November 16, British Columbia Utilities Commission 6th Floor, 900 Howe Street Vancouver, BC V6Z 2N3

Diane Roy Director, Regulatory Affairs - Gas FortisBC Energy Inc. FORTISBC ENERGY BFI COMPLIANCE FILING EXHIBIT B-1 November 16, 2012 16705 Fraser Highway Surrey, B.C. V4N 0E8 Tel: (604) 576-7349 Cell: (604) 908-2790 Fax: (604) 576-7074 Email: diane.roy@fortisbc.com www.fortisbc.com Regulatory Affairs Correspondence Email: gas.regulatory.affairs@fortisbc.com British Columbia Utilities Commission 6th Floor, 900 Howe Street Vancouver, BC V6Z 2N3 Attention: Ms. Erica M. Hamilton, Commission Secretary Dear Ms. Hamilton: Re: FortisBC Energy Inc. ( FEI ) Application for a Certificate of Public Convenience and Necessity ( CPCN ) for Constructing and Operating a Compressed Natural Gas ( CNG ) Refueling Station at BFI Canada Inc. ( BFI ) and Application for Variance and Reconsideration and Revised Application for Rates for Fueling Service for BFI British Columbia Utilities Commission (the Commission ) Order No. G-150-12 Compliance Filing On June 15, 2012, FEI submitted an Application for Variance and Reconsideration of Order No. C-6-12 ( Reconsideration Application ) and a revised application for rate design for CNG Service for BFI ( Revised Rates Application ). On September 14, 2012, the Commission issued Order No. G-126-12, approving a fueling charge as proposed in the Revised Rates Application on an interim basis. On October 17, 2012, the Commission issued its decision on the Reconsideration Application by Order No. G-150-12, and in Directive 3 of Order No. G-150-12, reiterated the previous requirement in Order No. G-126-12, also Directive 3, to confirm rates as applied for in the Revised Rates Application or apply for revised rates. Attached is FEI s filing in compliance with Directive 3 of Order No. G-150-12. If you require further information or have any questions regarding this submission, please contact the undersigned. Yours very truly, FORTISBC ENERGY INC. Original signed: Diane Roy Attachment

November 16, 2012 British Columbia Utilities Commission BFI CPCN Order G-150-12 Compliance Filing Page 2

FORTISBC ENERGY INC. BFI CPCN ORDER G-150-12 COMPLIANCE FILING 1. APPROVALS SOUGHT On January 31, 2012, FortisBC Energy Inc. ( FEI or the Company ) and BFI Canada Inc. ( BFI ) entered into an agreement which provides for FEI to supply, install and maintain a Compressed Natural Gas ( CNG ) refueling station on BFI s premises and to charge BFI for its CNG fueling station service. In this application (the Application or Compliance Filing ), FEI seeks the following approvals from the British Columbia Utilities Commission ( BCUC or the Commission ) under sections 59-61 of the Utilities Commission Act ( Act ) in order to provide and charge for the service: Approval of the allocation of the forecast overhead and marketing amounts to be recovered from FEI s CNG and LNG customers taking service under General Terms and Conditions Section 12B ( GT&Cs 12B ); and Approval of rate design and rates applicable to BFI as proposed in this Application on a permanent basis; and Approval to record any actual overhead and marketing charge recoveries received from CNG and LNG customers during 2012 and 2013 in the existing CNG and LNG Service Recoveries deferral account for refund to non-bypass customers starting in 2014. The approvals sought in this Application put in place a permanent rate structure to provide CNG refueling service to BFI. As well, approval of the proposed overhead and marketing charge will provide a predictable charge applicable to future CNG and LNG customers. FEI believes that the orders sought are just and reasonable. 2. BACKGROUND On February 29, 2012, FEI filed an application with the BCUC for a Certificate of Public Convenience and Necessity ( CPCN ) to construct and operate a CNG refueling station at the premises of BFI (the BFI Application ). On April 30, 2012, the Commission issued Order No. C- 6-12, granting a CPCN for the BFI Project but declining to approve the rates to be charged to BFI for providing CNG fueling service ( BFI Decision ). The Commission directed FEI to file an updated rate and rate design within 30 days of that Order. On June 15, 2012, FEI submitted an Application for Variance and Reconsideration of Order No. C-6-12 ( Reconsideration Application ) and a revised application for rate design for CNG Service for BFI ( Revised Rates Application ). Related to the rate design, FEI sought approval of an updated fueling charge proposed in the Revised Rates Application on an interim basis, pending the determination of the Reconsideration Application. In the Revised Rates Application FEI detailed a proposed cost methodology of the overhead and marketing charge applicable to BFI and all other CNG and LNG customers. This charge reflected the cost of the CNG/LNG Service program based on the figures of $569,396 for 2012 and $601,119 for 2013, allocated among CNG/LNG Service customers in a reasonable manner. Page 1

FORTISBC ENERGY INC. BFI CPCN ORDER G-150-12 COMPLIANCE FILING On September 14, 2012, the Commission issued Order No. G-126-12, approving a fueling charge as proposed in the Revised Rates Application on an interim basis, which enabled FEI to provide CNG service to meet BFI s operational deadline of October 1, 2012. Commission Order No. G-126-12 also set out in Directive 3 that FEI is to submit either a confirmation that the rates as applied for in the Revised Rates Application remain applicable or file an application for revised rates as appropriate. A final decision on the Reconsideration Application was issued by the Commission on October 17, 2012 by Order No. G-150-12 ( Reconsideration Decision ). 1 In the Reconsideration Decision, also under Directive 3, the Commission reiterated the previous requirement in Order No. G-126-12, to confirm rates as applied for in the Revised Rates Application or apply for revised rates (the Compliance Filing ). In the Reconsideration Decision, related to rate design and Order 5(b), the Commission states on Page 4: The Panel varies Order 5(b) to state: the figures of $569,396 for 2012 and $601,119 for 2013, [are] to be allocated among CNG/LNG Service customers and non-bypass natural gas customers in a reasonable manner. [Emphasis added]. Further on page 5 of the Reconsideration Decision, the Commission states: However, the Panel would consider an alternative allocation of forecast overhead amounts of $569,396 for 2012 and $601,119 for 2013, between the natural gas ratepayers and the customers taking service under tariff GT&C 12B, if FEI can provide a sufficient evidentiary basis for its proposed allocation. In this Compliance Filing, FEI provides its evidentiary basis for an allocation of these overhead amounts which reflects FEI s actual activities. This filing also proposes a fueling charge for BFI, on a permanent basis, based on the actual construction cost of BFI s CNG fueling station and an amended allocation of overhead costs. If approved by the Commission, FEI will amend the Fueling Station License and Use Agreement with BFI to reflect the permanent fueling charge. 3. OVERHEAD AND MARKETING CHARGE In the BFI Application, FEI proposed a methodology which would recover the incremental overhead and marketing costs associated with another CNG/LNG customer such as BFI. FEI proposed a charge of $0.20 per GJ, which would have recovered approximately $84,000 from BFI over the initial term of their contract. The BFI Decision directed FEI to revise this charge using approved fully allocated cost of service methodology and included in the cost of service and to recalculate the Operations and 1 This Compliance Filing does not delve into the BCUC variance of Order 3 and Order 5(e) as these items are more relevant to the AES Inquiry proceeding. Page 2

FORTISBC ENERGY INC. BFI CPCN ORDER G-150-12 COMPLIANCE FILING Maintenance charge in the BFI rate using the figures of $569,396 for 2012 and $601,119 for 2013, to be allocated among CNG/LNG Service customers in a reasonable manner. ( Order 5(b) ). 2 As the Commission acknowledged, these figures are approved in the Commission s decision regarding the FortisBC Energy Utilities Revenue Requirements Application for the 2012 and 2013 test years (the FEU 2012-2013 RRA ) for overhead, marketing, business development and customer education related to natural gas vehicle (NGV) services. FEI s position in the Reconsideration Application was that the $569,396 for 2012 and $601,119 for 2013 pertain to the overall development 3 of using natural gas as a fuel for transportation, not only the development of the CNG/LNG fueling station service. Much more effort is involved in convincing a potential NGT customer to switch their fleet to natural gas than is involved in developing a station for a customer once the decision to adopt natural gas vehicles has been made. However, for the purposes of the June 15, 2012 Revised Rates Application, the calculations complied with the Commission direction set forth in the BFI Decision, pending determination of the Reconsideration Application. The Revised Rates Application proposed an overhead and marketing charge of $0.38 per GJ applicable to BFI and future CNG and LNG customers, subject to approval by the BCUC. Pursuant to Commission order G-126-12 item 4, FEI will provide a refund to BFI for the difference between the final rate and the interim rate plus interest. Based on the Commission s variance of Order 5(b) in the Reconsideration Decision, FEI is proposing a different allocation of forecast overhead figures based on the additional evidence included in this filing. 3.1 Commission Directives in the Reconsideration Decision In the Reconsideration Decision at Page 5, the Commission requested a number of items to be provided in support of the overhead allocation. These items are: 1) A chronology of the negotiations with each of the existing customers (Waste Management, BFI, Vedder); 2) Staff resources allocated; 3) A list of activities undertaken to develop the NGT market generally; 4) Description of activities with other vendors in the marketplace to assist them in their marketing efforts; 5) Description of any amounts of overhead included in various rate schedules applicable to CNG/LNG Service and their source; 6) Provide evidence that increased throughput will benefit core customers and quantify those benefits to NGT customers; 2 3 BCUC Order No. C-6-12, Order 5(b) at Page 4 FEI defines this term in Appendix C Page 3

FORTISBC ENERGY INC. BFI CPCN ORDER G-150-12 COMPLIANCE FILING 7) Provide justification for the allocation of costs among the customers taking service under GT&Cs 12B; and 8) Propose a mechanism to ensure that there is no double recovery of any costs. Each of these items is addressed in the following subsections of this Compliance Filing. The information provided in these sections forms the evidentiary basis for FEI s proposed allocation of overhead charges. The calculation of the overhead charge is described further in section 3.2. 3.1.1 CHRONOLOGY OF NEGOTIATIONS WITH EXISTING CUSTOMERS FEI has summarized the chronology of each project (Waste Management, BFI, Vedder) on a quarterly basis in Appendix A of this Compliance Filing. The information shown in the three tables in Appendix A details the chronology of activities pertaining to the general development path of each fueling station. With the exception of rate approval, all of these activities are undertaken by the staff resources described in subsection 3.1.2 and included in the overhead and marketing charge in section 3.2. Construction of the fueling station also includes a project manager and various service providers whose time and costs are recovered in the capital expenditure for each individual CNG/LNG project. Customer inquiry, initial presentation; Contract negotiations; Site feasibility; Fueling station agreement; Regulatory applications; Fueling station construction; Rate approval; and Fueling station final commissioning. Over time, FEI expects the time spent on the end-to-end development of each CNG/LNG project to decrease. The timeline of the Waste Management ( WM ) CNG project compared to the BFI CNG project illustrates improved efficiency. Since the BFI Agreement was based on approved GT&Cs 12B, the time required to develop and negotiate a legal contract and regulatory application was less than required for WM. The build and install period of BFI s fueling station was also shorter given the experience gained from the WM project. In this Compliance Filing FEI has estimated the time related to its CNG/LNG projects. FEI does not code time sheets for each individual project. As such, FEI does not have an hourly breakdown of time spent on each CNG/LNG project. Page 4

FORTISBC ENERGY INC. BFI CPCN ORDER G-150-12 COMPLIANCE FILING 3.1.2 STAFF RESOURCES ALLOCATED For 2012 and 2013, FEI has identified six (6) employee positions which are directly involved in the development of CNG and LNG fueling stations. 4 These employees spend a portion of their time on the fueling station components of FEI s NGT initiatives. They also spend a significant portion of their time on other NGT activities and other business development initiatives. Since FEI does not code timesheets related to CNG and LNG projects, FEI has developed a percentage estimate of the time spent on fueling stations relative to other activities and responsibilities held by each position. To develop this estimate, FEI has: Identified the employees associated with fueling station development; Determined which employee s time is recovered in the fueling station project capital; 5 Surveyed each employee for their time spent on fueling station development in 2012; Verified this estimate with each employee s manager. The six positions associated with fueling station development are listed below, with related job descriptions provided in Appendix B. 1) Senior Manager, Business Development (BD); 2) Business Development (BD) Manager; 3) Business Development (BD) Specialist; 4) Manager, NGT Solutions (formerly Commercial and Industrial Sales Manager); 5) NGT Account Manager; and 6) Manager, New Product Development (NPD) (formerly Energy Products and Services Manager). Table 1 below summarizes a time allocation estimate by percentage of fueling station activities compared to other activities for each employee. 4 5 FEI s previous forecast of $569,396 in 2012 and $601,119 in 2013 reflected overall NGT development activities and totaled four full-time equivalent positions. Two other positions (Project Manager and New Product Development Specialist) are involved in fueling station construction activities however their proportionate time is allocated to the capital expenditures for each NGT project. Page 5

FORTISBC ENERGY INC. BFI CPCN ORDER G-150-12 COMPLIANCE FILING Table 1: Fueling Station Activities Represent 2.15 Full-Time Equivalents Fueling Station Time Allocation Other activites Title Senior Manager, BD 15% 85% BD Manager 50% 50% BD Specialist 15% 85% Manager, NGT Solutions 50% 50% NGT Account Manager 25% 75% Manager, NPD 60% 40% Total FTE: 2.15 3.85 In total, the time allocation toward CNG and LNG fueling station development is 2.15 full time equivalents ( FTE ) for 2012. FEI has assumed this same allocation of 2.15 FTE over the period from 2013 through 2017. This allocation is more accurate than FEI s previous estimate which formed the $0.20 per GJ overhead and marketing charge. The previous estimate was a forecast based on the expected time required to develop fueling stations. At the time this estimate was conducted FEI had only developed one CNG fueling station. The allocation presented in this Application reflects actual activities in 2012 which contributed to the development of FEI s three fueling station customers. The fueling station activities included in the 2.15 FTE were described in the previous section 3.1.1. The activities included in the remaining 3.85 FTE are shown in the figure below, which breaks down the time allocation of all six employees. Page 6

FORTISBC ENERGY INC. BFI CPCN ORDER G-150-12 COMPLIANCE FILING Figure 1: Total activity breakdown of six employees 6 0.10 0.10 0.05 NGT Fueling Stations 0.10 0.30 NGT Incentives Rate 6 / Light Duty FEI Fleet conversion 0.70 2.15 NGT Advocacy NGT Codes Standards 0.35 NGT Training Standards LNG Tankers 0.10 0.20 0.20 Rate 16 Application Remote LNG Marine LNG 0.05 0.40 1.20 Renewable Natural Gas Renewable Fuels Admin This figure illustrates that fueling station activities are only a portion of the work undertaken by these employees. For example, the Senior Manager, Business Development spends approximately 15 percent of his time on NGT fueling station activities, but 85 percent on other business development activities, FEI s Renewable Natural Gas program, and other long term low carbon / LNG opportunities (i.e. remote communities) among other tasks. Over time, FEI expects this allocation will change, however it is difficult to estimate whether the 2.15 FTE will decrease or increase. Since the Commission has approved GT&Cs 12B, FEI expects future CNG/LNG rate applications will be generally more efficient and require less time. As well, FEI s NGT business model and strategic direction is already well defined. Therefore FEI anticipates that Business Development positions will spend less time on fueling station development in the future. In contrast, FEI may require greater staff resources from the New Product Development and NGT Sales groups to build and install more fueling stations to meet customer demand. Activities such as customer negotiations, site feasibility, and fueling station construction may increase in the future. Other NGT activities NGT incentives, Rate Schedule 6 sales, FEI s own fleet conversion, NGT industry advocacy, NGT codes & standards, NGT training standards relate to overall development of the NGT industry in BC and Canada. 7 FEI s believes that these costs are most 6 7 A description of each activity category is provided in Appendix C. These activities sum to 2.15 FTE. Page 7

FORTISBC ENERGY INC. BFI CPCN ORDER G-150-12 COMPLIANCE FILING appropriately allocated to non-bypass natural gas customers as their purpose is to increase the adoption of NGT and throughput on the natural gas system. 3.1.2.1 Value of Staff Resources The value of these staff resources is based on budgeted salary amounts (fully loaded) for 2012 and 2013, escalated at a labour inflation rate of 3 percent per year until 2017. The table below shows the percentage allocated related to NGT fueling stations and the proportionate cost figure (in $) for 2012 through 2017. Table 2: Forecast staff resource cost related to fueling station activities 2012-2017 Title Fueling Station Time Allocation 2012 2013 2014 2015 2016 2017 Senior Manager, BD 15% 24,848 25,151 25,906 26,683 27,483 28,308 BD Manager 50% 59,000 59,373 61,154 62,988 64,878 66,824 BD Specialist 15% 15,450 15,660 16,130 16,614 17,112 17,625 Manager, NGT Solutions 50% 71,750 75,110 77,363 79,684 82,075 84,537 NGT Account Manager 25% 25,500 25,750 26,523 27,318 28,138 28,982 Manager, NPD 60% 81,000 81,540 83,986 86,506 89,101 91,774 Total 277,548 282,584 291,061 299,793 308,787 318,051 Total FTE: 2.15 Time allocations for fueling stations may fluctuate on a yearly basis over the 2012 through 2017 period, but for the purposes of developing an overhead charge FEI has assumed this to be constant over this time period and reflective of an average activity level. Please see section 3.2 for the cost methodology and calculation of the overhead and marketing charge that results from these salary forecasts. 3.1.3 ACTIVITIES UNDERTAKEN TO DEVELOP THE NGT MARKET GENERALLY In the Revised Rates Application, FEI stated that the amounts of $569,396 for 2012 and $601,119 for 2013 include, but are not limited to, the following NGT activities: a. NGT development and advocacy within British Columbia; b. Natural gas delivery service support (Rate Schedules 6, 16, 23, 25); c. Development of marine market applications; d. Development of Rate Schedule 16 amendments application; and e. Consultation and advice on the Province s recently enacted Greenhouse Gas Reduction (Clean Energy) Regulation (the GGRR ). In this Compliance Filing, FEI has divided these activities into the following categories: 1. NGT fueling stations; 2. NGT incentives; Page 8

