cycles Tilbury Mt. Hayes Tilbury Mt. Hayes Tilbury Mt. Hayes 1 340,000 1,268, ,500 1,563, ,000 1,268, ,500 1,563, ,000 1,268, ,500 1,563, ,000 1,268, ,500 1,563, This table shows that based on core and non-rate Schedule 16 requirements there is fewer than one cycle period in each scenario. The table below shows (ii) the number of annual cycles based on storage space allocated to commercial LNG customers under each of the four scenarios. Scenario LNG demand Storage Allocation Number of cycles 1-100, , , ,642, , ,190, ,000 22

18 Page 17 This table shows that at the largest demand under Scenario 4 the storage allocation cycles 22 times annually (forecast year is 2017). Rate Schedule 16 storage allocation cycles are higher that core market storage allocation cycles because Rate Schedule 16 demand is forecast to be flat. Core requirement cycles are low as demand is highly peaked into one or two send-out periods. 7.4 Please provide the forecasted total deliverability costs for FEI for each year, , from the named facilities under the various load growth scenarios. As explained in the response to BCPSO IR 1.7.3, these scenarios were not contemplated over a specific time period. The total deliverability costs under each scenario are shown in the Application, Table 9-3 under the column titled Total O&M. FEI has provided a copy of Table 9-3 below. Tilbury Total Production (GJ) Incremental Production (GJ) Total O&M Incremental O&M Incremental $/GJ S1-Base 340, ,000-1,868,807 - $ - Appenidix N, Page 1 S2-Base + 380, , ,000 2,171, ,863 $ 0.80 Appenidix N, Page 2 S3-Base + 912,500 1,252, ,500 2,735, ,172 $ 0.95 Appenidix N, Page 3 S4-Base + 1,168,000 1,508,000 1,168,000 3,123,729 1,254,922 $ 1.07 Appenidix N, Page 4 Appendix Line Number Mt Hayes Total Production (GJ) Incremental Production (GJ) Total O&M Incremental O&M Incremental $/GJ S1-Base 1,268,000 1,268,000-3,535,205 - $ - Appenidix N, Page 5 S2-Base + 380,000 1,648, ,000 3,838, ,499 $ 0.80 Appenidix N, Page 6 S3-Base + 730,000 1,998, ,000 4,127, ,256 $ 0.81 Appenidix N, Page 7 S4-Base + 1,022,000 2,290,000 1,022,000 4,376, ,290 $ 0.82 Appenidix N, Page 8 Appendix Line Number

19 Page Reference: Exhibit B-1, pages 66, Table 9-9, Benefits to Non-Rate 16 Customers 8.1 Please provide a Table similar to Table 9-9 that summarizes the benefits to non- Rate 16 customers under scenarios 1-4 under the assumption that the existing Rate Schedule 16 remains in effect. The Rate Schedule 16 tariff as it currently exists is an interruptible tariff with a supply cap for Rate Schedule 16 customers of 1,040 GJs per day from the Tilbury facility, or 379,600 GJs per year. Assuming that the maximum annual supply cap of 379,600 GJs per year is achieved, if the existing Rate Schedule 16 tariff were to remain in effect, each of Scenarios 2-4 would provide an equal benefit of approximately $1.2 million for non-rate Schedule 16 customers, as the supply cap of 379,600 GJs cannot be exceeded. The table below summarizes this potential incremental benefit to non-rate Schedule 16 customers under all four scenarios at a delivery rate of $4.05/GJ, assuming that the maximum annual supply cap of 379,600 GJs per year is achieved: Line Particulars Source Scenario 1 Scenario 2 Scenario 3 Scenario 4 1 RS 16 Rate Current Charge RS 16 Volume Supply Cap - 379, , ,600 3 Incremental Revenue Line 1 * Line 2-1,537,380 1,537,380 1,537,380 4 Incremental O&M Table , , ,863 5 Benefit to Natural Gas CustomersLine 3 - Line 4 $ - $ 1,234,517 $ 1,234,517 $ 1,234,517 It is, however, highly unlikely that maximum annual supply cap would be reached if Rate Schedule 16 is not approved as a permanent tariff. The temporary nature of the tariff is a significant deterrent for potential LNG customers, who require certainty regarding a reliable supply source in order to proceed with a transition to natural gas vehicles. Therefore, the actual benefit to non-rate Schedule 16 customers is certain to be much lower than the benefit shown in the table above. In addition, the benefit to non-rate Schedule 16 customers under the current tariff would only be realized for 2013 and The approval of Rate Schedule 16 as a permanent tariff would provide ongoing annual benefits for non-rate Schedule 16 customers, and would also benefit British Columbia residents as a whole through reduced GHG emissions.