FORTISBC ENERGY INC. BFI CPCN ORDER G-150-12 COMPLIANCE FILING 3. Rate Schedule 6 (light duty vehicles); 4. FEI fleet conversion; 5. NGT industry advocacy; 6. NGT codes & standards; and 7. NGT training standards. Consultation leading up to the GGRR is included under the NGT industry advocacy category for the purposes of developing staff resource allocations. Other LNG activities such as LNG marine projects, FEI s LNG tanker offering and the Rate Schedule 16 Amendments Application are not limited to CNG/LNG fueling station customers. These activities may benefit a host of other potential customers (e.g. LNG for remote communities, mines) throughout the Province, some of which have greater market potential than NGT fueling station projects. 8 Other third party service providers should also benefit from FEI s NGT development activities. If FEI is successful in receiving Commission approvals for increased access under the Rate Schedule 16 Amendments Application, other parties may have increased access to LNG for their customers elsewhere. Other parties should benefit from the GGRR including equipment manufacturers such as Westport Innovations and IMW Industries, and other third party service providers such as Clean Energy Fuels. 3.1.4 ACTIVITIES WITH OTHER VENDORS IN THE MARKETPLACE TO ASSIST THEM IN THEIR MARKETING EFFORTS In the Revised Rates Application at Page 8, FEI forecast customer education costs of $61 thousand in 2012 and $75 thousand in 2013. These amounts reflect costs to develop NGT sales material and a promotional video for FEI s external website. In general, FEI attracts fueling station customers through direct sales channels and does not strategically pursue marketing opportunities with other vendors. Marketing collaboration with other vendors such as Westport Innovations is limited and FEI has not forecast customer education costs for these activities. In this Compliance Filing, FEI has updated the customer education cost for 2012 to reflect actual costs, which is approximately $70 thousand. 9 This includes sales material, promotional video updates, and FEI s participation at GLOBE 2012 and Truxpo 2012 events (where NGT services including fueling station initiatives were featured). Also included in the $70 thousand total is $40 thousand provided to the Canadian Natural Gas Vehicle Alliance ( CNGVA ) to support the development of codes and standards and safety training in B.C. and across Canada. FEI has allocated the full $70 thousand across FEI s CNG and LNG fueling station customers. 8 Please refer to FEI s Application for Amendments to Rate Schedule 16. 9 Actual cost as of November 2012. No further costs are expected in December of 2012. Page 9

FORTISBC ENERGY INC. BFI CPCN ORDER G-150-12 COMPLIANCE FILING FEI s forecast customer education costs (and staff resource costs from Table 2 above) over the years 2012 through 2017 are summarized in the table below. Table 3: Forecast overhead and marketing costs related to fueling station activities 2012-2017 Item 2012 2013 2014 2015 2016 2017 TOTAL Staff resource cost 277,548 282,584 291,061 299,793 308,787 318,051 1,777,823 Customer Education 70,000 75,000 80,000 90,000 70,000 60,000 445,000 Total fueling station overhead costs $ 347,548 $ 357,584 $ 371,061 $ 389,793 $ 378,787 $ 378,051 $ 2,222,823 This forecast does not include vehicle and fueling station branding costs. The BFI Decision directed FEI to recover branding costs for vehicle decals and station signage from BFI through their fueling charge. FEI agrees it is reasonable to include the signage cost of the fueling station in each customer s capital expenditure and recover it through the fueling charge. The treatment of vehicle decal costs is slightly different, as some vehicle customers will not choose FEI to provide fueling station service but may receive vehicle incentives under FEI s NGT Incentive Program. For future CNG/LNG customers, FEI will recover branding costs related to vehicles under the GGRR expenditure allowance for Administration, marketing, training and education when vehicle incentives are provided by FEI under the GGRR. 3.1.5 OVERHEAD INCLUDED IN VARIOUS RATE SCHEDULES APPLICABLE TO CNG/LNG FUELING STATION SERVICE In the Revised Rates Application, FEI included overhead amounts of $569,396 for 2012 and $601,119 for 2013. These amounts are in support of NGT activities detailed in section 3.1.3 and are marketing efforts which FEI allocates to rate classes based on customer counts. Of the overhead amounts for 2012 and 2013, Table 4 shows the amount included in various FEI Rate Schedules that offer CNG/LNG service. Table 4: Overhead Allocation to Rate Schedules 3.1.6 INCREASED THROUGHPUT WILL BENEFIT CORE CUSTOMERS, AND QUANTIFICATION OF BENEFITS TO NGT CUSTOMERS In the Reconsideration Decision, the BCUC agreed that, to the extent fueling stations increase throughput, all things being equal, there may be a benefit to all ratepayers. 10 In FEI s Application for Rate Treatment of GGRR Expenditures proceeding FEI further quantified delivery margin benefit from its existing NGT customers 11 and forecast the delivery margin 10 BCUC Order No. G-150-12, at page 5 11 BCUC IR 1.5.1. Page 10

FORTISBC ENERGY INC. BFI CPCN ORDER G-150-12 COMPLIANCE FILING benefit under two scenarios. 12 These delivery margin benefits are summarized in Appendix D. These delivery margin benefits would not have occurred without FEI s involvement in the market. Since FEI s involvement in the fueling station market, four CNG/LNG customers have constructed fueling stations. Without an end-to-end fueling station offering and prior to FEI s involvement, nearly a decade of inactivity passed. The GGRR is also premised on the idea that public utility involvement in CNG/LNG is the way to spur market uptake. The fuel cost savings to NGT customers has also been thoroughly canvassed in the GGRR Rate Treatment proceeding. FEI estimates the fuel cost savings associated with its existing CNG/LNG customers is approximately $3.2 million per year (see Appendix E). 13 In general, FEI expects CNG/LNG customers to save 25 to 50 percent in annual fueling costs. 3.1.7 JUSTIFICATION FOR THE ALLOCATION OF COSTS AMONG THE CUSTOMERS TAKING SERVICE UNDER GT&CS 12B CNG and LNG customers taking service under GT&Cs 12B have requested and contracted with FEI to provide fueling station service for their fleet. The overhead and marketing charge component of the customer s fueling charge recovers those overhead costs directly associated with the development of each customer s fueling station, reducing the amount recovered from other natural gas ratepayers. FEI s natural gas ratepayers are insulated from much of the risk of CNG/LNG fueling station investments due to the structure of GT&Cs 12B. FEI believes the proposed allocation of overhead costs in this Compliance Filing is fair and reasonable to CNG/LNG customers and natural gas ratepayers because the overhead rate 14 is derived from the activities of employees supporting the CNG/LNG business. 3.1.8 PROPOSED MECHANISM TO ENSURE THAT THERE IS NO DOUBLE RECOVERY OF ANY COSTS FEI had forecast the costs of $569,396 for 2012 and $601,119 for 2013 in its 2012-2013 RRA, and the recovery of these costs from all natural gas ratepayers was approved through Commission Order No. G-44-12. Since a portion of these costs are now proposed to be recovered directly from CNG and LNG customers, to avoid double recovery of these costs, FEI is proposing to record any actual recoveries received from CNG and LNG customers during 2012 and 2013 in a deferral account for refund to non-bypass customers starting in 2014. If FEI s proposed overhead charge of $0.28 per GJ (see section 3.2) is approved by the Commission, FEI would amend its fueling station agreement with existing customers to reflect this new charge. The timing of this means the double recovery impact would occur in 2013 and a portion of 2012. At this time, three customers (Vedder, BFI and Kelowna School District or KSD) are subject to the overhead and marketing charge. 15 The forecast overhead charge revenues from these three customers for 2012 and 2013 are as follows: 12 GGRR Rate Treatment Application, Appendix G and Appendix H. 13 In the GGRR proceeding, CEC IR 1.11.2 14 Section 3.2 15 Commission Order No. G-128-11 determined the final rate approval for Waste Management. Page 11

FORTISBC ENERGY INC. BFI CPCN ORDER G-150-12 COMPLIANCE FILING BFI (15,000 GJ in 2012, and 60,000 GJ in 2013) = 75,000 * $0.28/GJ = $21,000 16 Vedder (15,833 GJ in 2012, and 190,000 GJ in 2013) = 205,833 * $0.28/GJ = $57,633 17 KSD (5,000 GJ in 2013) = 5,000 * $0.28/GJ = $1,400 The total overhead charge recoveries from these three customers is $80,033. If FEI adds any other CNG/LNG customers under GT&Cs 12B during 2013 these would also be subject to deferral account treatment. At the end of 2013, FEI will calculate the total overhead charge recoveries collected from all customers based on actual volumes and transfer the total to the existing CNG and LNG Service Recoveries deferral account. For subsequent years, the overhead charge will be included in the forecast of station revenues, effectively crediting nonbypass customers rates. 3.2 Cost Allocation Calculation The methodology to calculate the overhead charge is the division of the total forecast overhead costs (see Table 3) by the forecast CNG/LNG volumes (stimulated by the GGRR) until the end of the GGRR period in 2017. FEI intends to apply this methodology to future CNG/LNG service agreements. The forecast overhead and marketing costs and FEI s forecast CNG and LNG volumes as provided in the GGRR application are summarized in the table below. Table 5: Projected NGT Overhead and Marketing Budgets and Volume Forecast 2012 2013 2014 2015 2016 2017 TOTAL Staff Resources 277,548 282,584 291,061 299,793 308,787 318,051 1,777,823 Customer Education 70,000 75,000 80,000 90,000 70,000 60,000 445,000 Total Fueling station cost $ 347,548 $ 357,584 $ 371,061 $ 389,793 $ 378,787 $ 378,051 $ 2,222,823 GGRR Projected Volumes 178,000 457,938 917,155 1,416,098 2,032,387 2,882,287 7,883,865 Annual Charge ($/GJ) $ 1.95 $ 0.78 $ 0.40 $ 0.28 $ 0.19 $ 0.13 $ 0.28 This charge of $0.28 per GJ is embedded in the O&M portion of the fueling charge included in the revised rates for BFI. Under an amended BFI Agreement, the total overhead and marketing charge ($0.28 per GJ x 60,000 GJ) would recover $16,800 per year, or $117,600 (plus inflation) over the 7 year contract term. 4. PROPOSED FUELING SERVICE CHARGE FOR BFI In the Revised Rates Application and based on BCUC directives in the BFI Decision, FEI had proposed the following fueling charges for BFI: 16 Overhead and marketing charge recoveries began in October 1, 2012 when BFI fueling station entered service. 17 Overhead and marketing charge applies to Vedder s permanent station, which is expected to enter service in December 2012. Page 12

FORTISBC ENERGY INC. BFI CPCN ORDER G-150-12 COMPLIANCE FILING Table 6: BFI Interim Fueling Charges Component Fueling Charge Escalation ($ per GJ) per year Capital $ 3.66 2% O&M $ 0.85 CPI Overhead $ 0.38 CPI Total charge $ 4.89 This rate was approved in Commission Order No. G-126-12 on an interim basis. As described in section 3.2, FEI has calculated revised overhead and marketing charge. As well, FEI has updated the capital charge below based on the actual construction cost of BFI s fueling station, which commenced service on October 1, 2012. 4.1 BFI Fueling Station Capital Expenditures FEI completed the final commissioning of BFI s fueling station in mid-september 2012 following a four month construction period. BFI began fueling its fleet of CNG trucks on October 1, 2012 in order to meet a requirement set by the City of Surrey. In the table below, the actual costs of the fueling station are reconciled with the forecast cost presented in the CPCN Application. Table 7: BFI Fueling Station Actual Capital Expenditures Item BFI BFI CPCN Application Actual cost CNG Storage and Dispensing Equipment $ 770,531 $ 807,492 Civil, Structural Work $ 401,440 $ 354,558 Mechanical and Field Piping $ 93,331 $ 112,911 Electrical Work and Service $ 210,635 $ 175,022 Equipment Shipping $ 15,700 $ 19,202 FortisBC Engineering, Project Management, Commissioning $ 199,875 $ 231,732 Branding Cost $ - $ 2,765 Subtotal $ 1,691,512 $ 1,703,682 Contingency 10% - Total with Contingency $ 1,860,663 $ 1,703,682 The total capital expenditure of the fueling station was $1.7 million; $160 thousand lower than initially forecast. The primary variance element was the Project contingency which was not required during the construction of the fueling station. The total favourable variance was approximately 8.6 percent, which exceeds the 2 percent variance condition in the BFI Agreement. Thus FEI has recalculated BFI s fueling charge based on a cost of $1.7 million for submission of final rate approval in this filing. Page 13

FORTISBC ENERGY INC. BFI CPCN ORDER G-150-12 COMPLIANCE FILING 4.2 Proposed Fueling Charge for BFI Other than changes to the capital amount and the overhead and marketing charge, no element of the cost of service calculation has changed since the Revised Rates Application. Since the overhead charge was calculated using forecast costs (including expected inflation) for six years, and the BFI contract has a seven year term, FEI is not proposing to escalate the overhead rate for BFI because it already reflects inflationary impacts. The table below summarizes the proposed fueling charges for BFI, on a permanent basis. Table 8: BFI Permanent Fueling Charges Component Fueling Charge ($ per GJ) Esacalation per year Capital $ 3.33 2% O&M $ 0.85 CPI Overhead $ 0.28 Total Charge $ 4.46 Please see Appendix F for the detailed financial schedules supporting these calculations. 5. SUMMARY In this Compliance Filing, FEI has provided evidence of an allocation which accurately reflects the Company s activities related to fueling station development and a proposed overhead and marketing charge of $0.28 per GJ. FEI has also proposed a permanent fueling station rate for BFI which reflects the actual cost of construction and the proposed overhead and marketing charge. If approved by the Commission, FEI will amend its fueling station agreement with BFI to account for these changes retroactive to October 1, 2012. Page 14

Appendix A CHRONOLOGY OF CUSTOMER NEGOTIATIONS

Activites 2010 2011 Staff 1 2 3 4 1 2 3 4 Allocated Customer inquiry, initial presentation Manager, NGT Contract negotiations Sr Manager BD / Manager, NGT Conduct site feasibility Manager, NPD CNG/LNG & WM Application - December 1, 2010 Sr Manager BD / BD Manager Fueling station agreement - December 3, 2010 Sr Manager BD / Manager, NGT Fueling station construction Manager, NPD Interim rate approval - January 14, 2011 BCUC Fueling station agreement amended - February 17, 2011 Manager, NGT Fueling station final commissioning, trucks fueling Manager, NPD Final rate approval - July 19, 2011 BCUC

Activites 2010 2011 2012 Staff 1 2 3 4 1 2 3 4 1 2 3 4 Allocated Customer inquiry, initial presentation Manager, NGT Contract negotiations - ongoing Manager, NGT Conduct site feasibility Manager, NPD CNG/LNG & WM Application - December 1, 2010 Sr Manager BD / BD Manager Temp fueling station agreement - May 12, 2011 Sr Manager BD / Manager, NGT Temp fueling station final commissioning, trucks fueling Manager, NPD Permanent fueling station agreement - March 2, 2012 Manager, NGT Permanent fueling station construction Manager, NPD Vedder CPCN Application - July 13, 2012 BD Manager Interim rate approval - October 5, 2012 BCUC Permanent fueling station final commissioning Manager, NPD

Activites 2011 2012 Staff 1 2 3 4 1 2 3 4 Allocated Customer inquiry, initial presentation Manager, NGT Contractual negotiations Manager, NGT Conduct site feasibility Manager, NPD Fueling station agreement - January 31, 2012 Sr Manager BD / Manager, NGT BFI CPCN Application - February 29, 2012 BD Manager CPCN Approved - April 30, 2012 BCUC BFI Revised Rates Application - June 15, 2012 BD Manager Fueling station construction Manager, NPD Interim rate approval - September 14, 2012 BCUC Fueling station final commissioning, trucks fueling Manager, NPD

Appendix B JOB DESCRIPTIONS

Job Title: Senior Manager, Business Development Management and Exempt Role Description Band: Department: Business Development Job Family: External Relationships Division/Business Area: Gas Energy Solutions Date: September 20, 2012 Job Summary: Reporting to the Director, Business Development, this position is responsible to contribute to the growth of FortisBC s investment opportunities and revenues in the effective development and execution of new business in strategic market areas including Natural Gas for Transportation (NGT), Low Carbon Products and Renewable Natural Gas (LCP) and Liquefied Natural Gas (LNG). Key Accountabilities: Translate strategic objectives into a clear set of strategic initiatives that align with corporate and business development business priorities; manage regulatory implications of potential business opportunities in order to achieve long term goals. Provide subject matter expertise to senior management and executives on strategic relationship issues and the impact of various operational decisions; recommend path finding, innovative and strategic solutions, ideas, and approaches that enable and contribute to the significant growth of the NGT, LCP and LNG markets; define and execute business strategy and regulatory plans, secure supporting government policy to facilitate displacement of higher carbon fuels, identify appropriate segments for market penetration, develop the regulatory model and approvals for NGT/LCP/LNG offerings and negotiate commercial agreements with key customers and stakeholders. Provide leadership to business development team in the development of new business lines in strategic markets and deliver capital investment of long term business opportunities exceeding $1 billion; oversee capital project compliance and profitability guidelines. Develop and implement business development processes include stage gate models and business evaluation criteria. Establish and maintain effective relationships with key stakeholders; develop cross business unit teams required to successfully implement business development strategies and tactics including operations, engineering, sales, regulatory and government relations. Provide direction to project regulatory processes including BCUC CPCN processes and authorizations for major expenditures. Act as the senior point of contact for the Natural Gas business development project portfolio and subject matter expert in the effective negotiation of agreements; develop pricing and implementation strategies and oversee the negotiation of significant changes in project specification or scope. Act as a senior level expert resource and witness for customer interaction and BCUC proceedings. Oversee business development opportunities related to low carbon products and services for both residential and commercial markets and the development of new LNG markets that will, in concert with NGT LNG demand, justify further investments in LNG production and distribution assets. Develop market research quantifying the demand potential, complete technical and commercial feasibility studies and execute market demonstration projects. Education and Experience: Masters of Business Administration from a recognized program plus 12 to 15 years of experience in a senior strategic business development capacity and managing cross functional teams.

Job Title: Senior Manager, Business Development Management and Exempt Role Description Band: Department: Business Development Job Family: External Relationships Division/Business Area: Gas Energy Solutions Date: September 20, 2012 Technical Competencies: Knowledge of energy market place Knowledge of the regulatory process Knowledge on contracts and service agreements Knowledge and experience with financial models and evaluation criteria Knowledge of project management and business development processes Demonstrated ability to communicate at a high level, with the ability to understand commercial relationships and interpret and integrate fairly complex technical and regulatory information Demonstrated ability to prepare and present information, motivate and influence others Demonstrated ability to research and document relevant topics for potential customers Demonstrated ability to establish strong working relationships with all levels of the organization. Demonstrated ability to manage and launch new strategies and products in a regulated environment Demonstrated ability to professionally represent the company at various company and stakeholder sponsored public events Demonstrated ability to manage cross functional teams including technical and commercial elements Demonstrated ability to negotiate multi-million dollar commercial agreements Demonstrated ability to form project execution teams across functional units Demonstrated ability to prioritize work and manage competing project deliverables Demonstrated ability to communicate effectively both verbally and in writing Leadership Competencies: Ability to drive for results through planning, alignment, execution, and customer experience/responsiveness Ability to make optimal decisions through accountability, judgement, problem solving, prudent risk taking, market/industry awareness, and maintaining customer focus Ability to drive and implement prudent change through continuous improvement, challenge the status quo/innovation, flexibility/adaptability and customer value innovative customer solutions Ability to build working relationships through respect & integrity, open communication, teamwork, negotiation/influence and customer relationship management Ability to lead high performance through leading by example & initiative, continuous learning & coaching, measuring, rewarding & recognizing, customer service Additional Information (for Recruiting Purposes Only): Approval: Manager Signature Job Title Date

MEMO Tel: 778-578-3831 Fax: 604.592.7522 www.fortisbc.com To All Employees Date February 22, 2012 Expression of Interest From Susan Chiu Re Business Development Manager CC BCE-73/2012 The focus of this position is to grow FortisBC s rate base and revenues by pursuing profitable new business opportunities. Investments will be achieved through the identification and evaluation of potential projects and the successful strategic negotiations of commercial terms and arrangements resulting in contracts and subsequent investment. The key success measures are developing and concluding contracts and projects that allow FortisBC to invest in assets that provide benefit to its customers and earn a rate of return for the shareholders. Key Responsibilities Identify market opportunities based on their alignment with FortisBC s strategic objectives Develop plans to move proposed projects from the idea phase through to implementation Coordinate financial analysis of project initiatives and develop supporting business case Participate in commercial negotiations with customers, partners, suppliers, or stakeholders Support regulatory process for project approvals Develop relationships with Industry stakeholders, government and other utilities Maintain awareness of all activities that affect business development potential and to advise senior management on strategic issues. Required Qualifications Completion of a post-secondary degree in a relevant field such as Business Administration, Commerce or Engineering. 5 10 years related work experience. Strong skills in the use of financial evaluation methods and in project development Knowledge of utility regulatory principles Familiarity with gas pipeline infrastructure and market participants Ability to develop and maintain collaborative relationships including demonstrated effectiveness seeking input from stakeholders and communicating and negotiating with customers and public groups. Demonstrated ability to think strategically and understand and apply business analysis methods; Corporately focused with the ability to align projects with business goals; Ability to use technology to achieve departmental targets; Combines a results-oriented focus with a capacity to manage ambiguity and change; Must be capable of high levels of initiative and judgment; Memo Page 1 of 2

Must be capable of strong project manager skills, and is well organized with ability to plan and execute projects on time; Works effectively in a team-oriented environment. Preferred Experience, Skills & Knowledge (Above the minimum requirements) Prior experience in negotiating agreements in a regulated company. If you have what it takes to be successful in this role, please respond by submitting the On-line Employee Application (Internal Application) form # 1074. Click here for the link to the form. Include a covering letter and resume outlining how you meet the position requirements to Talent Sourcing, Human Resources, Surrey Ops 1 by March 6, 2012 4:30 PM. Memo Page 2 of 2

Title: Business Development Specialist Division: Gas Business Area: External Relations and Energy Solutions Department: Business Development Management and Exempt Job Description Job Summary: Working in accordance with the organization s strategic vision, core values and leadership competencies, reporting to the Senior Manager, Business Development, this position is responsible to support the development of business development projects, regulatory applications and investment opportunities in order to deliver value to our customers and enable sustainable growth. Key Accountabilities: Develop business cases and project plans to advance proposed projects from idea phase through to implementation; coordinate market and technical feasibility analyses and financial analysis of project initiatives. Provide pertinent information to support negotiations with key stakeholders, and maintain awareness of activities that affect resource development potential Develop key working relationships with engineers, analysis and managers throughout the company as well as government and regulatory agencies. Conduct market research, analysis reports and studies; deliver presentations to internal and external stakeholders. Support regulatory process for project approvals by assisting with the submission of regulatory applications and responding to Information Requests Qualifications: Education and Experience: Bachelor s degree in a relevant field such as Business Administration, Commerce or Engineering from a recognized program plus 3 to 5 years experience in engineering and/or business development. Knowledge, Skills and Abilities: Demonstrated ability to think strategically Knowledge of utility infrastructure design and capacity planning Knowledge of utility regulatory principles and energy markets Knowledge of asset management and reliability methods Strong skills in the use of business analysis, financial evaluation methods, and project management Demonstrated ability to communicate effectively and to maintain collaborative relationships Demonstrated ability to work effectively in a team environment Strong presentation skills Leadership Competencies: Ability to drive for results through planning, alignment, execution, and customer experience/responsiveness Ability to make optimal decisions through accountability, judgement, problem solving, prudent risk taking, market/industry awareness, and maintaining customer focus Ability to drive and implement prudent change through continuous improvement, challenge the status quo/innovation, flexibility/adaptability and customer value innovative customer solutions Ability to build working relationships through respect & integrity, open communication, teamwork, negotiation/influence and customer relationship management

Title: Business Development Specialist Division: Gas Business Area: External Relations and Energy Solutions Department: Business Development Management and Exempt Job Description Ability to lead high performance through leading by example & initiative, continuous learning & coaching, measuring, rewarding & recognizing, customer service Additional Information (for Recruiting Purposes Only): Approval: Gareth Jones Director, Business Development Feb 20, 2012 Manager Signature Job Title Date

Job Title: Manager, Natural Gas Transportation Solution Department: Natural Gas Transportation Solution Management and Exempt Role Description Band: Job Family: External Relationships Division/Business Area: Gas Date: July 9, 2012 Job Summary: Working in accordance with the organization s strategic vision, core values and leadership competencies, reporting to the Director, Business Development, this position is responsible for the execution of business development activities to support the development and investment of Natural Gas Vehicle (NGV) market to meet strategic objectives. Key Accountabilities: Develop sales programs, activities and account management goals and growth strategies for the Natural Gas Vehicle (NGV) sales market; actively solicit the sale of gas compression equipment in the designated service territory and executes opportunities to add to rate base through the sale and installation of compression equipment or LNG infrastructure. Prepare economic tests; determine viability of services. Manage relationships with current NGV accounts; establish and maintain regular contact with customers, compression equipment and vehicle conversion and OEM suppliers and other equipment vendors. Maintain relationships with various groups and associations to foster ideas and opportunities for capturing natural gas vehicle loads. Work with various representatives from municipal governments or organizations to influence codes and procedures to favour safe and competitive natural gas vehicle installations. Ensure the installation of compressor meets customer s expectations. Develop relationships with various representatives from municipal governments or organizations to influence codes and procedures to favour safe and competitive natural gas vehicle installations. SME on information related to current technological advances and constraints for NGV applications. Ensure the installation meets customer s expectations; liaise with various departments regarding the effective provisioning of sales contracts and related services. Education and Experience: Bachelors Degree in Marketing, Business or Commerce or equivalent from a recognized program plus 8 to 12 years related professional sales and marketing experience in the gas industry or an equivalent combination of education, training and experience. Role Specific Knowledge, Skills and Abilities: Knowledge of energy market place natural gas vs. gasoline or diesel Knowledge of NGV equipment (vehicle and compression equipment) Knowledge on contracts and service agreements Demonstrated sales and customer account/relationship management skills Demonstrated ability to communicate at a high level, with the ability to understand commercial relationships and interpret and integrate fairly complex technical and regulatory information Demonstrated ability to prepare and present information, motivate and influence others Demonstrated ability to research and document relevant topics for potential customers Demonstrated ability to establish strong working relationships with all levels of the organization

Job Title: Manager, Natural Gas Transportation Solution Department: Natural Gas Transportation Solution Management and Exempt Role Description Band: Job Family: External Relationships Division/Business Area: Gas Date: July 9, 2012 Demonstrated ability to manage and launch new strategies and products in a regulated environment Demonstrated ability to professionally represent the company at various company and stakeholder sponsored public events Leadership Competencies: Ability to drive for results through planning, alignment, execution, and customer experience/responsiveness Ability to make optimal decisions through accountability, judgement, problem solving, prudent risk taking, market/industry awareness, and maintaining customer focus Ability to drive and implement prudent change through continuous improvement, challenge the status quo/innovation, flexibility/adaptability and customer value innovative customer solutions Ability to build working relationships through respect & integrity, open communication, teamwork, negotiation/influence and customer relationship management Ability to lead high performance through leading by example & initiative, continuous learning & coaching, measuring, rewarding & recognizing, customer service Additional Information (for Recruiting Purposes Only): Approval: Manager Signature Job Title Date

MEMO Tel:778-578-3831 Fax: 604.592.7522 www.fortisbc.com To All Employees Date October 31, 2012 Expression of Interest From Susan Chiu Re Natural Gas Vehicles Account Manager Surrey or Burnaby BCE-445/2012 Role Summary: Reporting to the Sales Manager, this position is responsible to participate in the implementation sales program activities and account management goals and growth strategies for the Natural Gas Vehicle (NGV) sales market. Actively solicit the sale of gas compression equipment in the designated service territory and execute opportunities to add to rate base through the sale and installation of compression equipment or LNG infrastructure. Prepare economic tests to determine viability of compression services. Manage relationships with current NGV accounts; establish and maintain regular contact with customers, compression equipment and vehicle conversion and OEM suppliers and other equipment vendors. Maintain relationships with various groups and associations to foster ideas and opportunities for capturing natural gas vehicle loads. Work with various representatives from municipal governments or organizations to influence codes and procedures to favour safe and competitive natural gas vehicle installations. Ensure the installation of compressor meets customer s expectations. Key Accountabilities: Participate in the implementation of sales program activities and account management goals and growth strategies for the Natural Gas Vehicle (NGV) sales market; actively solicits the sale of gas compression equipment in the designated service territory and executes opportunities to add to rate base through the sale and installation of compression equipment or LNG infrastructure. Prepares economic tests; determines viability of compression services. Manages relationships with current NGV accounts; establishes and maintains regular contact with customers, compression equipment and vehicle conversion and OEM suppliers and other equipment vendors. Maintains relationships with various groups and associations to foster ideas and opportunities for capturing natural gas vehicle loads. Works with various representatives from municipal governments or organizations to influence codes and procedures to favour safe and competitive natural gas vehicle installations. Maintains current on information related to current technological advances and constraints for NGV applications. Ensures the installation of compressor meets customer s expectations; liaises with various departments regarding the effective provisioning of sales contracts and related services. Participates in trades shows; monitors and maintains expenses. Memo Page 1 of 2

Qualifications: Education and Experience: Bachelors Degree in Marketing, Business or Commerce or equivalent from a recognized program plus Five (5) years recent, related, professional sales and marketing experience experience in the gas industry or an equivalent combination of education, training and experience. Valid BC Drivers License. Role Specific Knowledge, Skills and Abilities: Knowledge of energy market place natural gas vs. gasoline or diesel Knowledge of NGV equipment (vehicle and compression equipment) Demonstrated sales and customer account/relationship management skills Ability to communicate effectively both verbally and in writing. Ability to prepare and present information, motivate and influence others Ability to research and document relevant topics for potential customers Ability to establish strong working relationships with all levels of the organization. If you have what it takes to be successful in this role, please respond by submitting the On-line Employee Application (Internal Application) form # 1074. Click here for the link to the form. Include a covering letter and resume outlining how you meet the position requirements to Susan Chiu, Talent Sourcing, Surrey Ops 1 by November 7, 2012 4:30 PM. Memo Page 2 of 2

Title: Manager, Energy Products and Services Division: Gas Business Area: Energy Solutions and External Relations Department: Market and Business Development Management and Exempt Job Description Job Summary: Working in accordance with the organization s strategic vision, core values and leadership competencies, reporting to the Director, Resource Planning and Market Development this position is responsible to provide leadership in the effective management and execution of technical product support for traditional and non-traditional energy marketing programs. Key Accountabilities: Provide leadership in the effective management and execution of technical support for marketing program development including product and service lines such as NGV, Bio-gas, Solar Thermal, Combined Heat & Power, Pilot Studies, Codes Standards, Innovative Technologies and support services for Demand Side Management program development. Participate in the development and implementation of customer growth and retention strategies for residential, commercial and industrial market segments and provide technical support for traditional and non-traditional alternate energy applications and related products. Provide leadership to staff; effectively utilize team members and help execute career development plans. Coordinate internal and external resources required to deliver successful results; ensure key deliverables are defined and assign responsibilities with planned outcomes. Support other departments in the development of processes to enable proper program delivery; resolve and/or escalates issues. Provide high level project management of asset construction and ongoing operation and maintenance. Establish and maintain effective relationships with stakeholders; provide information, monitors systems integration activities, negotiates deviations in plans and coordinates resources. Liaise with customers, marketers and others; maintain awareness of activities impacting business development potential, customer relationships and energy technological advancements. Assess feedback from customers, municipalities, regulators and other stakeholders to ensure internal business processes are responsive to customer need. Leads energy feasibility proposal efforts, including project scoping; work with project partners throughout the program design, implementation, management and close-out process and interface with program funders and clients; ensure work complies with engineering standards, codes, specifications, and safety design instructions. Develop and maintain budgets; monitor expenses. Qualifications: Education and Experience: Bachelor s degree in a related discipline from a recognized program plus Eight (8) years of technical management experience in energy product market development within an Utility environment including project management, operations and maintenance experience or an equivalent combination of education, training and experience.

Title: Manager, Energy Products and Services Division: Gas Business Area: Energy Solutions and External Relations Department: Market and Business Development Management and Exempt Job Description Knowledge, Skills and Abilities: Knowledge of NGV commercial and industrial market segments in BC, LNG station design and operation Knowledge of Energy related Codes and Standards, single and three phase electrical systems, Building Science and EnerGuide rating systems, building energy performance monitoring and metering systems, Bio-gas systems, Solar Energy systems Business Development and Customer Relationship skills Demonstrated ability to facilitate team and client meetings effectively Demonstrated ability to work well independently and in a team setting Demonstrated ability to develop, document and implement strategies Demonstrated ability to seek out opportunities to increase customer satisfaction and deepen client relationships Demonstrated ability to communicate effectively with clients identifying needs and evaluating alternative energy solutions Demonstrated ability to educate other innovators and clients through both formal and informal training programs Demonstrated ability to independently leverage critical thinking skills to address real-world issues Demonstrated ability to prioritize and multitask on a wide range of competing demands with attention to detail Demonstrated ability to communicate effectively both verbally and in writing Demonstrated ability to adapt communication of complex technical processes to a verity of audiences Demonstrated ability to work across cultural and organizational boundaries, and operate successfully in an intense business environment maintaining effective working relationships Demonstrated ability to manage the process of innovative change effectively Additional Information (for Recruiting Purposes Only): Integrated Leadership Competencies: Drive for Results Lead High Performance Drive and Implement Prudent Change Make Optimal Decisions Build Working Relationships Core Values: Safety First Respect, Integrity, Open Communication Teamwork Action Oriented, Results Focused Continuous Learning & Innovation Reward Performance and Excellence Approval: David A. Bennett Dir, Resource Plan g & Mkt Dev November 3, 2011 Name Title Date

Appendix C ACTIVITY CATEGORIES

FORTISBC ENERGY INC. BFI CPCN ORDER G-150-12 COMPLIANCE FILING APPENDIX C Appendix C Activity Categories This Appendix describes the activities, tasks, and responsibilities undertaken by staff listed in Table 1 for 2012. Please refer to Appendix B for the related job descriptions. CNG/LNG Fueling stations Fueling station agreements o Presentation o Negotiation of terms and conditions o Execution Customer needs analysis Sales strategy Manage existing NGT customer accounts Customer site feasibility Fueling station cost quotations Project coordination with service providers Project scoping, design, implementation, support to Project Manager Develop and monitor project budgets, monitor expenses Cost of service modeling Regulatory proceedings related to fueling stations (BFI CPCN, Vedder CPCN) NGT Incentives Regulatory proceedings related to incentives (GGRR Rate Treatment Application, Prudency Review) Provide expertise to Energy Products and Services group for development of NGT Incentive Program Contribution Agreements o Presentation o Negotiation of terms and conditions o Execution Rate Schedule 6 (Light Duty Vehicles) Sales and administration of Rate Schedule 6 grants Respond to fleet customer inquiries for CNG conversions Page 1

FORTISBC ENERGY INC. BFI CPCN ORDER G-150-12 COMPLIANCE FILING APPENDIX C FEI Fleet Conversion Provide expertise on conversion of fleet vehicles Coordinate with conversion companies regarding tank/kit specifications NGT Advocacy Government policy advisory on transportation related issues Development and consultation on development of the Greenhouse Gas Reduction Regulation Stakeholder participation on Low Carbon Fuel Requirements Regulation Participation in and presentation at NGT workshops, conferences, events NGT Codes & Standards Participation in Canadian Natural Gas Vehicle Alliance working group Work with municipal, provincial and federal bodies to develop codes and standards related to CNG and LNG fueling infrastructure NGT Training Participation in Canadian Natural Gas Vehicle Alliance working group Examine best practices in other jurisdictions LNG Tankers Determine customer requirements Gather cost estimates from suppliers through Request for Quotations process Conduct feasibility and financial analysis Create business case based on operational requirements and financial results Rate Schedule 16 Application Completion of Application including: o Draft, review and filing of Application o Co-ordination and response to related IR s Regulatory proceedings related to Application including: o Procedural Conference o Written Process Page 2

Appendix D DELIVERY MARGIN BENEFITS (EXCERPTS FROM GGRR APPLICATION)

GGRR Application (Exhibit B-1) Appendices G and H Appendix G FINANCIAL SCHEDULES, SCENARIO 1 (EXPECTED CASE)

Appendix G Financial Schedules Scenario 1: Planned Growth List of Schedules GGRR Application (Exhibit B-1) Appendices G and H List of Schedules 1 Financial Assumptions 2 Scenario 1: Planned Growth Schedule 1: Summary of Costs and Benefits 6 Schedule 2: Benefits 8 Schedule 3: Cost of Service 12 Page 1

Appendix G Scenario 1: Planned Growth Financial Assumptions GGRR Application (Exhibit B-1) Appendices G and H 1) Scenario 1 Description Market continues to expand after the expiration of the prescribed undertaking, LNG capital (Liquefaction and Storage equipment: $66M in 2011$) added to meet LNG demand in 2018, 2023, 2025,2027,2029,2030. Total CNG/LNG volumes projected to reach 25.3PJ by 2030. Capital cost based on high level estimates, further detailed study required. Rate 16 increased by $1/GJ in 2018 to pay for additional LNG facilities. 2) Rates & Capital Structure FEI 2011 2012 1 2013 1 2014+ Rates ROE 9.50% 9.50% 9.50% 9.50% Short Term Debt Rate 4.50% 2.50% 3.50% 3.50% Long Term Debt Rate 6.95% 6.85% 6.87% 6.87% Capital Structure Equity Ratio 40.00% 40.00% 40.00% 40.00% STD Ratio 1.63% 1.93% 3.03% 3.03% Ltd Ratio 58.37% 58.07% 56.97% 56.97% Total 100.00% 100.00% 100.00% 100.00% Note 1: 2012-13, BCUC Order No.G-44-12 3) Income Tax Rate 2010 2011 2012+ 28.5% 26.5% 25.0% 4) Incentive Award & Payout Schedule Vehicle & Marine Incentives are assumed to be awarded once per year. 25% of the incentive award paid out when initial terms of the contract have been met, remaining 75% is paid when CNG/LNG vehicles enter service, ranging from 6 to 12 months later. Incentives recorded in deferral account based on cash payment of incentives. Maintenance Upgrades & Safety Incentives are assumed to be awarded once per year. 25% of the incentive award paid out upon incentive award, balance of incentive is paid when work is completed ranging from 2 to 6 months later. Incentives recorded in deferral account based on cash payment of incentives. 2

Appendix G Scenario 1: Planned Growth Financial Assumptions (continued) GGRR Application (Exhibit B-1) Appendices G and H Administration, Marketing, Training and Education Expenditures assumed to be evenly spread throughout the year. Total Incentive Award Schedule ('000$) 2010/11 2012 2013 2014 2015 2016 Total Vehicles 5,573 7,843 7,979 7,404 7,307 7,794 43,900 Marine Vessels 0 3,500 3,000 2,500 2,000 11,000 Admin, Marketing, Training & Education 300 1,000 900 600 300 3,100 Maintenance Upgrades & Safety 200 950 950 950 950 4,000 Total 5,573 8,343 13,429 12,254 11,357 11,044 62,000 Cumulative Incentives 5,573 13,916 27,345 39,599 50,956 62,000 Total Incentive Payout (Cash Basis) ('000$) 2010/11 2012 2013 2014 2015 2016 2017 Total Vehicles & Marine 5,573 1,961 8,752 11,210 10,255 9,804 7,345 43,900 Admin, Marketing, Training & Education 300 1,000 900 600 300 0 11,000 Maintenance Upgrades & Safety 50 922 950 950 1,128 0 4,000 Total 5,573 2,311 10,674 13,060 11,805 11,232 7,345 62,000 Cumulative Incentives 5,573 7,884 18,558 31,618 43,423 54,655 62,000 5) Deferral Account & Amortization Period Non Rate Base Deferral Account The non rate base deferral account contains the following: 1) Incentive payouts (cash basis) prior to 2014. 2) Incremental margins (exclude margins already included in RRA 2012/13) prior to 2014. 3) Prior incentives ($5.573 million). AFUDC is calculated on incentive payouts from August 2012 to the end of 2013. AFUDC is calculated on prior incentives from the date of the first vehicle and marine incentive payment, forecasted to be Oct 1, 2012 to the end of 2013. The non rate base deferral account is transferred to a rate base deferral account beginning January 1, 2014 and amortized over 10 years. Rate Base Deferral Account Incentive payouts (cash basis) are added to a rate base deferral account for incentive payouts starting in 2014. Each annual addition to the rate base deferral account is amortized over 10 years in the following year. The non rate base deferral account is transferred to the rate base deferral account at the start of 2014 and amortized over 10 years. 3

GGRR Application (Exhibit B-1) Appendices G and H Appendix G Scenario 1: Planned Growth Financial Assumptions (continued) 6) FEI Total Delivery Margin 2012 1,3 2013 1,3 2014 2,3 + FEI Total Delivery Margin $575M $577M Increase at 2% per year Note 1: 2012 & 2013 based on 2012-13 RRA G-44-12 Compliance Filing May 1, 2012 Note 2: Inflation based on high level long range planning assumptions Note 3: FEI Delivery Margins do not include any impact of the prescribed undertaking expenditures 7) FEI Delivery Rates FEI 2012 1 2013 1 2014 2 + Rate 16 3 $/GJ 4.05 4.11 Increase at 2%/year Rate 23 $/GJ 2.44 2.62 Increase at 2%/year Rate 25 Delivery $/GJ 0.68 0.73 Increase at 2%/year Rate 25 Demand Demand $/Month /GJ of Daily Demand 16.82 18.06 Increase at 2%/year Note 1: 2012 & 2013 approved Note 2: Inflation based on high level long range planning assumptions Note 3: $1/GJ added in 2018 to fund incremental LNG liquefaction and storage facilities for Scenario 1 8) Rate 16 Delivery Rate less Incremental Cost of LNG 2012 2013 2014 2015 2016 2017 2018 2 + Rate 16 $/GJ 4.05 1 4.11 1 4.19 4.28 4.36 4.45 2014+ Increase at BC CPI All Items, assumed to be 2% / year & Note 5 Incremental Cost of LNG 4 $/GJ 0.80 0.82 0.92 1.01 1.00 0.98 Note 3: Rate 16 Incremental Cost of $/GJ 3.25 3.29 3.28 3.27 3.36 3.47 LNG Note 1: 2012 & 2013 approved Note 2: BC CPI All Items based on high level long range planning assumptions Note 3: Vary from $0.80 to $1.01 / GJ depending on LNG volumes and sources, increase at BC CPI All Items projected to be 2% / year Note 4: Incremental Cost of LNG = Incremental O&M / Incremental volumes sold into the LNG market Note 5: $1/GJ added in 2018 to fund incremental LNG liquefaction and storage facilities for Scenario 1 4

Appendix G Scenario 1: Planned Growth Financial Assumptions (continued) GGRR Application (Exhibit B-1) Appendices G and H 9) Incremental LNG Capital 1,5 2011$M 3 As Spent $M 4 2018 2 66 74 2023 66 84 2025 66 87 2027 66 91 2029 66 94 2030 66 96 Note 1: Scenario 1 only, incremental LNG capital added to meet increasing LNG demand Note 2: In Service Nov 2017 Note 3: Capital costs are high level estimates, further detailed study required Note 4: 2011$ estimates converted to As Spent $ at 2% per year Note 5: Incremental LNG capital includes liquefaction and storage facilities 5

GGRR Application (Exhibit B-1) Appendices G and H Appendix G - Scenario 1: Planned Growth Appendix G - Scenario 1: Planned Growth Potential Rate Impact to Existing FEI Natural Gas Customers Potential Rate Impact to Existing FEI Natural Gas Customers Schedule 1: Summary of Costs and Benefits (2012-2021) Schedule 1: Summary of Costs and Benefits (2012-2021) Market expands, additional LNG equipment (liquefaction and storage) added to meet demand $000's, unless otherwise stated Reference 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 1 Annual NG Volume (TJ) Sch 2, Line 8 178 458 917 1,416 2,032 2,882 3,407 4,027 4,760 5,626 2 3 Discount Rate 2014 FEI After-Tax WACC 6.81% 4 Discount Period (years) 1 2 3 4 5 6 7 8 9 10 5 6 FEI Total Delivery Margin Projections $Millions Note 1 575 577 588 600 612 624 637 649 662 676 7 8 Net COS Benefit (Cost) to Existing Natural Gas Customers 9 Annual Incremental Margin from additional NGT volume Sch 2, Line 40, Note 2,4 538 1,284 2,662 4,044 5,958 8,690 12,964 15,628 18,842 22,719 10 Annual Incentive Funding COS Sch 3, -Line 76 (3,488) (5,471) (7,181) (9,175) (17,316) (17,640) (18,117) (18,783) 11 Net Annual COS Benefit (Cost) '000$ Line 9 + Line 10 538 1,284 (826) (1,427) (1,223) (485) (4,352) (2,012) 725 3,937 12 13 Approximate Annual FEI Delivery (Reduction) Increase, % -Line 11 / (Line 6 x 1000), Note 3 0.14% 0.24% 0.20% 0.08% 0.68% 0.31% (0.11)% (0.58)% 14 15 Present Value of Annual Net COS Benefit (Cost) Line 11/(1+Line 3)^(Line 4) 504 1,126 (678) (1,096) (879) (327) (2,743) (1,187) 401 2,036 16 17 NPV of Net COS Benefit (Cost) '000$ Sum Line 15 2012 to year 504 1,629 952 (144) (1,024) (1,351) (4,094) (5,282) (4,881) (2,845) 18 19 NPV of Net COS Benefit (Cost) 2012 to 2030 (19 Years) 66,147 20 Note: 21 1: 2012, 2013 based on 2012-2013 RRA G-44-12 Compliance Filing May 1, 2012; 2014+ increase at 2%/year reflecting high level long range planning assumptions, 22 does not include any impact of the prescribed undertaking expenditures or prior incentives 23 2: 2012 & 2013 incremental margin added to non rate base deferral account in Schedule 3: Cost of Service Line 32 24 3: Cumulative FEI Delivery (Reduction) increase, FEI delivery margin does not include any impact of the prescribed undertaking expenditures or prior incentives 25 4: 2012 & 2013 includes some margin already included in the 2012/13 RRA 6

GGRR Application (Exhibit B-1) Appendices G and H Appendix G - Scenario 1: Planned Growth Appendix G - Scenario 1: Planned Growth Potential Rate Impact to Existing FEI Natural Gas Customers Potential Rate Impact to Existing FEI Natural Gas Customers Schedule 1: Summary of Costs and Benefits (continued 2022-2030) Schedule 1: Summary of Costs and Benefits (continued 2022-2030) Market expands, additional LNG equipment (liquefaction and storage) added to meet demand $000's, unless otherwise stated Reference 2022 2023 2024 2025 2026 2027 2028 2029 2030 1 Annual NG Volume (TJ) Sch 2, Line 8 6,650 7,861 9,291 10,982 12,981 15,344 18,136 21,437 25,338 2 3 Discount Rate 2014 FEI After-Tax WACC 4 Discount Period (years) 11 12 13 14 15 16 17 18 19 5 6 FEI Total Delivery Margin Projections $Millions Note 1 689 703 717 731 746 761 776 792 808 7 8 Net COS Benefit (Cost) to Existing Natural Gas Customers 9 Annual Incremental Margin from additional NGT volume Sch 2, Line 40, Note 2,4 27,388 33,024 39,812 47,999 57,872 69,768 84,123 101,417 122,281 10 Annual Incentive Funding COS Sch 3, -Line 76 (19,679) (24,758) (28,336) (33,207) (38,716) (45,196) (52,776) (62,230) (77,137) 11 Net Annual COS Benefit (Cost) '000$ Line 9 + Line 10 7,709 8,266 11,476 14,793 19,156 24,572 31,347 39,187 45,144 12 13 Approximate Annual FEI Delivery (Reduction) Increase, % -Line 11 / (Line 6 x 1000), Note 3 (1.12)% (1.18)% (1.60)% (2.02)% (2.57)% (3.23)% (4.04)% (4.95)% (5.59)% 14 15 Present Value of Annual Net COS Benefit (Cost) Line 11/(1+Line 3)^(Line 4) 3,733 3,747 4,871 5,878 7,126 8,557 10,220 11,961 12,900 16 17 NPV of Net COS Benefit (Cost) '000$ Sum Line 15 2012 to year 888 4,635 9,506 15,384 22,509 31,066 41,286 53,247 66,147 18 19 20 Note: 21 1: 2012, 2013 based on 2012-2013 RRA G-44-12 Compliance Filing May 1, 2012; 2014+ increase at 2%/year reflecting high level long range planning assumptions, 22 does not include any impact of the prescribed undertaking expenditures or prior incentives 23 2: 2012 & 2013 incremental margin added to non rate base deferral account in Schedule 3: Cost of Service Line 32 24 3: Cumulative FEI Delivery (Reduction) increase, FEI delivery margin does not include any impact of the prescribed undertaking expenditures or prior incentives 25 4: 2012 & 2013 includes some margin already included in the 2012/13 RRA 7

GGRR Application (Exhibit B-1) Appendices G and H Appendix G - Scenario 1: Planned Growth Appendix G - Scenario 1: Planned Growth Schedule 2, Part A: Benefits (2012-2021) Schedule 2, Part A: Benefits (2012-2021) Market expands, additional LNG equipment (liquefaction and storage) added to meet demand $000's, Unless Otherwise Stated Reference 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 1 Annual NG Volume (TJ) 2 Rate 16 not included in RRA 2012/13 12 183 698 1,036 1,482 2,103 2,486 2,938 3,473 4,105 3 Rate 16 included in RRA 2012/13 Note 8 139 139 4 Rate 23 not included in RRA 2012/13 1 1 15 27 39 55 64 76 90 106 5 Rate 23 included in RRA 2012/13 Note 8 6 6 6 Rate 25 not included in RRA 2012/13 2 110 204 353 512 725 857 1,012 1,197 1,415 7 Rate 25 included in RRA 2012/13 Note 8 19 19 8 Total NG Volume (TJ) Sum of Lines 2 to 7 178 458 917 1,416 2,032 2,882 3,407 4,027 4,760 5,626 9 Number of CNG Stations 10 Rate 23 - - - - 1 1 1 1 1 1 11 Rate 25 1 3 5 8 11 15 18 21 25 30 12 Number of LNG Stations 2 3 5 8 11 16 18 21 25 30 13 Estimated Impact to Rate 25 Demand Volume Note 1, 4, 10 8 378 698 1,210 1,752 2,482 2,934 3,467 4,098 4,844 14 Estimated Impact to Rate 25 Demand Volume Note 1, 5, 11 65 65 15 Volumetric Delivery Rates ($/GJ) Note 2 16 Rate 16 (Net of incremental costs) Note 3 & 12 2012 & 2013 approved 3.25 3.29 3.28 3.27 3.36 3.47 4.54 4.63 4.72 4.81 17 Rate 23 2012 & 2013 approved 2.44 2.62 2.67 2.72 2.78 2.83 2.89 2.95 3.01 3.07 18 Rate 25 2012 & 2013 approved 0.68 0.73 0.75 0.76 0.78 0.79 0.81 0.82 0.84 0.86 19 Demand Rates Note 2 20 Rate 25 $/ Month / GJ of Daily Demand 2012 & 2013 approved 16.82 18.06 18.42 18.79 19.17 19.55 19.94 20.34 20.75 21.16 21 Basic & Admin Charge Note 2, 7 22 Rate 23 $/Month 2012 & 2013 approved 210.52 210.52 214.73 219.03 223.41 227.87 232.43 237.08 241.82 246.66 23 Rate 25 $/Month 2012 & 2013 approved 665.00 665.00 678.30 691.87 705.70 719.82 734.21 748.90 763.88 779.15 24 Rate 16 $/Month Note 9 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 25 Inflation Annual: Delivery/Demand/Basic Long term planning assumptions 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 8

GGRR Application (Exhibit B-1) Appendices G and H Appendix G - Scenario 1: Planned Growth Appendix G - Scenario 1: Planned Growth Schedule 1, Part B: Benefits (2012-2021) Schedule 1, Part B: Benefits (2012-2021) Market expands, additional LNG equipment (liquefaction and storage) added to meet demand $000's, Unless Otherwise Stated Reference 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 26 Incremental Margin '000$ 27 Delivery 28 Rate 16 not included in RRA 2012/13 (Line 2 x Line 16) 37 604 2,288 3,386 4,988 7,291 11,277 13,596 16,391 19,762 29 Rate 16 included in RRA 2012/13 (Line 3 x Line 16) 450 456 30 Rate 23 not included in RRA 2012/13 (Line 4 x Line 17) 2 2 41 72 107 155 186 225 271 326 31 Rate 23 included in RRA 2012/13 (Line 5 x Line 17) 15 16 32 Rate 25 not included in RRA 2012/13 (Line 6 x Line 18) 2 81 152 269 397 573 691 834 1,005 1,212 33 Rate 25 included in RRA 2012/13 (Line 7 x Line 18) 13 14 34 Demand 35 Rate 25 not included in RRA 2012/13 (Line 13 x Line 20x12/1000) 2 82 154 273 403 582 702 846 1,020 1,230 36 Rate 25 included in RRA 2012/13 (Line 14 x Line 20x12/1000) 13 14 37 Basic Charges 38 Rate 23 + 25 Note 6 5 16 27 44 64 88 108 128 155 189 39 Rate 16 - - - - - - - - - - 40 Total Incremental Margin Sum of Lines 28 to 39 538 1,284 2,662 4,044 5,958 8,690 12,964 15,628 18,842 22,719 41 Cumulative Incremental Margin 538 1,822 4,484 8,528 14,487 23,177 36,140 51,768 70,610 93,330 42 Note: 43 1 Compression load is assumed to be consistent; therefore, the peak will not change in a winter month 44 2 Existing delivery / demand / basic & admin charges are approved 2012 and 2013 charges, 2014+ increase at 2% per year reflecting high level long range planning assumptions 45 3 Rate 16 reflects delivery rate minus incremental cost of LNG (incremental O&M / incremental volume sold into the LNG market), further detail included in this appendix, 46 Financial Assumptions, section 8 47 4 Rate 25 demand volumes not included in RRA 2012/13 filing 48 5 Rate 25 demand volumes included in RRA 2012/13 filing 49 6 (Line 10 x Line 22 x 12) /1000 x (2/3) + Line 11 x (Line 23 x 12) /1000x(2/3); Basic charges reduce by 1/3 to reflect that some existing accounts are already on R23/25 50 7 New CNG/LNG stations results in new Rate 23/25/16 accounts 51 8 Volumes related to prior incentives, included in 2012/13 RRA 52 9 There are no basic or admin charges for LNG Rate 16 accounts 53 10 Line 6 / 365 x 1.25 x 1000 54 11 Line 7 / 365 x 1.25 x 1000 55 12 Add $1/GJ in 2018 to fund incremental LNG liquefaction and storage 9

GGRR Application (Exhibit B-1) Appendices G and H Appendix G - Scenario 1: Planned Growth Appendix G - Scenario 1: Planned Growth Schedule 2, Part A: Benefits (continued 2022-2030) Schedule 2, Part A: Benefits (continued 2022-2030) Market expands, additional LNG equipment (liquefaction and storage) added to meet demand $000's, Unless Otherwise Stated Reference 2022 2023 2024 2025 2026 2027 2028 2029 2030 1 Annual NG Volume (TJ) 2 Rate 16 not included in RRA 2012/13 4,852 5,736 6,779 8,013 9,472 11,196 13,233 15,642 18,488 3 Rate 16 included in RRA 2012/13 Note 8 - - - - - - - - - 4 Rate 23 not included in RRA 2012/13 126 149 176 208 246 290 343 406 480 5 Rate 23 included in RRA 2012/13 Note 8 - - - - - - - - - 6 Rate 25 not included in RRA 2012/13 1,672 1,976 2,336 2,761 3,264 3,858 4,560 5,390 6,371 7 Rate 25 included in RRA 2012/13 Note 8 - - - - - - - - - 8 Total NG Volume (TJ) Sum of Lines 2 to 7 6,650 7,861 9,291 10,982 12,981 15,344 18,136 21,437 25,338 9 Number of CNG Stations 10 Rate 23 1 1 2 2 2 2 2 2 2 11 Rate 25 35 42 49 58 69 81 97 114 136 12 Number of LNG Stations 35 41 49 58 68 80 95 112 133 13 Estimated Impact to Rate 25 Demand Volume Note 1, 4, 10 5,726 6,768 8,000 9,456 11,177 13,211 15,616 18,458 21,817 14 Estimated Impact to Rate 25 Demand Volume Note 1, 5, 11 - - - - - - - - - 15 Volumetric Delivery Rates ($/GJ) Note 2 16 Rate 16 (Net of incremental costs) Note 3 & 122012 & 2013 approved 4.91 5.01 5.11 5.21 5.31 5.42 5.53 5.64 5.75 17 Rate 23 2012 & 2013 approved 3.13 3.19 3.25 3.32 3.39 3.45 3.52 3.59 3.66 18 Rate 25 2012 & 2013 approved 0.87 0.89 0.91 0.93 0.95 0.96 0.98 1.00 1.02 19 Demand Rates 20 Rate 25 $/ Month / GJ of Daily Demand 2012 & 2013 approved 21.59 22.02 22.46 22.91 23.37 23.83 24.31 24.80 25.29 21 Basic & Admin Charge Note 2, 7 22 Rate 23 $/Month 2012 & 2013 approved 251.59 256.62 261.76 266.99 272.33 277.78 283.33 289.00 294.78 23 Rate 25 $/Month 2012 & 2013 approved 794.74 810.63 826.84 843.38 860.25 877.45 895.00 912.90 931.16 24 Rate 16 $/Month Note 9 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 25 Inflation Annual: Delivery/Demand/Basic Long term planning assumptions 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 10

GGRR Application (Exhibit B-1) Appendices G and H Appendix G - Scenario 1: Planned Growth Appendix G - Scenario 1: Planned Growth Schedule 2, Part B: Benefits (continued 2022-2030) Schedule 2, Part B: Benefits (continued 2022-2030) Market expands, additional LNG equipment (liquefaction and storage) added to meet demand $000's, Unless Otherwise Stated Reference 2022 2023 2024 2025 2026 2027 2028 2029 2030 26 Incremental Margin '000$ 27 Delivery 28 Rate 16 not included in RRA 2012/13 (Line 2 x Line 16) 23,826 28,726 34,633 41,755 50,341 60,693 73,174 88,221 106,363 29 Rate 16 included in RRA 2012/13 (Line 3 x Line 16) - - - - - - - - - 30 Rate 23 not included in RRA 2012/13 (Line 4 x Line 17) 394 475 572 690 832 1,003 1,209 1,457 1,757 31 Rate 23 included in RRA 2012/13 (Line 5 x Line 17) - - - - - - - - - 32 Rate 25 not included in RRA 2012/13 (Line 6 x Line 18) 1,461 1,761 2,123 2,560 3,086 3,721 4,486 5,409 6,521 33 Rate 25 included in RRA 2012/13 (Line 7 x Line 18) - - - - - - - - - 34 Demand 35 Rate 25 not included in RRA 2012/13 (Line 13 x Line 20x12/1000) 1,483 1,788 2,156 2,599 3,134 3,778 4,556 5,492 6,622 36 Rate 25 included in RRA 2012/13 (Line 14 x Line 20x12/1000) - - - - - - - - - 37 Basic Charges 38 Rate 23 + 25 Note 6 225 274 328 396 479 573 699 837 1,018 39 Rate 16 - - - - - - - - - 40 Total Incremental Margin Sum of Lines 28 to 39 27,388 33,024 39,812 47,999 57,872 69,768 84,123 101,417 122,281 41 Cumulative Incremental Margin 120,718 153,742 193,554 241,554 299,426 369,194 453,317 554,734 677,015 42 Note: 43 1 Compression load is assumed to be consistent; therefore, the peak will not change in a winter month 44 2 Existing delivery / demand / basic & admin charges are approved 2012 and 2013 charges, 2014+ increase at 2% per year reflecting high level long range planning assumptions 45 3 Rate 16 reflects delivery rate minus incremental cost of LNG (incremental O&M / incremental volume sold into the LNG market), further detail included in this appendix, 46 Financial Assumptions, section 8 47 4 Rate 25 demand volumes not included in RRA 2012/13 filing 48 5 Rate 25 demand volumes included in RRA 2012/13 filing 49 6 (Line 10 x Line 22 x 12) /1000 x (2/3) + Line 11 x (Line 23 x 12) /1000x(2/3); Basic charges reduce by 1/3 to reflect that some existing accounts are already on R23/25 50 7 New CNG/LNG stations results in new Rate 23/25/16 accounts 51 8 Volumes related to prior incentives, included in 2012/13 RRA 52 9 There are no basic or admin charges for LNG Rate 16 accounts 53 10 Line 6 / 365 x 1.25 x 1000 54 11 Line 7 / 365 x 1.25 x 1000 55 12 Add $1/GJ in 2018 to fund incremental LNG liquefaction and storage 11

GGRR Application (Exhibit B-1) Appendices G and H Appendix G - Scenario 1: Planned Growth Appendix G - Scenario 1: Planned Growth Schedule 3, Part A: Cost of Service (2011-2021) Schedule 3, Part A: Cost of Service (2011-2021) Market expands, additional LNG equipment (liquefaction and storage) added to meet demand $000's, Unless Otherwise Stated Reference 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 1 Key Assumptions 2 Rates 3 ROE % BCUC Order No. G-44-12 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 4 STD Rate % BCUC Order No. G-44-12 4.50% 2.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 5 LTD Rate % BCUC Order No. G-44-12 6.95% 6.85% 6.87% 6.87% 6.87% 6.87% 6.87% 6.87% 6.87% 6.87% 6.87% 6 Capital Structure 7 Equity % BCUC Order No. G-44-12 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 8 STD % BCUC Order No. G-44-12 1.63% 1.93% 3.03% 3.03% 3.03% 3.03% 3.03% 3.03% 3.03% 3.03% 3.03% 9 LTD % BCUC Order No. G-44-12 58.37% 58.07% 56.97% 56.97% 56.97% 56.97% 56.97% 56.97% 56.97% 56.97% 56.97% 10 Total % 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 11 Return on Rate Base % Note 5 7.93% 7.83% 7.82% 7.82% 7.82% 7.82% 7.82% 7.82% 7.82% 7.82% 7.82% 12 WACC % Note 6 6.84% 6.82% 6.81% 6.81% 6.81% 6.81% 6.81% 6.81% 6.81% 6.81% 6.81% 13 Tax Rate % 26.50% 25.00% 25.00% 25.00% 25.00% 25.00% 25.00% 25.00% 25.00% 25.00% 25.00% 14 Incentive Award Schedule Note 1 15 Prior Vehicle Incentives Note 10 5,573 16 Vehicle & Marine - 7,843 11,479 10,404 9,807 9,794-17 Maintenance Upgrades & Safety - 200 950 950 950 950-18 Admin, Marketing, Train, Education - 300 1,000 900 600 300-19 Total Incentive Awards ($62000) Sum of Lines 15 to 18 5,573 8,343 13,429 12,254 11,357 11,044-20 Incentive Payouts (Cash Basis) Note 1 21 Prior Vehicle Incentives 5,573 22 Vehicle & Marine Note 1-1,961 8,752 11,210 10,255 9,804 7,345 23 Maintenance Upgrades & Safety Note 1 50 922 950 950 1,128-24 Admin, Marketing, Train, Education Note 1 300 1,000 900 600 300-25 Total Incentive Payouts (Cash Basis) Sum of Lines 21 to 24 5,573 2,311 10,674 13,060 11,805 11,232 7,345 12

GGRR Application (Exhibit B-1) Appendices G and H Appendix G - Scenario 1: Planned Growth Appendix G - Scenario 1: Planned Growth Schedule 3, Part B: Cost of Service (2011-2021) Schedule 3, Part B: Cost of Service (2011-2021) Market expands, additional LNG equipment (liquefaction and storage) added to meet demand $000's, Unless Otherwise Stated Reference 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 26 Non Rate Base Deferral Account (NRBDA)Calculation 27 Gross Additions Line 25 (2011-2013) 5,573 2,311 10,674 28 Tax - Line 27 x Line 13 (1,477) (578) (2,668) - - - - - - - - 29 Net Additions Line 27 + Line 28 4,097 1,733 8,005 - - - - - - - - 30 Opening Deferral Account Balance Previous Year, Line 34-4,097 5,851 31 Net Additions Line 29 4,097 1,733 8,005 32 Incremental Margins pre 2014 Note 7 - (36) (588) 33 AFUDC on Deferral Account pre 2014 Note 4, 11-58 585 34 Closing Deferral Account Balance Sum of Lines 30 to 33 4,097 5,851 13,853 35 Rate Base Deferral Account Calculation 36 Amortization Period (Years) 10 37 Gross Additions Line 25 (2014+) 13,060 11,805 11,232 7,345 - - - - 38 Tax - Line 37 x Line 13 (3,265) (2,951) (2,808) (1,836) - - - - 39 Net Additions Line 37 + Line 38 9,795 8,854 8,424 5,509 - - - - 40 Annual Amortization of Net Addition Line 39/10 years 980 885 842 551 - - - - 41 Add NRBDA Line 34, 2013 Closing & Note 2 13,853 42 Annual Amortization of NRBDA Line 41/10 years 1,385 43 Opening Deferral Account Balance Note 8 13,853 22,263 28,752 33,925 35,342 30,698 26,055 21,411 44 Net Additions Line 39 9,795 8,854 8,424 5,509 - - - - 45 Amortization: Net Additions Sum of Line 40 & Note 9 (980) (1,865) (2,707) (3,258) (3,258) (3,258) (3,258) 46 Amortization: NRBDA Line 42 over 10 years & Note 3 (1,385) (1,385) (1,385) (1,385) (1,385) (1,385) (1,385) (1,385) 47 Closing Deferral Account Balance Sum of Lines 43 to 46 22,263 28,752 33,925 35,342 30,698 26,055 21,411 16,768 48 Total Amortization Line 45 + Line 46 (1,385) (2,365) (3,250) (4,093) (4,643) (4,643) (4,643) (4,643) 49 Mid Year Rate Base (Line 43 + Line 47)/2 18,058 25,508 31,339 34,634 33,020 28,377 23,733 19,090 50 Income Tax Expense 51 Equity Earned Return Line 60 - - - 686 969 1,191 1,316 1,255 1,078 902 725 52 Add: Amortization Expense - Line 48 - - - 1,385 2,365 3,250 4,093 4,643 4,643 4,643 4,643 53 Taxable Income After Tax Line 51 + Line 52 - - - 2,072 3,334 4,441 5,409 5,898 5,722 5,545 5,369 54 Taxable Income Line 53 / (1 - Line 13) - - - 2,762 4,446 5,921 7,212 7,864 7,629 7,394 7,159 55 Income Tax Expense Line 54 x Line 13 - - - 691 1,111 1,480 1,803 1,966 1,907 1,848 1,790 13

GGRR Application (Exhibit B-1) Appendices G and H Appendix G - Scenario 1: Planned Growth Appendix G - Scenario 1: Planned Growth Schedule 3, Part C: Cost of Service (2011-2021) Schedule 3, Part C: Cost of Service (2011-2021) Market expands, additional LNG equipment (liquefaction and storage) added to meet demand $000's, Unless Otherwise Stated Reference 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 56 Earned Return 57 Total Rate Base Line 49 18,058 25,508 31,339 34,634 33,020 28,377 23,733 19,090 58 ROE Rate % Line 3 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 59 Equity Ratio % Line 7 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 60 Equity Return Line 57 x Line 58 x Line 59 686 969 1,191 1,316 1,255 1,078 902 725 61 Total Rate Base Line 49 18,058 25,508 31,339 34,634 33,020 28,377 23,733 19,090 62 Short Term Debt Rate % Line 4 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 63 Short Term Debt Ratio % Line 8 3.03% 3.03% 3.03% 3.03% 3.03% 3.03% 3.03% 3.03% 64 Short Term Debt Component Line 61 x Line 62 x Line 63 19 27 33 37 35 30 25 20 65 Total Rate Base Line 49 18,058 25,508 31,339 34,634 33,020 28,377 23,733 19,090 66 Long Term Debt Rate % Line 5 6.87% 6.87% 6.87% 6.87% 6.87% 6.87% 6.87% 6.87% 67 Long Term Debt Ratio % Line 9 56.97% 56.97% 56.97% 56.97% 56.97% 56.97% 56.97% 56.97% 68 Long Term Debt Component Line 65 x Line 66 x Line 67 707 998 1,227 1,356 1,292 1,111 929 747 69 Total Debt Component Line 64 + Line 68 726 1,025 1,260 1,392 1,327 1,141 954 767 70 Total Earned Return Line 60 + Line 69 1,412 1,995 2,451 2,708 2,582 2,219 1,856 1,493 71 Annual Cost of Service Impact of NGT Incentive Program 72 Amortization Expense - Line 48 - - - 1,385 2,365 3,250 4,093 4,643 4,643 4,643 4,643 73 Income Tax Expense Line 55 - - - 691 1,111 1,480 1,803 1,966 1,907 1,848 1,790 74 Earned Return Line 70 - - - 1,412 1,995 2,451 2,708 2,582 2,219 1,856 1,493 75 Upgrade LNG Capital COS Note 12 - - - - - 571 8,125 8,870 9,769 10,857 76 Total Cost of Service Sum of Lines 72 to 75 - - - 3,488 5,471 7,181 9,175 17,316 17,640 18,117 18,783 77 Note: 78 1: This appendix, Financial Assumptions, Section 4 79 2: Non rate base deferral account is transferred to the rate base deferral account at the start of 2014 80 3: Non rate base deferral account transferred to rate base deferral account in 2014 and amortized over 10 years starting in 2014 81 4: AFUDC calculated on prior incentives added to non rate base deferral account from the date (forecasted Oct 2012) of the first vehicle and marine incentive payment to end of 2013 82 5: Line 3 x Line 7 + Line 4 x Line 8 + Line 5 x Line 9 83 6: Line 3 x Line 7 + (Line 4 x Line 8 + Line 5 x Line 9) x (1 - Line 13) 84 7: Exclude volumes / margin already included in RRA 2012/2013; Schedule 2 Benefits: Line 28+ Line 30 + Line 32 + Line 35 + Line 38 85 8: 2014 Opening rate base deferral account equals 2013 closing non rate base deferral account of $13.853 Million, 2015 onwards previous year Line 47 86 9: Amortization of new additions in following year over 10 years 87 10: Prior incentive spending in 2011 includes 2010 amounts, totals $5.573 million 88 11: AFUDC calculated on incentives added to the non rate base deferral account from Aug 2012 to the end of 2013 89 12: Liquefaction and Storage capital added to meet increasing LNG demand, please see financial assumption, section 9 of this appendix for further detail 14

GGRR Application (Exhibit B-1) Appendices G and H Appendix G - Scenario 1: Planned Growth Appendix G - Scenario 1: Planned Growth Schedule 3, Part A: Cost of Service (continued 2022-2030) Schedule 3, Part A: Cost of Service (continued 2022-2030) Market expands, additional LNG equipment (liquefaction and storage) added to meet demand $000's, Unless Otherwise Stated Reference 2022 2023 2024 2025 2026 2027 2028 2029 2030 1 Key Assumptions - 2 Rates 3 ROE % BCUC Order No. G-44-12 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 4 STD Rate % BCUC Order No. G-44-12 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 5 LTD Rate % BCUC Order No. G-44-12 6.87% 6.87% 6.87% 6.87% 6.87% 6.87% 6.87% 6.87% 6.87% 6 Capital Structure 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 7 Equity % BCUC Order No. G-44-12 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 8 STD % BCUC Order No. G-44-12 3.03% 3.03% 3.03% 3.03% 3.03% 3.03% 3.03% 3.03% 3.03% 9 LTD % BCUC Order No. G-44-12 56.97% 56.97% 56.97% 56.97% 56.97% 56.97% 56.97% 56.97% 56.97% 10 Total % 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 11 Return on Rate Base % Note 5 7.82% 7.82% 7.82% 7.82% 7.82% 7.82% 7.82% 7.82% 7.82% 12 WACC % Note 6 6.81% 6.81% 6.81% 6.81% 6.81% 6.81% 6.81% 6.81% 6.81% 13 Tax Rate % 25.00% 25.00% 25.00% 25.00% 25.00% 25.00% 25.00% 25.00% 25.00% 14 Incentive Award Schedule Note 1 - - - - - - - - - 15 Prior Vehicle Incentives Note 10 - - - - - - - - - 16 Vehicle & Marine - - - - - - - - - 17 Maintenance Upgrades & Safety - - - - - - - - - 18 Admin, Marketing, Train, Education - - - - - - - - - 19 Total Incentive Awards ($62000) Sum of Lines 15 to 18 - - - - - - - - - 20 Incentive Payouts (Cash Basis) Note 1 21 Prior Vehicle Incentives - - - - - - - - - 22 Vehicle & Marine Note 1 - - - - - - - - - 23 Maintenance Upgrades & Safety Note 1 - - - - - - - - - 24 Admin, Marketing, Train, Education Note 1 - - - - - - - - - 25 Total Incentive Payouts (Cash Basis) Sum of Lines 21 to 24 - - - - - - - - - 15

GGRR Application (Exhibit B-1) Appendices G and H Appendix G - Scenario 1: Planned Growth Appendix G - Scenario 1: Planned Growth Schedule 3, Part B: Cost of Service (continued 2022-2030) Schedule 3, Part B: Cost of Service (continued 2022-2030) Market expands, additional LNG equipment (liquefaction and storage) added to meet demand $000's, Unless Otherwise Stated Reference 2022 2023 2024 2025 2026 2027 2028 2029 2030 26 Non Rate Base Deferral Account (NRBDA)Calculation 27 Gross Additions Line 25 (2011-2013) - - - - - - - - - 28 Tax - Line 27 x Line 13 - - - - - - - - - 29 Net Additions Line 27 + Line 28 - - - - - - - - - 30 Opening Deferral Account Balance Previous Year, Line 34 - - - - - - - - - 31 Net Additions Line 29 - - - - - - - - - 32 Incremental Margins pre 2014 Note 7 - - - - - - - - - 33 AFUDC on Deferral Account pre 2014 Note 4, 11 - - - - - - - - - 34 Closing Deferral Account Balance Sum of Lines 30 to 33 - - - - - - - - - 35 Rate Base Deferral Account Calculation 36 Amortization Period (Years) 37 Gross Additions Line 25 (2014+) - - - - - - - - - 38 Tax - Line 37 x Line 13 - - - - - - - - - 39 Net Additions Line 37 + Line 38 - - - - - - - - - 40 Annual Amortization of Net Addition Line 39/10 years - - - - - - - - - 41 Add NRBDA Line 34, 2013 Closing & Note 2 - - - - - - - - - 42 Annual Amortization of NRBDA Line 41/10 years - - - - - - - - - 43 Opening Deferral Account Balance Note 8 16,768 12,125 7,481 4,223 1,944 551 0 0 0 44 Net Additions Line 39 - - - - - - - - - 45 Amortization: Net Additions Sum of Line 40 & Note 9 (3,258) (3,258) (3,258) (2,279) (1,393) (551) - - - 46 Amortization: NRBDA Line 42 over 10 years & Note 3 (1,385) (1,385) - - - - - - - 47 Closing Deferral Account Balance Sum of Lines 43 to 46 12,125 7,481 4,223 1,944 551 0 0 0 0 48 Total Amortization Line 45 + Line 46 (4,643) (4,643) (3,258) (2,279) (1,393) (551) - - - 49 Mid Year Rate Base (Line 43 + Line 47)/2 14,446 9,803 5,852 3,084 1,248 275 0 0 0 50 Income Tax Expense 51 Equity Earned Return Line 60 549 373 222 117 47 10 0 0 0 52 Add: Amortization Expense - Line 48 4,643 4,643 3,258 2,279 1,393 551 - - - 53 Taxable Income After Tax Line 51 + Line 52 5,192 5,016 3,481 2,396 1,441 561 0 0 0 54 Taxable Income Line 53 / (1 - Line 13) 6,923 6,688 4,641 3,194 1,921 748 0 0 0 55 Income Tax Expense Line 54 x Line 13 1,731 1,672 1,160 799 480 187 0 0 0 16

GGRR Application (Exhibit B-1) Appendices G and H Appendix G - Scenario 1: Planned Growth Appendix G - Scenario 1: Planned Growth Schedule 3, Part C: Cost of Service (continued 2022-2030) Schedule 3, Part C: Cost of Service (continued 2022-2030) Market expands, additional LNG equipment (liquefaction and storage) added to meet demand $000's, Unless Otherwise Stated Reference 2022 2023 2024 2025 2026 2027 2028 2029 2030 56 Earned Return 57 Total Rate Base Line 49 14,446 9,803 5,852 3,084 1,248 275 0 0 0 58 ROE Rate % Line 3 0 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 59 Equity Ratio % Line 7 0 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 60 Equity Return Line 57 x Line 58 x Line 59 549 373 222 117 47 10 0 0 0 61 Total Rate Base Line 49 14,446 9,803 5,852 3,084 1,248 275 0 0 0 62 Short Term Debt Rate % Line 4 0 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 63 Short Term Debt Ratio % Line 8 0 3.03% 3.03% 3.03% 3.03% 3.03% 3.03% 3.03% 3.03% 64 Short Term Debt Component Line 61 x Line 62 x Line 63 15 10 6 3 1 0 0 0 0 65 Total Rate Base Line 49 14,446 9,803 5,852 3,084 1,248 275 0 0 0 66 Long Term Debt Rate % Line 5 0 6.87% 6.87% 6.87% 6.87% 6.87% 6.87% 6.87% 6.87% 67 Long Term Debt Ratio % Line 9 1 56.97% 56.97% 56.97% 56.97% 56.97% 56.97% 56.97% 56.97% 68 Long Term Debt Component Line 65 x Line 66 x Line 67 565 384 229 121 49 11 0 0 0 69 Total Debt Component Line 64 + Line 68 581 394 235 124 50 11 0 0 0 70 Total Earned Return Line 60 + Line 69 1,130 767 458 241 98 22 0 0 0 71 Annual Cost of Service Impact of NGT Incentive Program 72 Amortization Expense - Line 48 4,643 4,643 3,258 2,279 1,393 551 - - - 73 Income Tax Expense Line 55 1,731 1,672 1,160 799 480 187 0 0 0 74 Earned Return Line 70 1,130 767 458 241 98 22 0 0 0 75 Upgrade LNG Capital COS Note 12 12,175 17,676 23,460 29,888 36,745 44,437 52,776 62,230 77,137 76 Total Cost of Service Sum of Lines 72 to 75 19,679 24,758 28,336 33,207 38,716 45,196 52,776 62,230 77,137 77 Note: 78 1: This appendix, Financial Assumptions, Section 4 79 2: Non rate base deferral account is transferred to the rate base deferral account at the start of 2014 80 3: Non rate base deferral account transferred to rate base deferral account in 2014 and amortized over 10 years starting in 2014 81 4: AFUDC calculated on prior incentives added to non rate base deferral account from the date (forecasted Oct 2012) of the first vehicle and marine incentive payment to end of 2013 82 5: Line 3 x Line 7 + Line 4 x Line 8 + Line 5 x Line 9 83 6: Line 3 x Line 7 + (Line 4 x Line 8 + Line 5 x Line 9) x (1 - Line 13) 84 7: Exclude volumes / margin already included in RRA 2012/2013; Schedule 2 Benefits: Line 28+ Line 30 + Line 32 + Line 35 + Line 38 85 8: 2014 Opening rate base deferral account equals 2013 closing non rate base deferral account of $13.853 Million, 2015 onwards previous year Line 47 86 9: Amortization of new additions in following year over 10 years 87 10: Prior incentive spending in 2011 includes 2010 amounts, totals $5.573 million 88 11: AFUDC calculated on incentives added to the non rate base deferral account from Aug 2012 to the end of 2013 89 12: Liquefaction and Storage capital added to meet increasing LNG demand, please see financial assumption, section 9 of this appendix for further detail 17

GGRR Application (Exhibit B-1) Appendices G and H Appendix H FINANCIAL SCHEDULES, SCENARIO 2 (LOW GROWTH CASE)

Appendix H Financial Schedules - Scenario 2: GGRR Load Growth Only List of Schedules GGRR Application (Exhibit B-1) Appendices G and H List of Schedules 1 Financial Assumptions 2 Scenario 2: GGRR Load Growth Only Schedule 1: Summary of Costs and Benefits 5 Schedule 2: Benefits 7 Schedule 3: Cost of Service 11 Page 1

Appendix H Scenario 2: GGRR Load Growth Only Financial Assumptions GGRR Application (Exhibit B-1) Appendices G and H 1) Scenario 2 Description Market does not expand further after incentives discontinued, CNG / LNG vehicles replaced at end of vehicle life and volumes maintained at 2.9PJ per year. No additional LNG capital required. 2) Rates & Capital Structure FEI 2011 2012 1 2013 1 2014+ Rates ROE 9.50% 9.50% 9.50% 9.50% Short Term Debt Rate 4.50% 2.50% 3.50% 3.50% Long Term Debt Rate 6.95% 6.85% 6.87% 6.87% Capital Structure Equity Ratio 40.00% 40.00% 40.00% 40.00% Short Term Debt Ratio 1.63% 1.93% 3.03% 3.03% Long Term Debt Ratio 58.37% 58.07% 56.97% 56.97% Total 100.00% 100.00% 100.00% 100.00% Note 1: 2012-13, BCUC Order No.G-44-12 3) Income Tax Rate 2010 2011 2012+ 28.5% 26.5% 25.0% 4) Incentive Award & Payout Schedule Vehicle & Marine Incentives are assumed to be awarded once per year. 25% of the incentive award paid out when initial terms of the contract have been met, remaining 75% is paid when CNG/LNG vehicles enter service, ranging from 6 to 12 months later. Incentives recorded in deferral account based on cash payment of incentives. Maintenance Upgrades & Safety Incentives are assumed to be awarded once per year. 25% of the incentive award paid out upon incentive award, balance of incentive is paid when work is completed ranging from 2 to 6 months later. Incentives recorded in deferral account based on cash payment of incentives. 2

GGRR Application (Exhibit B-1) Appendices G and H Appendix H Scenario 2: GGRR Load Growth Only Financial Assumptions (continued) Administration, Marketing, Training and Education Expenditures assumed to be evenly spread throughout the year. Total Incentive Award Schedule ('000$) 2010/11 2012 2013 2014 2015 2016 Total Vehicles 5,573 7,843 7,979 7,404 7,307 7,794 43,900 Marine Vessels 0 3,500 3,000 2,500 2,000 11,000 Admin, Marketing, Training & Education 300 1,000 900 600 300 3,100 Maintenance Upgrades & Safety 200 950 950 950 950 4,000 Total 5,573 8,343 13,429 12,254 11,357 11,044 62,000 Cumulative Incentives 5,573 13,916 27,345 39,599 50,956 62,000 Total Incentive Payout (Cash Basis) ('000$) 2010/11 2012 2013 2014 2015 2016 2017 Total Vehicles & Marine 5,573 1,961 8,752 11,210 10,255 9,804 7,345 43,900 Admin, Marketing, Training & Education 300 1,000 900 600 300 0 11,000 Maintenance Upgrades & Safety 50 922 950 950 1,128 0 4,000 Total 5,573 2,311 10,674 13,060 11,805 11,232 7,345 62,000 Cumulative Incentives 5,573 7,884 18,558 31,618 43,423 54,655 62,000 5) Deferral Account & Amortization Period Non Rate Base Deferral Account The non rate base deferral account contains the following: 1) Incentive payouts (cash basis) prior to 2014. 2) Incremental margins (exclude margins already included in RRA 2012/13) prior to 2014. 3) Prior incentives ($5.573 million). AFUDC is calculated on incentive payouts from August 2012 to the end of 2013. AFUDC is calculated on prior incentives from the date of the first vehicle and marine incentive payment, forecasted to be Oct 1, 2012 to the end of 2013. The non rate base deferral account is transferred to a rate base deferral account beginning January 1, 2014 and amortized over 10 years. Rate Base Deferral Account Incentive payouts (cash basis) are added to a rate base deferral account for incentive payouts starting in 2014. Each annual addition to the rate base deferral account is amortized over 10 years in the following year. The non rate base deferral account is transferred to the rate base deferral account at the start of 2014 and amortized over 10 years. 3

GGRR Application (Exhibit B-1) Appendices G and H Appendix H Scenario 2: GGRR Load Growth Only Financial Assumptions (continued) 6) FEI Total Delivery Margin 2012 1,3 2013 1,3 2014 2,3 + FEI Total Delivery Margin $575M $577M Increase at 2% per year Note 1: 2012 & 2013 based on 2012-13 RRA G-44-12 Compliance Filing May 1, 2012 Note 2: Based on high level long range planning assumptions Note 3: FEI Delivery Margins do not include any impact of the prescribed undertaking expenditures 7) FEI Delivery Rates FEI 2012 1 2013 1 2014 2 + Rate 16 $/GJ 4.05 4.11 Increase at 2%/year Rate 23 $/GJ 2.44 2.62 Increase at 2%/year Rate 25 Delivery $/GJ 0.68 0.73 Increase at 2%/year Rate 25 Demand Demand $/Month /GJ of Daily Demand 16.82 18.06 Increase at 2%/year Note 1: 2012 & 2013 approved Note 2: Based on high level long range planning assumptions 8) Rate 16 Delivery Rate less Incremental Cost of LNG 2012 2013 2014 2015 2016 2017 2018 2 + Rate 16 $/GJ 4.05 1 4.11 1 4.19 4.28 4.36 4.45 2014+ Increase at BC CPI All Items, assumed to be 2% / year Incremental Cost of LNG 4 $/GJ 0.80 0.82 0.92 1.01 1.00 0.98 Note 3 Rate 16 Incremental Cost of $/GJ 3.25 3.29 3.28 3.27 3.36 3.47 LNG Note 1: 2012 & 2013 approved Note 2: BC CPI All Items based on high level long range planning assumptions Note 3: Vary from $0.80 to $1.01 / GJ depending on LNG volumes and sources, increase at BC CPI All Items projected to be 2% / year Note 4: Incremental Cost of LNG = Incremental O&M / Incremental volumes sold into the LNG market 4

Appendix H - Scenario 2: GGRR Load Growth Only Appendix H - Scenario 2: GGRR Load Growth Only Potential Rate Impact to Existing FEI Natural Gas Customers Potential Rate Impact to Existing FEI Natural Gas Customers Schedule 1: Summary of Costs and Benefits (2012-2021) Schedule 1: Summary of Costs and Benefits (2012-2021) Market does not expand after incentives, NGV vehicles replaced at end of product cycle and volumes maintained $000's, unless otherwise stated Reference 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 1 Annual NG Volume (TJ) Sch 2, Line 8 178 458 917 1,416 2,032 2,882 2,882 2,882 2,882 2,882 2 3 Discount Rate 2014 FEI After-Tax WACC 6.81% 4 Discount Period (years) 1 2 3 4 5 6 7 8 9 10 5 6 FEI Total Delivery Margin Projections $Millions Note 1 575 577 588 600 612 624 637 649 662 676 7 8 Net COS Benefit (Cost) to Existing FEI Natural Gas Customers 9 Annual Incremental Margin from additional NGT volumes Sch 2, Line 40, Note 2,4 538 1,284 2,662 4,044 5,958 8,690 8,864 9,041 9,222 9,406 10 Annual Incentive Funding COS Sch 3, -Line 75 - - (3,488) (5,471) (7,181) (8,604) (9,192) (8,770) (8,348) (7,926) 11 Net Annual COS Benefit (Cost) '000$ Line 9 + Line 10 538 1,284 (826) (1,427) (1,223) 86 (328) 271 874 1,480 12 GGRR Application (Exhibit B-1) Appendices G and H 13 Approximate Annual FEI Delivery / (Reduction) Increase, % -Line 11 / (Line 6 x 1000), Note 3 0.14% 0.24% 0.20% (0.01)% 0.05% (0.04)% (0.13)% (0.22)% 14 15 Present Value of Annual Net COS Benefit (Cost) Line 11/(1+Line 3)^(Line 4) 504 1,126 (678) (1,096) (879) 58 (207) 160 483 766 16 17 NPV of Net COS Benefit (Cost) '000$ Sum Line 15 2012 to year 504 1,629 952 (144) (1,024) (966) (1,173) (1,013) (530) 235 18 19 NPV of Net COS Benefit (Cost) 2012 to 2030 (19 Years) 24,020 20 Note: 21 1: 2012, 2013 based on 2012-2013 RRA G-44-12 Compliance Filing May 1, 2012; 2014+ increase at 2%/year reflecting high level long range planning assumptions, 22 does not include any impact of the prescribed undertaking expenditures or prior incentives 23 2: 2012 & 2013 incremental margin added to non rate base deferral account in Schedule 3: Cost of Service Line 32 24 3: Cumulative FEI Delivery (Reduction) increase, FEI delivery margin does not include any impact of the prescribed undertaking expenditures or prior incentives 25 4: 2012 & 2013 includes some margin already included in the 2012/13 RRA 5

Appendix H - Scenario 2: GGRR Load Growth Only Appendix H - Scenario 2: GGRR Load Growth Only Potential Rate Impact to Existing FEI Natural Gas Customers Potential Rate Impact to Existing FEI Natural Gas Customers Schedule 1: Summary of Costs and Benefits (continued 2022-2030) Schedule 1: Summary of Costs and Benefits (continued 2022-2030) Market does not expand after incentives, NGV vehicles replaced at end of product cycle and volumes maintained $000's, unless otherwise stated Reference 2022 2023 2024 2025 2026 2027 2028 2029 2030 1 Annual NG Volume (TJ) Sch 2, Line 8 2,882 2,882 2,882 2,882 2,882 2,882 2,882 2,882 2,882 2 3 Discount Rate 2014 FEI After-Tax WACC 4 Discount Period (years) 11 12 13 14 15 16 17 18 19 5 6 FEI Total Delivery Margin Projections $Millions Note 1 689 703 717 731 746 761 776 792 808 7 8 Net COS Benefit (Cost) to Existing FEI Natural Gas Customers 9 Annual Incremental Margin from additional NGT volumes Sch 2, Line 40, Note 2,4 9,594 9,786 9,982 10,181 10,385 10,593 10,805 11,021 11,241 10 Annual Incentive Funding COS Sch 3, -Line 75 (7,504) (7,082) (4,876) (3,318) (1,971) (760) (0) (0) (0) 11 Net Annual COS Benefit (Cost) '000$ Line 9 + Line 10 2,090 2,704 5,106 6,863 8,414 9,833 10,805 11,021 11,241 12 GGRR Application (Exhibit B-1) Appendices G and H 13 Approximate Annual FEI Delivery / (Reduction) Increase, % -Line 11 / (Line 6 x 1000), Note 3 (0.30)% (0.38)% (0.71)% (0.94)% (1.13)% (1.29)% (1.39)% (1.39)% (1.39)% 14 15 Present Value of Annual Net COS Benefit (Cost) Line 11/(1+Line 3)^(Line 4) 1,012 1,226 2,167 2,727 3,130 3,424 3,523 3,364 3,212 16 17 NPV of Net COS Benefit (Cost) '000$ Sum Line 15 2012 to year 1,248 2,473 4,640 7,367 10,497 13,922 17,444 20,808 24,020 18 19 20 Note: 21 1: 2012, 2013 based on 2012-2013 RRA G-44-12 Compliance Filing May 1, 2012; 2014+ increase at 2%/year reflecting high level long range planning assumptions, 22 does not include any impact of the prescribed undertaking expenditures or prior incentives 23 2: 2012 & 2013 incremental margin added to non rate base deferral account in Schedule 3: Cost of Service Line 32 24 3: Cumulative FEI Delivery (Reduction) increase, FEI delivery margin does not include any impact of the prescribed undertaking expenditures or prior incentives 25 4: 2012 & 2013 includes some margin already included in the 2012/13 RRA 6

GGRR Application (Exhibit B-1) Appendices G and H Appendix H - Scenario 2: GGRR Load Growth Only Appendix H - Scenario 2: GGRR Load Growth Only Schedule 2, Part A: Benefits (2012-2021) Schedule 2, Part A: Benefits (2012-2021) Market does not expand after incentives, NGV vehicles replaced at end of product cycle and volumes maintained $000's, Unless Otherwise Stated Reference 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 1 Annual NG Volume (TJ) 2 Rate 16 not included in RRA 2012/13 12 183 698 1,036 1,482 2,103 2,103 2,103 2,103 2,103 3 Rate 16 included in RRA 2012/13 Note 8 139 139 4 Rate 23 not included in RRA 2012/13 1 1 15 27 39 55 55 55 55 55 5 Rate 23 included in RRA 2012/13 Note 8 6 6 6 Rate 25 not included in RRA 2012/13 2 110 204 353 512 725 725 725 725 725 7 Rate 25 included in RRA 2012/13 Note 8 19 19 8 Total NG Volume (TJ) Sum of Lines 2 to 7 178 458 917 1,416 2,032 2,882 2,882 2,882 2,882 2,882 9 Number of CNG Stations 10 Rate 23 - - - - 1 1 1 1 1 1 11 Rate 25 1 3 5 8 11 15 15 15 15 15 12 Number of LNG Stations 2 3 5 8 11 16 18 21 25 30 13 Estimated Impact to Rate 25 Demand Volume Note 1, 4, 10 8 378 698 1,210 1,752 2,482 2,482 2,482 2,482 2,482 14 Estimated Impact to Rate 25 Demand Volume Note 1, 5, 11 65 65 15 Volumetric Delivery Rates ($/GJ) Note 2 16 Rate 16 (Net of incremental costs) Note 3 2012 & 2013 approved 3.25 3.29 3.28 3.27 3.36 3.47 3.54 3.61 3.68 3.75 17 Rate 23 2012 & 2013 approved 2.44 2.62 2.67 2.72 2.78 2.83 2.89 2.95 3.01 3.07 18 Rate 25 2012 & 2013 approved 0.68 0.73 0.75 0.76 0.78 0.79 0.81 0.82 0.84 0.86 19 Demand Rates Note 2 20 Rate 25 $/ Month / GJ of Daily Demand 2012 & 2013 approved 16.82 18.06 18.42 18.79 19.17 19.55 19.94 20.34 20.75 21.16 21 Basic & Admin Charge Note 2, 7 22 Rate 23 $/Month 2012 & 2013 approved 210.52 210.52 214.73 219.03 223.41 227.87 232.43 237.08 241.82 246.66 23 Rate 25 $/Month 2012 & 2013 approved 665.00 665.00 678.30 691.87 705.70 719.82 734.21 748.90 763.88 779.15 24 Rate 16 $/Month Note 9 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 25 Inflation Annual: Delivery/Demand/Basic Long term planning assumptions 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 7

Appendix H - Scenario 2: GGRR Load Growth Only Appendix H - Scenario 2: GGRR Load Growth Only Schedule 2, Part B: Benefits (2012-2021) Schedule 2, Part B: Benefits (2012-2021) Market does not expand after incentives, NGV vehicles replaced at end of product cycle and volumes maintained $000's, Unless Otherwise Stated Reference 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 26 Incremental Margin '000$ 27 Delivery 28 Rate 16 not included in RRA 2012/13 (Line 2 x Line 16) 37 604 2,288 3,386 4,988 7,291 7,437 7,586 7,738 7,892 29 Rate 16 included in RRA 2012/13 (Line 3 x Line 16) 450 456 30 Rate 23 not included in RRA 2012/13 (Line 4 x Line 17) 2 2 41 72 107 155 158 161 164 167 31 Rate 23 included in RRA 2012/13 (Line 5 x Line 17) 15 16 32 Rate 25 not included in RRA 2012/13 (Line 6 x Line 18) 2 81 152 269 397 573 585 597 609 621 33 Rate 25 included in RRA 2012/13 (Line 7 x Line 18) 13 14 34 Demand 35 Rate 25 not included in RRA 2012/13 (Line 13xLine 20x12/1000) 2 82 154 273 403 582 594 606 618 630 36 Rate 25 included in RRA 2012/13 (Line 14xLine 20x12/1000) 13 14 37 Basic Charges GGRR Application (Exhibit B-1) Appendices G and H 38 Rate 23 + 25 Note 6 5 16 27 44 64 88 90 92 94 95 39 Rate 16 - - - - - - - - - - 40 Total Incremental Margin Sum of Lines 28 to 39 538 1,284 2,662 4,044 5,958 8,690 8,864 9,041 9,222 9,406 41 Cumulative Incremental Margin 538 1,822 4,484 8,528 14,487 23,177 32,040 41,081 50,303 59,709 42 Note: 43 1 Compression load is assumed to be consistent; therefore, the peak will not change in a winter month 44 2 Existing delivery / demand / basic & admin charges are approved 2012 and 2013 charges, 2014+ increase at 2% per year reflecting high level long range planning assumptions 45 3 Rate 16 reflects delivery rate minus incremental cost of LNG (incremental O&M / incremental volume sold into the LNG market), further detail included in this appendix, 46 Financial Assumptions, section 8 47 4 Rate 25 demand volumes not included in RRA 2012/13 filing 48 5 Rate 25 demand volumes included in RRA 2012/13 filing 49 6 (Line 10 x Line 22 x 12) /1000 x (2/3) + (Line 11 x Line 23 x 12) /1000 x (2/3); Basic charges reduce by 1/3 to reflect that some existing accounts are already on R23/25 50 7 New CNG/LNG stations results in new Rate 23/25 accounts 51 8 Volumes related to prior incentives, included in 2012/13 RRA 52 9 There are no basic or admin charges for LNG Rate 16 accounts 53 10 Line 6 / 365 x 1.25 x 1000 54 11 Line 7 / 365 x 1.25 x 1000 8

Appendix H - Scenario 2: GGRR Load Growth Only Appendix H - Scenario 2: GGRR Load Growth Only Schedule 2, Part A: Benefits (continued 2022-2030) Schedule 2, Part A: Benefits (continued 2022-2030) Market does not expand after incentives, NGV vehicles replaced at end of product cycle and volumes maintained $000's, Unless Otherwise Stated Reference 2022 2023 2024 2025 2026 2027 2028 2029 2030 1 Annual NG Volume (TJ) 2 Rate 16 not included in RRA 2012/13 2,103 2,103 2,103 2,103 2,103 2,103 2,103 2,103 2,103 3 Rate 16 included in RRA 2012/13 Note 8 4 Rate 23 not included in RRA 2012/13 55 55 55 55 55 55 55 55 55 5 Rate 23 included in RRA 2012/13 Note 8 6 Rate 25 not included in RRA 2012/13 725 725 725 725 725 725 725 725 725 7 Rate 25 included in RRA 2012/13 Note 8 8 Total NG Volume (TJ) Sum of Lines 2 to 7 2,882 2,882 2,882 2,882 2,882 2,882 2,882 2,882 2,882 9 Number of CNG Stations 10 Rate 23 - - - 1 1 1 1 1 1 11 Rate 25 3 5 8 11 15 15 15 15 15 12 Number of LNG Stations 3 5 8 11 16 18 21 25 30 13 Estimated Impact to Rate 25 Demand Volume 1,4 Note 1, 4, 10 2,482 2,482 2,482 2,482 2,482 2,482 2,482 2,482 2,482 14 Estimated Impact to Rate 25 Demand Volume 1,5 Note 1, 5, 11 GGRR Application (Exhibit B-1) Appendices G and H 15 Volumetric Delivery Rates ($/GJ) Note 2 16 Rate 16 (Net of incremental costs) Note 3 2012 & 2013 approved 3.83 3.90 3.98 4.06 4.14 4.23 4.31 4.40 4.48 17 Rate 23 2012 & 2013 approved 3.13 3.19 3.25 3.32 3.39 3.45 3.52 3.59 3.66 18 Rate 25 2012 & 2013 approved 0.87 0.89 0.91 0.93 0.95 0.96 0.98 1.00 1.02 19 Demand Rates 20 Rate 25 $/ Month / GJ of Daily Demand 2012 & 2013 approved 21.59 22.02 22.46 22.91 23.37 23.83 24.31 24.80 25.29 21 Basic & Admin Charge Note 2, 7 22 Rate 23 $/Month 2012 & 2013 approved 251.59 256.62 261.76 266.99 272.33 277.78 283.33 289.00 294.78 23 Rate 25 $/Month 2012 & 2013 approved 794.74 810.63 826.84 843.38 860.25 877.45 895.00 912.90 931.16 24 Rate 16 $/Month Note 9 25 Inflation Annual: Delivery/Demand/Basic Long term planning assumptions 0.02 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 9

GGRR Application (Exhibit B-1) Appendices G and H Appendix H - Scenario 2: GGRR Load Growth Only Appendix H - Scenario 2: GGRR Load Growth Only Schedule 2, Part B: Benefits (continued 2022-2030) Schedule 2, Part B: Benefits (continued 2022-2030) Market does not expand after incentives, NGV vehicles replaced at end of product cycle and volumes maintained $000's, Unless Otherwise Stated Reference 2022 2023 2024 2025 2026 2027 2028 2029 2030 26 Incremental Margin '000$ 27 Delivery 28 Rate 16 not included in RRA 2012/13 (Line 2 x Line 16) 8,050 8,211 8,375 8,543 8,714 8,888 9,066 9,247 9,432 29 Rate 16 included in RRA 2012/13 (Line 3 x Line 16) - - - - - - - - - 30 Rate 23 not included in RRA 2012/13 (Line 4 x Line 17) 171 174 177 181 185 188 192 196 200 31 Rate 23 included in RRA 2012/13 (Line 5 x Line 17) - - - - - - - - - 32 Rate 25 not included in RRA 2012/13 (Line 6 x Line 18) 633 646 659 672 685 699 713 727 742 33 Rate 25 included in RRA 2012/13 (Line 7 x Line 18) - - - - - - - - - 34 Demand 35 Rate 25 not included in RRA 2012/13 (Line 13xLine 20x12/1000) 643 656 669 682 696 710 724 738 753 36 Rate 25 included in RRA 2012/13 (Line 14xLine 20x12/1000) - - - - - - - - - 37 Basic Charges 38 Rate 23 + 25 Note 6 97 99 101 103 105 108 110 112 114 39 Rate 16 - - - - - - - - - 40 Total Incremental Margin Sum of Lines 28 to 39 9,594 9,786 9,982 10,181 10,385 10,593 10,805 11,021 11,241 41 Cumulative Incremental Margin 69,303 79,089 89,071 99,252 109,637 120,230 131,035 142,055 153,297 42 Note: 43 1 Compression load is assumed to be consistent; therefore, the peak will not change in a winter month 44 2 Existing delivery / demand / basic & admin charges are approved 2012 and 2013 charges, 2014+ increase at 2% per year reflecting high level long range planning assumptions 45 3 Rate 16 reflects delivery rate minus incremental cost of LNG (incremental O&M / incremental volume sold into the LNG market), further detail included in this appendix, 46 Financial Assumptions, section 8 47 4 Rate 25 demand volumes not included in RRA 2012/13 filing 48 5 Rate 25 demand volumes included in RRA 2012/13 filing 49 6 (Line 10 x Line 22 x 12) /1000 x (2/3) + (Line 11 x Line 23 x 12) /1000 x (2/3); Basic charges reduce by 1/3 to reflect that some existing accounts are already on R23/25 50 7 New CNG/LNG stations results in new Rate 23/25 accounts 51 8 Volumes related to prior incentives, included in 2012/13 RRA 52 9 There are no basic or admin charges for LNG Rate 16 accounts 53 10 Line 6 / 365 x 1.25 x 1000 54 11 Line 7 / 365 x 1.25 x 1000 10

GGRR Application (Exhibit B-1) Appendices G and H Appendix H - Scenario 2: GGRR Load Growth Only Appendix H - Scenario 2: GGRR Load Growth Only Schedule 3, Part A: Cost of Service (2011-2021) Schedule 3, Part A: Cost of Service (2011-2021) Market does not expand after incentives, NGV vehicles replaced at end of product cycle and volumes maintained $000's, Unless Otherwise Stated Reference 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 1 Key Assumptions 2 Rates 3 ROE % BCUC Order No. G-44-12 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 4 STD Rate BCUC Order No. G-44-12 4.50% 2.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 5 LTD Rate BCUC Order No. G-44-12 6.95% 6.85% 6.87% 6.87% 6.87% 6.87% 6.87% 6.87% 6.87% 6.87% 6.87% 6 Capital Structure 7 Equity BCUC Order No. G-44-12 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 8 STD % BCUC Order No. G-44-12 1.63% 1.93% 3.03% 3.03% 3.03% 3.03% 3.03% 3.03% 3.03% 3.03% 3.03% 9 LTD % BCUC Order No. G-44-12 58.37% 58.07% 56.97% 56.97% 56.97% 56.97% 56.97% 56.97% 56.97% 56.97% 56.97% 10 Total % 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 11 Return on Rate Base Note 5 7.93% 7.83% 7.82% 7.82% 7.82% 7.82% 7.82% 7.82% 7.82% 7.82% 7.82% 12 WACC Note 6 6.84% 6.82% 6.81% 6.81% 6.81% 6.81% 6.81% 6.81% 6.81% 6.81% 6.81% 13 Tax Rate 26.50% 25.00% 25.00% 25.00% 25.00% 25.00% 25.00% 25.00% 25.00% 25.00% 25.00% 14 Incentive Award Schedule Note 1 15 Prior Vehicle Incentives Note 10 5,573 16 Vehicle & Marine - 7,843 11,479 10,404 9,807 9,794-17 Maintenance Upgrades & Safety - 200 950 950 950 950-18 Admin, Marketing, Train, Education - 300 1,000 900 600 300-19 Total Incentive Awards ($62000) Sum of Lines 15 to 18 5,573 8,343 13,429 12,254 11,357 11,044-20 Incentive Payouts (Cash Basis) Note 1 21 Prior Vehicle Incentives 5,573 22 Vehicle & Marine Note 1-1,961 8,752 11,210 10,255 9,804 7,345 23 Maintenance Upgrades & Safety Note 1 50 922 950 950 1,128-24 Admin, Marketing, Train, Education Note 1 300 1,000 900 600 300-25 Total Incentive Payouts (Cash Basis) Sum of Lines 21 to 24 5,573 2,311 10,674 13,060 11,805 11,232 7,345 11

GGRR Application (Exhibit B-1) Appendices G and H Appendix H - Scenario 2: GGRR Load Growth Only Appendix H - Scenario 2: GGRR Load Growth Only Schedule 3, Part B: Cost of Service (2012-2021) Schedule 3, Part B: Cost of Service (2012-2021) Market does not expand after incentives, NGV vehicles replaced at end of product cycle and volumes maintained $000's, Unless Otherwise Stated Reference 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 26 Non Rate Base Deferral Account (NRBDA)Calculation 27 Gross Additions Line 25 (2011-2013) 5,573 2,311 10,674 28 Tax - Line 27 x Line 13 (1,477) (578) (2,668) - - - - - - - - 29 Net Additions Line 27 + Line 28 4,097 1,733 8,005 - - - - - - - - 30 Opening Deferral Account Balance Previous Year, Line 34-4,097 5,851 31 Net Additions Line 29 4,097 1,733 8,005 32 Incremental Margins pre 2014 Note 7 (36) (588) 33 AFUDC on Deferral Account pre 2014 Note 4, 11-58 585 34 Closing Deferral Account Balance Sum of Lines 30 to 33 4,097 5,851 13,853 35 Rate Base Deferral Account Calculation 36 Amortization Period (Years) 10 37 Gross Additions Line 25 (2014+) 13,060 11,805 11,232 7,345 - - - - 38 Tax - Line 37 x Line 13 (3,265) (2,951) (2,808) (1,836) - - - - 39 Net Additions Line 37 + Line 38 9,795 8,854 8,424 5,509 - - - - 40 Annual Amortization of Net Addition Line 39/10 years 980 885 842 551 - - - - 41 Add NRBDA Line 34, 2013 Closing & Note 2 13,853 42 Annual Amortization of NRBDA Line 41/10 years 1,385 43 Opening Deferral Account Balance Note 8 13,853 22,263 28,752 33,925 35,342 30,698 26,055 21,411 44 Net Additions Line 39 9,795 8,854 8,424 5,509 - - - - 45 Amortization: Net Additions Sum of Line 40 & Note 9 (980) (1,865) (2,707) (3,258) (3,258) (3,258) (3,258) 46 Amortization: NRBDA Line 42 over 10 years & Note 3 (1,385) (1,385) (1,385) (1,385) (1,385) (1,385) (1,385) (1,385) 47 Closing Deferral Account Balance Sum of Lines 43 to 46 22,263 28,752 33,925 35,342 30,698 26,055 21,411 16,768 48 Total Amortization Line 45 + Line 46 (1,385) (2,365) (3,250) (4,093) (4,643) (4,643) (4,643) (4,643) 49 Mid Year Rate Base (Line 43 + Line 47)/2 18,058 25,508 31,339 34,634 33,020 28,377 23,733 19,090 50 Income Tax Expense 51 Equity Earned Return Line 60 - - - 686 969 1,191 1,316 1,255 1,078 902 725 52 Add: Amortization Expense - Line 48 - - - 1,385 2,365 3,250 4,093 4,643 4,643 4,643 4,643 53 Taxable Income After Tax Line 51 + Line 52 - - - 2,072 3,334 4,441 5,409 5,898 5,722 5,545 5,369 54 Taxable Income Line 53 / (1 - Line 13) - - - 2,762 4,446 5,921 7,212 7,864 7,629 7,394 7,159 55 Income Tax Expense Line 54 x Line 13 - - - 691 1,111 1,480 1,803 1,966 1,907 1,848 1,790 12

GGRR Application (Exhibit B-1) Appendices G and H Appendix H - Scenario 2: GGRR Load Growth Only Appendix H - Scenario 2: GGRR Load Growth Only Schedule 3, Part C: Cost of Service (2012-2021) Schedule 3, Part C: Cost of Service (2012-2021) Market does not expand after incentives, NGV vehicles replaced at end of product cycle and volumes maintained $000's, Unless Otherwise Stated Reference 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 56 Earned Return 57 Total Rate Base Line 49 18,058 25,508 31,339 34,634 33,020 28,377 23,733 19,090 58 ROE Rate % Line 3 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 59 Equity Ratio % Line 7 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 60 Equity Return Line 57 x Line 58 x Line 59 686 969 1,191 1,316 1,255 1,078 902 725 61 Total Rate Base Line 49 18,058 25,508 31,339 34,634 33,020 28,377 23,733 19,090 62 Short Term Debt Rate % Line 4 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 63 Short Term Debt Ratio % Line 8 3.03% 3.03% 3.03% 3.03% 3.03% 3.03% 3.03% 3.03% 64 Short Term Debt Component Line 61 x Line 62 x Line 63 19 27 33 37 35 30 25 20 65 Total Rate Base Line 49 18,058 25,508 31,339 34,634 33,020 28,377 23,733 19,090 66 Long Term Debt Rate % Line 5 6.87% 6.87% 6.87% 6.87% 6.87% 6.87% 6.87% 6.87% 67 Long Term Debt Ratio % Line 9 56.97% 56.97% 56.97% 56.97% 56.97% 56.97% 56.97% 56.97% 68 Long Term Debt Component Line 65 x Line 66 x Line 67 707 998 1,227 1,356 1,292 1,111 929 747 69 Total Debt Component Line 64 + Line 68 726 1,025 1,260 1,392 1,327 1,141 954 767 70 Total Earned Return Line 60 + Line 69 1,412 1,995 2,451 2,708 2,582 2,219 1,856 1,493 71 Annual Cost of Service Impact of NGT Incentive Program 72 Amortization Expense - Line 48 - - - 1,385 2,365 3,250 4,093 4,643 4,643 4,643 4,643 73 Income Tax Expense Line 55 - - - 691 1,111 1,480 1,803 1,966 1,907 1,848 1,790 74 Earned Return Line 70 - - - 1,412 1,995 2,451 2,708 2,582 2,219 1,856 1,493 75 Total Cost of Service Sum of Lines 72 to 74 - - - 3,488 5,471 7,181 8,604 9,192 8,770 8,348 7,926 76 Note: 77 1: This appendix, Financial Assumptions, Section 4 78 2: Non rate base deferral account is transferred to the rate base deferral account at the start of 2014 79 3: Non rate base deferral account transferred to rate base deferral account in 2014 and amortized over 10 years starting in 2014 80 4: AFUDC calculated on prior incentives added to non rate base deferral account from the date (forecasted Oct 2012) of the first vehicle and marine incentive payment to end of 2013 81 5: Line 3 x Line 7 + Line 4 x Line 8 + Line 5 x Line 9 82 6: Line 3 x Line 7 + (Line 4 x Line 8 + Line 5 x Line 9) x (1 - Line 13) 83 7: Exclude volumes / margin already included in RRA 2012/2013; Schedule 2 Benefits: Line 28+ Line 30 + Line 32 + Line 35 + Line 38 84 8: 2014 Opening rate base deferral account equals 2013 closing non rate base deferral account of $13.853 Million, 2015 onwards previous year line 47 85 9: Amortization of new additions in following year over 10 years 86 10: Prior incentive spending in 2011 includes 2010 amounts, totals $5.573 million 87 11: AFUDC calculated on incentives added to the non rate base deferral account from Aug 2012 to the end of 2013 13

GGRR Application (Exhibit B-1) Appendices G and H Appendix H - Scenario 2: GGRR Load Growth Only Appendix H - Scenario 2: GGRR Load Growth Only Schedule 3, Part A: Cost of Service (continued 2022-2030) Schedule 3, Part A: Cost of Service (continued 2022-2030) Market does not expand after incentives, NGV vehicles replaced at end of product cycle and volumes maintained $000's, Unless Otherwise Stated Reference 2022 2023 2024 2025 2026 2027 2028 2029 2030 1 Key Assumptions - 2 Rates 3 ROE % BCUC Order No. G-44-12 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 4 STD Rate BCUC Order No. G-44-12 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 5 LTD Rate BCUC Order No. G-44-12 6.87% 6.87% 6.87% 6.87% 6.87% 6.87% 6.87% 6.87% 6.87% 6 Capital Structure 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 7 Equity BCUC Order No. G-44-12 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 8 STD % BCUC Order No. G-44-12 3.03% 3.03% 3.03% 3.03% 3.03% 3.03% 3.03% 3.03% 3.03% 9 LTD % BCUC Order No. G-44-12 56.97% 56.97% 56.97% 56.97% 56.97% 56.97% 56.97% 56.97% 56.97% 10 Total % 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 11 Return on Rate Base Note 5 7.82% 7.82% 7.82% 7.82% 7.82% 7.82% 7.82% 7.82% 7.82% 12 WACC Note 6 6.81% 6.81% 6.81% 6.81% 6.81% 6.81% 6.81% 6.81% 6.81% 13 Tax Rate 25.00% 25.00% 25.00% 25.00% 25.00% 25.00% 25.00% 25.00% 25.00% 14 Incentive Award Schedule Note 1 15 Prior Vehicle Incentives Note 10 - - - - - - - - - 16 Vehicle & Marine - - - - - - - - - 17 Maintenance Upgrades & Safety - - - - - - - - - 18 Admin, Marketing, Train, Education - - - - - - - - - 19 Total Incentive Awards ($62000) Sum of Lines 15 to 18 - - - - - - - - - 20 Incentive Payouts (Cash Basis) Note 1 21 Prior Vehicle Incentives - - - - - - - - - 22 Vehicle & Marine Note 1 - - - - - - - - - 23 Maintenance Upgrades & Safety Note 1 - - - - - - - - - 24 Admin, Marketing, Train, Education Note 1 - - - - - - - - - 25 Total Incentive Payouts (Cash Basis) Sum of Lines 21 to 24 - - - - - - - - - 14

GGRR Application (Exhibit B-1) Appendices G and H Appendix H - Scenario 2: GGRR Load Growth Only Appendix H - Scenario 2: GGRR Load Growth Only Schedule 3, Part B: Cost of Service (continued 2022-2030) Schedule 3, Part B: Cost of Service (continued 2022-2030) Market does not expand after incentives, NGV vehicles replaced at end of product cycle and volumes maintained $000's, Unless Otherwise Stated Reference 2022 2023 2024 2025 2026 2027 2028 2029 2030 26 Non Rate Base Deferral Account (NRBDA)Calculation 27 Gross Additions Line 25 (2011-2013) - - - - - - - - - 28 Tax - Line 27 x Line 13 - - - - - - - - - 29 Net Additions Line 27 + Line 28 - - - - - - - - - 30 Opening Deferral Account Balance Previous Year, Line 34 - - - - - - - - - 31 Net Additions Line 29 - - - - - - - - - 32 Incremental Margins pre 2014 Note 7 - - - - - - - - - 33 AFUDC on Deferral Account pre 2014 Note 4, 11 - - - - - - - - - 34 Closing Deferral Account Balance Sum of Lines 30 to 33 - - - - - - - - - 35 Rate Base Deferral Account Calculation 36 Amortization Period (Years) 37 Gross Additions Line 25 (2014+) - - - - - - - - - 38 Tax - Line 37 x Line 13 - - - - - - - - - 39 Net Additions Line 37 + Line 38 - - - - - - - - - 40 Annual Amortization of Net Addition Line 39/10 years - - - - - - - - - 41 Add NRBDA Line 34, 2013 Closing & Note 2 - - - - - - - - - 42 Annual Amortization of NRBDA Line 41/10 years - - - - - - - - - 43 Opening Deferral Account Balance Note 8 16,768 12,125 7,481 4,223 1,944 551 0 0 0 44 Net Additions Line 39 - - - - - - - - - 45 Amortization: Net Additions Sum of Line 40 & Note 9 (3,258) (3,258) (3,258) (2,279) (1,393) (551) - - - 46 Amortization: NRBDA Line 42 over 10 years & Note 3 (1,385) (1,385) - - - - - - - 47 Closing Deferral Account Balance Sum of Lines 43 to 46 12,125 7,481 4,223 1,944 551 0 0 0 0 48 Total Amortization Line 45 + Line 46 (4,643) (4,643) (3,258) (2,279) (1,393) (551) - - - 49 Mid Year Rate Base (Line 43 + Line 47)/2 14,446 9,803 5,852 3,084 1,248 275 0 0 0 50 Income Tax Expense 51 Equity Earned Return Line 60 549 373 222 117 47 10 0 0 0 52 Add: Amortization Expense - Line 48 4,643 4,643 3,258 2,279 1,393 551 - - - 53 Taxable Income After Tax Line 51 + Line 52 5,192 5,016 3,481 2,396 1,441 561 0 0 0 54 Taxable Income Line 53 / (1 - Line 13) 6,923 6,688 4,641 3,194 1,921 748 0 0 0 55 Income Tax Expense Line 54 x Line 13 1,731 1,672 1,160 799 480 187 0 0 0 15

GGRR Application (Exhibit B-1) Appendices G and H Appendix H - Scenario 2: GGRR Load Growth Only Appendix H - Scenario 2: GGRR Load Growth Only Schedule 3, Part C: Cost of Service (continued 2022-2030) Schedule 3, Part C: Cost of Service (continued 2022-2030) Market does not expand after incentives, NGV vehicles replaced at end of product cycle and volumes maintained $000's, Unless Otherwise Stated Reference 2022 2023 2024 2025 2026 2027 2028 2029 2030 56 Earned Return 57 Total Rate Base Line 49 14,446 9,803 5,852 3,084 1,248 275 0 0 0 58 ROE Rate % Line 3 0 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 9.50% 59 Equity Ratio % Line 7 0 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 60 Equity Return Line 57 x Line 58 x Line 59 549 373 222 117 47 10 0 0 0 61 Total Rate Base Line 49 14,446 9,803 5,852 3,084 1,248 275 0 0 0 62 Short Term Debt Rate % Line 4 0 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 63 Short Term Debt Ratio % Line 8 0 3.03% 3.03% 3.03% 3.03% 3.03% 3.03% 3.03% 3.03% 64 Short Term Debt Component Line 61 x Line 62 x Line 63 15 10 6 3 1 0 0 0 0 65 Total Rate Base Line 49 14,446 9,803 5,852 3,084 1,248 275 0 0 0 66 Long Term Debt Rate % Line 5 0 6.87% 6.87% 6.87% 6.87% 6.87% 6.87% 6.87% 6.87% 67 Long Term Debt Ratio % Line 9 1 56.97% 56.97% 56.97% 56.97% 56.97% 56.97% 56.97% 56.97% 68 Long Term Debt Component Line 65 x Line 66 x Line 67 565 384 229 121 49 11 0 0 0 69 Total Debt Component Line 64 + Line 68 581 394 235 124 50 11 0 0 0 70 Total Earned Return Line 60 + Line 69 0 1,130 767 458 241 98 22 0 0 0 71 Annual Cost of Service Impact of NGT Incentive Program 72 Amortization Expense - Line 48 4,643 4,643 3,258 2,279 1,393 551 - - - 73 Income Tax Expense Line 55 1,731 1,672 1,160 799 480 187 0 0 0 74 Earned Return Line 70 1,130 767 458 241 98 22 0 0 0 75 Total Cost of Service Sum of Lines 72 to 74 7,504 7,082 4,876 3,318 1,971 760 0 0 0 76 Note: 77 1: This appendix, Financial Assumptions, Section 4 78 2: Non rate base deferral account is transferred to the rate base deferral account at the start of 2014 79 3: Non rate base deferral account transferred to rate base deferral account in 2014 and amortized over 10 years starting in 2014 80 4: AFUDC calculated on prior incentives added to non rate base deferral account from the date (forecasted Oct 2012) of the first vehicle and marine incentive payment to end of 2013 81 5: Line 3 x Line 7 + Line 4 x Line 8 + Line 5 x Line 9 82 6: Line 3 x Line 7 + (Line 4 x Line 8 + Line 5 x Line 9) x (1 - Line 13) 83 7: Exclude volumes / margin already included in RRA 2012/2013; Schedule 2 Benefits: Line 28+ Line 30 + Line 32 + Line 35 + Line 38 84 8: 2014 Opening rate base deferral account equals 2013 closing non rate base deferral account of $13.853 Million, 2015 onwards previous year line 47 85 9: Amortization of new additions in following year over 10 years 86 10: Prior incentive spending in 2011 includes 2010 amounts, totals $5.573 million 87 11: AFUDC calculated on incentives added to the non rate base deferral account from Aug 2012 to the end of 2013 16

Appendix E FUEL COST SAVINGS

FortisBC Energy Inc. ("FEI" or the Company ) Application for Approval of Rate Treatment of Expenditures under the Greenhouse Gas Reductions (Clean Energy) Regulation ( GGRR ), and Prudency Review of Incentives under the 2010 2011 Commercial NGV Demonstration Program (the Application ) Response to Commercial Energy Consumers Association of British Columbia ( CEC ) Information Request ( IR ) No. 1 Submission Date: October 15, 2012 Page 47 11. Exhibit B-1, Page 31 11.1 Do all of the investments made remain used and useful to the end use customers and to the existing natural gas ratepayers. Response: Yes, all investments made by the Utility remain used and useful. To clarify, the investment by the Utility is the incentives granted to assist with vehicle purchases. The vehicles themselves are not being added to rate base. Rather, the incentives are included in a rate base deferral account and the costs are amortized over a fixed period. An incentive is used and useful throughout its amortization period as it has resulted in the purchase of a vehicle, its intended utility purpose. Please refer to the response to BCUC IR 1.5.1 for the expected vehicle measure life for each customer. 11.2 Please update the table with current actual results. Response: The following table contains updated actual results: