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					                                                                   Scott A. Thomson
                                                                   Vice President,
                                                                   Finance & Regulatory Affairs

                                                                   16705 Fraser Highway
                                                                   Surrey, B.C. V3S 2X7
                                                                   Tel: (604) 592-7784
                                                                   Fax: (604) 592-7890
                                                                   Email: scott.thomson@terasengas.com
                                                                   www.terasengas.com




November 8, 2004



British Columbia Utilities Commission
Sixth Floor - 900 Howe Street
Vancouver, B.C.
V6Z 2N3

Attention: Mr. Robert J. Pellatt, Commission Secretary


RE:     Terasen Gas (Vancouver Island) Inc. (“TGVI”)
        Review of Resource Plan and an Application for a Certificate of Public
        Convenience and Necessity (“CPCN”) for a Liquefied Natural Gas Storage Project
        Response to Commission Information Request No. 2

Terasen Gas (Vancouver Island) Inc. respectfully submits the attached respons es to
Commission Information Request No. 2, which was received on November 2, 2004. In that
request the Commission requested a response by Friday November 5, however in discussion
with Commission staff, it was agreed that TGVI could submit first thing Monday, November 8.
Twenty hard copies of the attached will be sent to the Commission office this afternoon.

Yours very truly,

TERASEN GAS (VANCOUVER ISLAND) INC.

Original signed by Tom Loski for:


Scott A. Thomson

Encl.

c.      Registered Intervenors
                        TERASEN GAS (VANCOUVER ISLAND) INC.

        RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
       CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                 DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

              RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




48.0   Reference:     Exhibit B-3, Response to BCUC IR 34.0; Exhibit B-6, Tab 3,
                    MEM IR 4.3, 21.3; October 22 Workshop

       TGVI uses the term Base to refer to the most likely scenario, including the base core
       market forecast, the Squamish forecast, the base VIGJV forecast and the expectation of
       firm service to ICP. TGVI states that the decrease in VIGJV demand may be greater
       than it forecast in the CPCN Application.

       Further to information from the Workshop, the Commission understands TGVI and the
       VIGJV may be discussing an arrangement whereby the Contract Demand (“CD”) of the
       VIGJV Transportation Service Agreement (“TSA”) may be reduced to 12.5 TJ/d and the
       Peaking Gas Management Agreement may be terminated, effective January 1, 2006.

       48.1   Please describe TGVI’s most current expectations about forecast design day
              loads, and update the Base Forecast shown in Appendix 3 of the CPCN
              Application to reflect TGVI’s most recent information regarding VIGJV demand
              and any revised expectations regarding ICP (“Revised Base forecast”). On the
              assumption that the VIGJV TSA CD will be reduced to 12.5 TJ/d, the Revised
              Base forecast for 2007 would appear to be 169.9 TJ/d before curtailments. If this
              is not the case, please explain.

              Also, please assume that ICP has fuel switching capability, and can provide up to
              240 hours of curtailment in a design year (based on the response to BCUC IR
              34.13).

       Response

       Recent developments with the VIGJV and the BC Hydro CFT process provide more
       clarity on forecast design day loads. Regarding the VIGJV demand, a new arrangement
       has been reached between TGVI and the VIGJV which will reduce the long-term
       forecast of the VIGJV firm demand from the previous assumption of 33.6 TJ/day to 12.5
       TJ/day. In concert with this reduction, peaking gas supply available under the PGMA will
       also be reduced to 0 TJ/d. BC Hydro also recently announced the outcome of their CFT
       process on Vancouver Island. The selected 252 MW gas-fired Duke Point Power project
       is expected to require 45 TJ/d of firm gas transportation.

       To address the VIGJV demand reduction, TGVI has revised its Base forecast (see also
       IR 49.1). The Revised Base forecast results in a demand of 169.9 TJ/d before
       curtailment in 2007 as shown in the table below. Completion of the CFT process reduces


                                             -1-
                    TERASEN GAS (VANCOUVER ISLAND) INC.

        RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
       CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                 DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

             RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




uncertainty related to the generation component of the gross demand forecast. Only two
outcomes need now be considered to reflect Commission approval of the EPA awarded
as a result of the CFT:

   •   Revised Base +0, which reflects the most likely outcome if the CFT generation
       does not proceed.
   •   Revised Base +45, which reflects the most likely outcome if the CFT generation
       does proceed.

Core market and ICP forecast requirements remain unchanged. The following table is a
revision of that included in Appendix 3 of the CPCN Application and shows the
component requirements of the Revised Base forecast irrespective of any peaking gas
supply or curtailment:

Revised Forecasts: Base + 0 and Base + 45

Gas Core        Squamish Joint     BC Hydro BC Hydro Revised Revised
Year Customers            Venture (ICP)      (CFT)      Base + 0 Base + 45
2005      100.4       4.8     20.0      38.0        0.0     163.2     163.2
2006      103.9       5.0     12.5      38.0        0.0     159.4     159.4
2007      107.3       5.1     12.5      45.0       45.0     169.9     214.9
2008      110.5       5.3     12.5      45.0       45.0     173.3     218.3
2009      113.6       5.5     12.5      45.0       45.0     176.6     221.6
2010      116.4       5.7     12.5      45.0       45.0     179.6     224.6
2011      119.0       5.9     12.5      45.0       45.0     182.4     227.4
2012      121.5       6.1     12.5      45.0       45.0     185.1     230.1
2013      123.9       6.3     12.5      45.0       45.0     187.7     232.7
2014      126.4       6.4     12.5      45.0       45.0     190.3     235.3
2015      129.0       6.6     12.5      45.0       45.0     193.1     238.1
2016      131.5       6.8     12.5      45.0       45.0     195.8     240.8
2017      134.2       7.0     12.5      45.0       45.0     198.7     243.7
2018      136.9       7.1     12.5      45.0       45.0     201.5     246.5
2019      139.6       7.3     12.5      45.0       45.0     204.4     249.4
2020      142.4       7.5     12.5      45.0       45.0     207.4     252.4
2021      145.2       7.7     12.5      45.0       45.0     210.4     255.4
2022      148.1       7.8     12.5      45.0       45.0     213.4     258.4
2023      151.1       8.0     12.5      45.0       45.0     216.6     261.6
2024      154.1       8.2     12.5      45.0       45.0     219.8     264.8
2025      157.2       8.4     12.5      45.0       45.0     223.1     268.1
2026      160.4       8.5     12.5      45.0       45.0     226.4     271.4




                                      -2-
                     TERASEN GAS (VANCOUVER ISLAND) INC.

         RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
        CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                  DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

             RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




48.2   Using the Revised Base forecast and ICP curtailment assumption from the
       preceding question and making full use of such curtailment, please provide
       updated information for the LNG, Pipe and Compression and PCC portfolios for
       each of the Base +0, Base +20 and Base +45 forecasts. For each scenario,
       please provide the Incremental TGVI Facility Requirements schedule, the
       expanded Cost of Service Summary for Incremental TGVI Facilities and figures
       and schedule showing system costs and rate impacts similar to those that were
       provided in response to BCUC IR 41.7.

Response

In the response to BCUC IR48.1, TGVI has provided updated demand forecasts that
reflects the current expectation of the VIGJV long-term firm capacity requirement and the
outcome of BC Hydro’s CFT. TGVI has used the Revised Base +0 and the Revised
Base +45 demand forecasts to develop new resource portfolios based on similar
assumptions and criteria used in the Resource Plan and the LNG Facility CPCN. From
the requirements of each of the demand forecasts revised capital plans for each
portfolios are attached (Attachment 3). Two PC&C portfolios have been developed, the
first based on ICP’s existing 53 hour distillate storage capacity, and the second
assuming 240 hours of fuel switching is available. A discussion of the considerations that
were made when developing the portfolios with ICP curtailment is provided in
Attachment 1 to this IR response.

In the Revised Base +0 scenario where the Commission does not approve the proposed
Duke Point Power project, no new facilities are required in 2007 if the existing ICP fuel
switching capacity (53 hrs) is used. In other words, the LNG facility could be deferred
and could be displaced by other future resources. As a result the cost of service
summaries (Attachment 4) and customer impact information have only been prepared
for the Revised Base +45 scenarios in order to support the immediate approvals that are
required concerning BC Hydro’s CFT result and TGVI’s proposed LNG facility. If the
Duke Point Power project does not proceed, TGVI will review its resource portfolio
options and resubmit its four year Action Plan to reflect changes to its long-term plans
for facility additions.

The impact of the Revised Base +45 forecast on the facility additions required in the
LNG Portfolio is illustrated in Figure BCUC IR48.2a in Attachment 2. The reduction in
baseload demand from the original Base +45 demand scenario allows for the deferral of
new compressor additions and also defers the need for any looping requirements
outside the planning period. In addition, as illustrated in Figure BCUC IR48.2b, in this
scenario TGVI is using more of the LNG storage capacity for meeting its own
requirements in the initial years than was anticipated in the original Base +45 forecast.
This reduces the amount of available capacity used for third party storage services,




                                       -3-
                      TERASEN GAS (VANCOUVER ISLAND) INC.

         RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
        CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                  DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

              RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




however it allows for even more efficient use of the existing system facilities to meet the
increased system demand.

As requested, also appended to this response (Attachment 6) are the figures and
schedules for the Revised Base +45 scenario showing system costs and indicative
customer rate impacts similar to those that were provided in response to BCUC IR 41.7.

Further to TGVI’s response to MEM IR1-28.8, these indicative burnertip rates and
transport tolls have been produced under two sets of assumptions. In the first case, as
before, the LNG facility is allocated in the same manner as the transmission assets. In
the second case the LNG facility is allocated only to Core customers. These two
assessments were performed for illustrative purposes only, however they demonstrate
that based on current assumptions there is little difference between the two approaches.
Neither of the LNG scenarios assume there are curtailment/peaking gas arrangements
available.

The present value cost of service comparison of the different portfolios is provided in the
following response to BCUC IR48.3. These results support TGVI’s conclusion that the
LNG portfolio continues to be the least cost solution to meeting future requirements on
TGVI’s system.

In preparing these revised capital schedules and cost summaries and customer impact
schedules TGVI has updated the following underlying assumptions:

Updated Operational Assumptions
   • Performance of the existing C50 compressor units at VI Coquitlam have been
      upgraded as described in BC Hydro IR3.0(a).
   • Retention of the Texada compressor occurs in late 2005
   • Operating costs for the LNG Facility have been increased by $230,000 per year
      to correct the previous omission of certain costs
   • Cost associated with curtailment/peaking gas arrangements are based on the
      parameters provided in the BC Hydro IR2-50.0 to TGVI. ($500k annual demand
      charge and $15/GJ commodity charge indexed to CPI).
   • Fuel associated with third party storage services is now applied against
      mitigating revenues and is no longer included as part of the transportation fuel
      differential

Updated Financial and Economic Assumptions
   • Revised depreciation rates in accordance with TGVI’s response to BCUC IR47.3
   • Cost of service summaries provided in calendar year format to allow consistency
      with the schedules showing system costs and customer impacts
   • Large Corporate Tax calculation has been changed to reduce to 0% by 2008 as
      per the announced federal tax policies



                                        -4-
                     TERASEN GAS (VANCOUVER ISLAND) INC.

         RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
        CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                  DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

               RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




   •   Underlying oil and gas price forecasts are based on the October 2004 GLJA
       forecast.
   •   Long-term CDN/US$ exchange rate of $0.75 is used for determining future oil
       and gas costs and mitigating revenues.
   •   Electricity rates used for the “soft cap” mechanism are based on a 6% increase
       over 2003 rates to 2005 and annual increases of ½ CPI thereafter.


The following attachments include the requested capital information and financial
schedules.

Attachment 1   Discussion of Curtailment in Portfolio Development
Attachment 2   Comparison of LNG Portfolios for Revised Base +45 Scenarios
Attachment 3   Capital Plans for Revised Demand Scenarios
Attachment 4   Expanded Cost of Service Summaries
Attachment 5   Gas Supply and LNG Mitigating Revenue Summary
Attachment 6   System Costs and Customer Impacts




                                       -5-
            TERASEN GAS (VANCOUVER ISLAND) INC.

 RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
          DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

     RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




                                                          BCUC IR 48.2


                                                  ATTACHMENT 1

Discussion of Curtailment in Portfolio Development




                            -6-
                             TERASEN GAS (VANCOUVER ISLAND) INC.

                 RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
                CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                          DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                     RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




Attachment 1 - Consideration of Curtailment in Portfolio Development

The PC&C portfolios used in the Resource Plan and CPCN application were developed
according to TGVI’s planning criteria (described in BCUC IR 35.1) as well as the assumption
that after 2007, curtailment would be provided by BC Hydro and the VIGJV based on their
existing fuel switching capability (described in BCUC IR 34.1). In summary, the capital
requirements shown in PC&C portfolios are identified based on the requirements to:
    • maintain sufficient pipeline capacity to serve the Normal Peak Day (-3°C) with out
        reliance on curtailment.
    • maintain sufficient pipeline capacity to meet the Design Day (-10°C) within the limits of
        available curtailment.

Both the Normal Peak Day and Design Day requirements were met with the full capacity of the
system under steady-state conditions with no additional capacity margin to account for
prolonged equipment failure or other upset conditions. For capacity planning TGVI assumed
that the limits of available curtailment were based on the then existing fuel switching capability
of BC Hydro and VIGJV:
     • 84 TJ from the VIGJV with maximum daily capacity of 17 TJ/d
     • 97.5 TJ from BC Hydro at ICP with a daily maximum capacity of 45 TJ/d.

To minimize capital requirements for the PC&C portfolios this curtailment is assumed to be
optimally dispatched to meet the requirements of the design year profile within the limits of the
planning criteria described above. In other words, the curtailment is used to levelise the demand
net of curtailment as much as possible to minimize capital requirements. The dispatch
assumption used to develop PC&C portfolios for the Resource plan and CPCN Application is
shown in response to BCUC IR 35.4. While this approach relies on the assumption of perfect
information (i.e. that curtailment would be perfectly dispatched despite uncertainties of daily
weather), the problem is minimized in this case because curtailment use is limited to colder than
normal weather and therefore dispatched infrequently.

In response to BCUC IR 35.5, TGVI provided an alternative dispatch profile where the same
curtailment volume was used to levelise demand net of curtailment without restricting reliance
on curtailment to colder than normal weather. While the result showed the potential to reduce
cost, the accuracy of dispatch required to achieve these savings would be difficult to realize in
practice. This case would require curtailment up to 12 days in a normal year of amounts less
than the normal daily forecast variation.

Unlike LNG send-out which can be started at any time with short notice, varied continuously,
and stopped at any time, curtailment must be arranged in advance. For example, under the
existing Peaking Agreement with BC Hydro curtailment would normally be nominated 24 hours
in advance. There is provision in this agreement for curtailment on short hours notice but this
service is encumbered with restrictions on duration, frequency of use, and costs penalties
($10,000 per call and $900/hr, see BCUC IR 34.12). Note that while the agreement allows 2
hours notice, 4 hours appears to be required for fuel switching at ICP (see TGVI response to BC



                                                -7-
                              TERASEN GAS (VANCOUVER ISLAND) INC.

                 RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
                CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                          DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                      RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




Hydro IR 22a). Regardless of the notice period, unlike LNG send-out, once the nomination is
made it cannot be revoked, reduced, or increased and the associated cost is sunk.

Nominations for curtailment are made by TGVI, in advance, based on weather forecasts. The
normal variation of these forecasts from actual temperatures is approximately +/- 3°C which
translates to +/- 9 TJ/d of demand. This is an important consideration when relying on
curtailment to meet capacity requirements. Without perfect information it is prudent for the
operator to nominate curtailment in excess of the forecast requirement in order to avoid
penalties or suffer outages due to lack of capacity. It is impractical to expect that curtailment can
be nominated with greater precision. To address this problem in cases that rely on extensive
use of curtailment a margin or reserve of either pipeline capacity or curtailment volume would be
required to account for forecast variation and to ensure reliability.

As a result of the new arrangement with the VIGJV, the base forecast for VIGJV demand has
been reduced to 12.5 TJ/d and no peaking gas supply is expected to be available. While the
previous base forecast was 33.6 TJ/d up to 50% of this volume was curtailable during colder
than normal weather. For the PC&C portfolios the effect of the new agreement is only a 4.3 TJ/d
reduction in firm demand after curtailment and total curtailment is now limited to that available
from ICP (33.6 x 50% – 12.5 = 4.3).

As requested, in responding to this IR TGVI has assumed that ICP has fuel switching capability,
and can provide up to 240 hours of curtailment in a design year based on the information
provided in TGVI’s response to BCUC IR 34.13. While periods of distillate use are permitted
under BC Hydro’s EPA with Calpine for up to 240 hours in a 12 month period TGVI believes that
the curtailment available from this facility may be less due to:
    • BC Hydro’s requirement for dependable capacity beginning 2007
    • The limitation of only 53 hours of on-site distillate storage
    • The process and time required to re-fill the on-site storage
    • ICP cannot run on distillate and natural gas simultaneously
    • Other issues described in response to IRs 51.2

In addition to the PC&C results based on 240 hours, results are also provided for PC&C
assuming 53 hours of curtailment from ICP. While previous portfolio comparisons relied on the
assumption that peaking gas would be available to TGVI for $5.42 plus the Huntingdon index
with no demand charge this assumption has been revised to reflect the terms provided by BC
Hydro in their IR 50. The pricing is now based on a demand charge of $0.5 million per year and
a commodity charge of $15 per GJ indexed at CPI. It should be noted that although this pricing
has been included in BC Hydro IR 50 to TGVI, and used in the development of this response,
BC Hydro has not presented TGVI with a firm commitment to provide curtailment at this price.

As in all previous cases the PC&C(240 hrs) portfolio has been modeled based on the
assumption of perfect nomination of curtailment to meet design winter requirements. Since this
case relies on extensive use of curtailment a margin of pipeline capacity or curtailment volume
would be required to account for forecast variation and to ensure reliability. If in practice a 9


                                                -8-
                             TERASEN GAS (VANCOUVER ISLAND) INC.

                RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
               CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                         DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                     RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




TJ/d margin of pipeline capacity was maintained to account for forecast variation and to ensure
reliability the effect would be to advance all capital after 2007 by approximately 3 years to
maintain that 9 TJ/d reserve margin. As a result PV of incremental cost of service would be $15
million greater than that shown in Table IR 48.3c.

Increased reliance on curtailment means that curtailment would be used more frequently and
that the probability and extent of multiple day events would also increase. For example, in 2017
for the PC&C(240 hrs) portfolio curtailment would be required for 0°C and colder weather.
Based on the design year profile this would be expected to occur on 18 days. If it is not possible
to operate ICP to meet this requirement the portfolio should be modified to reflect what can be
achieved. To ensure that the benefit of capital deferral is realized a long-term commitment to
this level of curtailment would be required. BC Hydro has not presented TGVI with any firm
commitment to provide this level of curtailment.




                                               -9-
            TERASEN GAS (VANCOUVER ISLAND) INC.

 RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
          DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

     RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




                                                          BCUC IR 48.2


                                                  ATTACHMENT 2

Comparison of LNG Portfolios for Revised Base +45
                                         Forecast




                           - 10 -
                                                                             TERASEN GAS (VANCOUVER ISLAND) INC.

                                                            RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
                                                           CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                                                                     DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                                                                  RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




Attachment 2
FIGURE BCUC IR 48.2a: Impact of Revised Base Case on Facility Additions
                                          160

                                          140             Secret Cove                                              Firm Transport Load
                                                                                                                   JV          33.6 TJ/d
 Capital Expenditures 2004 $ (Millions)




                                          120              Coquitlam
                                                          Squamish
                                          100            Compressor
                                                                                                                   ICP         45 TJ/d

                                           80                                                                      CFT         45 TJ/d

                                           60
                                                                         Original Base + 45
                                           40            Mount Hayes
                                                            LNG                                      25 km    Dunsmuir
                                                Texada                                               Loop    Compressor12 km
                                           20
                                                                                                                       Loop
                                            0
                                             06

                                             07




                                             10

                                             11

                                             12




                                             15

                                             16

                                             17




                                             20

                                             21

                                             22




                                             25

                                             26
                                             05




                                             08

                                             09




                                             13

                                             14




                                             18

                                             19




                                             23

                                             24
                                          160
                                           20

                                           20




                                           20

                                           20

                                           20




                                           20

                                           20

                                           20




                                           20

                                           20

                                           20




                                           20

                                           20
                                           20




                                           20

                                           20




                                           20

                                           20




                                           20

                                           20




                                           20

                                           20
                                          140
                                                                                                                   Firm Transport Load
                                                                                                                   JV           12.5 TJ/d
                                          120
                                                          Squamish                                                 ICP          45 TJ/d
                                          100            Compressor
                                                                                                                   CFT          45 TJ/d
                                           80
                                                         Mount               Revised Base + 45
                                           60            Hayes
                                                          LNG
                                           40
                                                                              Secret Cove
                                           20   Texada           Coquitlam

                                            0
                                             07

                                             08




                                             11

                                             12




                                             15

                                             16



                                             18

                                             19

                                             20



                                             22

                                             23




                                             26
                                             05




                                             09




                                             13




                                             17




                                             24
                                             06




                                             10




                                             14




                                             21




                                             25
                                           20

                                           20




                                           20

                                           20




                                           20

                                           20



                                           20

                                           20

                                           20



                                           20

                                           20




                                           20
                                           20




                                           20




                                           20




                                           20




                                           20
                                           20




                                           20




                                           20




                                           20




                                           20                                               - 11 -
                                                                                          TERASEN GAS (VANCOUVER ISLAND) INC.

                                                                          RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
                                                                         CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                                                                                   DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                                                                                RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




                                         FIGURE BCUC IR 48.2b: Impact of Revised Base Case on TGVI Usage of LNG Facility


                                                                       TGVI Storage Requirement
                                  1000
TGVI Storage Required (mmcf)




                                   900
                                   800
                                   700        Original Base +45
                                   600
                                   500
                                   400
                                   300
                                   200
                                   100
                                     0
                                         2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026



                                                                       TGVI Storage Requirement
                                  1000
   TGVI Storage Required (mmcf)




                                   900
                                   800
                                   700
                                   600                                     Revised Base +45
                                   500
                                   400
                                   300
                                   200
                                   100
                                     0
                                         2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026




                                                                                                                - 12 -
            TERASEN GAS (VANCOUVER ISLAND) INC.

 RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
          DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

     RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




                                                          BCUC IR 48.2


                                                  ATTACHMENT 3

         Capital Plans for Revised Demand Scenarios




                           - 13 -
                                                                 TERASEN GAS (VANCOUVER ISLAND) INC.

                                             RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
                                            CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                                                      DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                                                     RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




FIGURE BCUC IR 48.2c: Revised Base +45 Forecast - Incremental Facility Requirements
Year                   LNG Storage                                      PC                                    PC&C (53 hrs)                              PC&C (240 hrs)
            Required TGVI     Forecast System           Required TGVI        Forecast System        Required TGVI    Forecast System           Required TGVI     Forecast System
              Facilities       Direct   Fuel              Facilities          Direct   Fuel           Facilities        Direct  Fuel             Facilities       Direct   Fuel
                              (millions                                      (millions                                (millions                                  (millions
                               2004$)   (%)                                   2004$)   (%)                             2004$)   (%)                               2004$)   (%)
2004
2005     V4                            15            V4                           15             V4                          15             V4                           15
2006     CFT MS                         2            CFT MS                        2             CFT MS                       2             CFT MS                        2
2007     LNG, V2, spares              121    4.6%    V1U4, V2, V3b, V5,          117    4.2%     V1U4, V2, V3b, V5,          82      4.4%   V1U4, V2, V3b, V5,           82    4.3%
                                                     loop 25km d/s WS,                           spares                                     spares
                                                     loop 12km d/s V2,
                                                     spares
2008                                         4.6%    loop 27km d/s V3b            25    4.2%                                         4.4%                                      4.3%
2009                                         4.6%    loop 40km d/s WF             36    4.1%                                         4.4%                                      4.4%
2010                                         4.6%                                       4.1%                                         4.4%                                      4.4%
2011     V1U4                          15    4.7%                                       4.1%     loop 25km d/s WS            23      4.4%                                      4.4%
2012                                         4.7%    V1U5                         15    4.1%                                         4.4%                                      4.5%
2013     V3b                           20    4.7%                                       4.1%     loop 12km d/s V2            12      4.4%                                      4.5%
2014                                         4.7%                                       4.1%                                         4.4%                                      4.6%
2015                                         4.7%                                       4.0%                                         4.4%                                      4.6%
2016                                         4.7%                                       4.0%                                         4.4%                                      4.6%
2017                                         4.7%    loop 19km d/s PM             17    4.0%                                         4.5%                                      4.7%
2018                                         4.8%                                       4.0%     loop 27km d/s V3b           17      4.4%   loop 25km d/s WS             23    4.6%
2019                                         4.8%                                       4.0%                                         4.4%                                      4.6%
2020                                         4.8%                                       4.0%     loop 40km d/s WF            36      4.4%   loop 12km d/s V2             12    4.5%
2021                                         4.8%                                       4.0%                                         4.4%                                      4.5%
2022                                         4.9%                                       4.0%     V1U5                        15      4.3%                                      4.4%
2023                                         4.9%    loop 10km d/s V4             12    4.0%                                         4.3%   loop 27km d/s V3b            25    4.4%
2024                                         4.9%    loop 7km d/s V5,             16    4.0%     loop 7km d/s V5              7      4.3%   loop 7km d/s V5               7    4.3%
                                                     loop 10km d/s WS
2025                                         4.9%                                       4.0%                                         4.3%   loop 40km d/s WF             36    4.3%
2026                                         5.0%                                       4.0%                                         4.3%                                      4.2%

Legend
         CFT MS                CFT Meter Station                                                                      V1U5                                         V1U5
                                                                                                                                  5th unit to VI - Coquitlam Compressor Station
         d/s                   'downstream of'                                                                        V2          V2 - Squamish Compressor Station V2
         km                    'kilometre'                                                                            V3b                                          V3b
                                                                                                                                  V3b - Secret Cove Compressor Station
         LNG                   Mt Hayes LNG Storage Facility                                                          V4          V4 - Texada Compressor StationV4 (retention and upgrades)
         PM                    'Port Mellon'                                                                          V5          V5 - Dunsmuir Compressor Station V5
         spares                Spare Compressor Engines                                                               WF          'Woodfibre'                      WF
         V1U4                  4th unit to VI - Coquitlam Compressor Station                                          WS          'Watershed'                      WS
Notes
        System fuel includes compressor fuel plus 0.5% for meter station fuel, 1% for UAF




                                                                                               - 14 -
                                                        TERASEN GAS (VANCOUVER ISLAND) INC.

                                    RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
                                   CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                                             DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                                           RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




FIGURE BCUC IR 48.2d: Revised Base +0 Forecast - Incremental Facility Requirements
Year               LNG Storage                             PC                                PC&C(53 hrs)                            PC&C(240 hrs)
              Required TGVI   Forecast         Required TGVI    Forecast          Required TGVI      Forecast Direct             Required TGVI  Forecast
                Facilities      Direct           Facilities       Direct            Facilities              Cost                   Facilities     Direct
                               2004$)                            2004$)                              (millions 2004$)                            2004$)
2004
2005     V4                         15    V4                           15    V4                                    15       V4                        15
2006
2007     LNG, spares                99    V2, V1U4, spares             42    spares                                     5   spares                     5
2008                                      V3b                          20
2009
2010                                                                         V2                                    22
2011
2012
2013
2014
2015
2016                                                                         V1U4                                  15       V2                        22
2017
2018                                      loop 25km d/s WS             23    V3b                                   20
2019                                      V5                           20
2020                                      loop 12km d/s V2             12
2021
2022                                                                         V5                                    20       V1U4, V5                  35
2023
2024
2025                                      loop 40km d/s WF,            61                                                   V3b                       20
                                          loop 27km d/s V3b
2026

Legend
         CFT MS              CFT Meter Station                                                      V1U5      5th unit to VI - Coquitlam Compressor Station
         d/s                 'downstream of'                                                        V2        V2 - Squamish Compressor Station
         km                  'kilometre'                                                            V3b       V3b - Secret Cove Compressor Station
         LNG                 Mt Hayes LNG Storage Facility                                          V4        V4 - Texada Compressor Station (retention and upgrades)
         PM                  'Port Mellon'                                                          V5        V5 - Dunsmuir Compressor Station
         spares              Spare Compressor Engines                                               WF        'Woodfibre'
         V1U4                4th unit to VI - Coquitlam Compressor Station                          WS        'Watershed'




                                                                                  - 15 -
            TERASEN GAS (VANCOUVER ISLAND) INC.

 RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
          DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

     RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




                                                          BCUC IR 48.2


                                                  ATTACHMENT 4

                   Expanded Cost of Service Summaries




                           - 16 -
                                                                           TERASEN GAS (VANCOUVER ISLAND) INC.

                                                  RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
                                                 CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                                                           DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                                                            RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




ATTACHMENT 4
Revised Base + 45 Forecast
LNG Storage Portfolio

Cost of Service Summary for Incremental TGVI Facilities
(Million Cdn Dollars)                                                            Calendar Year
                                              2005     2006       2007    2008   2009 2010 2011       2012 2013     2014   2015   2016   2017 2018     2019 2020     2021   2022 2023     2024 2025     2026   2027
                                                 1        2          3       4       5     6   7         8    9       10     11     12     13   14       15   16       17     18   19       20   21       22     23

  Operating Expenses (excl Fuel)                0.0        0.0     1.0     2.5    2.5    2.6    2.6    3.1    3.2    4.0    4.1    4.1    4.2    4.3    4.4    4.5    4.6    4.7    4.8    4.8    4.9    5.0    5.1
  Other Taxes                                   0.0        0.0     0.0     0.8    0.7    0.7    0.7    0.8    0.8    0.9    0.9    0.9    0.9    1.0    1.0    1.0    1.0    1.0    1.1    1.1    1.1    1.1    1.1
  Depreciation                                  0.0        0.5     0.6     4.6    4.6    4.6    4.6    5.2    5.2    6.1    6.1    6.1    6.1    6.1    6.1    6.1    6.1    6.2    6.2    6.2    6.2    6.2    6.2
  Return on Rate Base                           0.0        1.1     1.3    11.3   11.0   10.7   10.4   11.3   10.9   12.3   11.8   11.4   11.0   10.5   10.1    9.7    9.2    8.8    8.4    7.9    7.5    7.1    6.6
  Income Taxes                                 (0.7)      (0.7)   (2.7)    0.2    0.7    1.1    0.7    0.9    0.5    1.0    1.6    2.1    2.5    2.8    3.0    3.2    3.3    3.4    3.5    3.5    3.5    3.5    3.5
  Incremental Wheeling Cost                                        0.7     0.6    0.7    0.8    0.8    0.9    0.9    1.0    1.1    1.1    1.2    1.3    1.4    1.4    1.5    1.6    1.7    1.8    1.9    2.0    2.1

  Total Incremental Cost of Service            (0.7)      1.0      0.9    19.9   20.2   20.4   19.8   22.2   21.5   25.2   25.5   25.8   25.9   26.0   26.0   25.9   25.8   25.7   25.5   25.3   25.1   24.9   24.7

  Present Value Incremental Cost@6.1%          (0.6)      0.9      0.7    15.7   15.0   14.3   13.1   13.8   12.6   13.9   13.3   12.7   12.0   11.3   10.7   10.0    9.4    8.8    8.3    7.7    7.2    6.8    6.3
  Present Value Incremental Cost@10.0%         (0.6)      0.8      0.7    13.6   12.5   11.5   10.2   10.3    9.1    9.7    9.0    8.2    7.5    6.8    6.2    5.6    5.1    4.6    4.2    3.8    3.4    3.1    2.8

  Present Value Total (2004-26)                6.1% 10.0%
  Total                                         223  148



Rate Base Summary for Incremental TGVI Facilities
(Million Cdn Dollars)                                                                        Calendar Year
                                              2005     2006       2007    2008   2009   2010 2011 2012 2013         2014   2015   2016   2017 2018     2019 2020     2021   2022 2023     2024 2025     2026   2027
                                                 1        2          3       4      5      6     7     8   9          10     11     12     13   14       15   16       17     18   19       20   21       22     23

  Incremental Capital Additions                   0        16       2      135      0     0      0     17       0    24       0     0      0      0      0      0      0      0      0      0      0      0       0

  Gas Plant In Service                            0        16       18     153    154   154    154    172    172     196    196   197    197    197    198    198     199   199    199    200    200     201    201
  Accumulated Depreciation                        0         1        1       6     10    15     19     25     30      36     42    48     54     60     66     72      79    85     91     97    103     109    116

  Working Capital                                 0         0       0        0      0     0      0      0       0     0       0     0      0      0      0      0      0      0      0      0      0      0       0

  Average Plant in Service                        0        15       17     148    143   139    135    147    142     160    154   149    143    137    132    126     120   114    108    103     97      91     85




                                                                                                       - 17 -
                                                                           TERASEN GAS (VANCOUVER ISLAND) INC.

                                                  RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
                                                 CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                                                           DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                                                            RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2



Revised Base + 45 Forecast
Pipe & Compression Portfolio

Cost of Service Summary for Incremental TGVI Facilities
(Million Cdn Dollars)                                                            Calendar Year
                                              2005     2006       2007    2008   2009 2010 2011       2012 2013      2014   2015   2016   2017 2018     2019 2020     2021   2022 2023     2024 2025     2026   2027
                                                 1        2          3       4       5     6   7         8    9        10     11     12     13   14       15   16       17     18   19       20   21       22     23

  Operating Expenses (excl Fuel)                0.0        0.0     0.4     2.3   2.4   2.5  2.6        2.6    3.1     3.2    3.3    3.3    3.4    3.5    3.5    3.6    3.7    3.8    3.8    3.9    4.0    4.1    4.2
  Other Taxes                                   0.0        0.0     0.0     0.5   0.5   0.7  0.7        0.8    0.8     0.8    0.9    0.9    0.9    1.0    1.0    1.1    1.1    1.1    1.1    1.2    1.3    1.4    1.4
  Depreciation                                  0.0        0.5     0.6     4.4   5.0   5.8  5.8        5.8    6.5     6.5    6.5    6.6    6.6    7.1    7.2    7.2    7.2    7.3    7.3    7.7    8.2    8.3    8.3
  Return on Rate Base                           0.0        1.1     1.3    10.5 12.2 14.9 14.5         14.2   15.1    14.7   14.3   13.9   13.5   14.9   14.4   14.0   13.6   13.1   12.7   13.4   14.8   14.3   13.8
  Income Taxes                                 (0.7)      (0.7)   (4.5)   (3.7) (2.3) (0.4) 0.5        0.3    0.8     1.6    2.2    2.6    2.8    3.5    3.7    3.9    4.1    4.2    4.1    4.2    4.7    4.7    4.7
  Incremental Wheeling Cost                                        0.9     2.3   2.4   2.6  2.7        2.8    2.9     3.0    3.1    3.3    3.4    3.5    3.6    3.8    3.9    4.1    4.2    4.4    4.5    4.7    4.8

  Total Incremental Cost of Service            (0.7)      1.0     (1.4)   16.3   20.3   26.0   26.8   26.5   29.3    29.8   30.2   30.6   30.5   33.5   33.6   33.6   33.6   33.5   33.3   34.7   37.5   37.4   37.3

  Present Value Incremental Cost@6.1%          (0.6)      0.9     (1.1)   12.9   15.1   18.2   17.7   16.5   17.2    16.5   15.8   15.0   14.1   14.6   13.8   13.0   12.2   11.5   10.8   10.6   10.8   10.1    9.5
  Present Value Incremental Cost@10.0%         (0.6)      0.8     (1.0)   11.2   12.6   14.7   13.8   12.4   12.4    11.5   10.6    9.7    8.8    8.8    8.0    7.3    6.6    6.0    5.4    5.2    5.1    4.6    4.2

  Present Value Total (2004-26)                6.1% 10.0%
  Total                                         275  178



Rate Base Summary for Incremental TGVI Facilities
(Million Cdn Dollars)                                                                        Calendar Year
                                              2005     2006       2007    2008   2009   2010 2011 2012 2013          2014   2015   2016   2017 2018     2019 2020     2021   2022 2023     2024 2025     2026   2027
                                                 1        2          3       4      5      6     7     8   9           10     11     12     13   14       15   16       17     18   19       20   21       22     23

  Incremental Capital Additions                   0        16       2      127     28    42      1      1       18     1       1     1      1     26      1      1      1      1      2     17     27      2       2

  Gas Plant In Service                            0        16       18     145    173   215    216    217    236      237    238   239    240    266    267    269     270   272    273    290    317     319    321
  Accumulated Depreciation                        0         1        1       5     10    16     22     28     34       41     47    54     61     68     75     82      89    97    104    112    120     128    136

  Working Capital                                 0         0       0        0      0     0      0      0        0     0       0     0      0      0      0      0      0      0      0      0      0      0       0

  Average Plant in Service                        0        15       17     140    163   199    194    189    201      196    190   185    180    198    192    187     181   175    169    178    197     191    184




                                                                                                       - 18 -
                                                                            TERASEN GAS (VANCOUVER ISLAND) INC.

                                                  RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
                                                 CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                                                           DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                                                            RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2



Revised Base + 45 Forecast
Pipe & Compression & Curtailment (53 Hours) Portfolio

Cost of Service Summary for Incremental TGVI Facilities
(Million Cdn Dollars)                                                              Calendar Year
                                              2005      2006      2007    2008     2009 2010 2011           2012 2013       2014   2015   2016   2017 2018     2019 2020     2021   2022 2023     2024 2025     2026   2027
                                                 1         2         3       4         5     6   7             8    9         10     11     12     13   14       15   16       17     18   19       20   21       22     23

  Operating Expenses (excl Fuel)                0.0        0.0     0.4      2.3      2.3     2.4     2.4     2.5      2.6    2.6    2.7    2.7    2.8    2.8    2.9    3.0    3.1    3.2    3.8    3.9    4.0    4.1    4.1
  Other Taxes                                   0.0        0.0     0.0      0.2      0.2     0.3     0.3     0.4      0.4    0.5    0.5    0.5    0.5    0.5    0.7    0.7    0.9    0.9    1.0    1.0    1.1    1.1    1.1
  Depreciation                                  0.0        0.5     0.6      3.6      3.6     3.7     3.7     4.2      4.2    4.6    4.6    4.6    4.7    4.7    5.4    5.4    6.4    6.5    7.3    7.3    7.5    7.6    7.6
  Return on Rate Base                           0.0        1.1     1.3      7.6      7.4     7.1     6.9     8.6      8.4    9.3    9.0    8.7    8.4    8.1   10.3   10.0   13.4   13.0   14.1   13.7   14.1   13.6   13.2
  Income Taxes                                 (0.7)      (0.7)   (4.1)    (3.8)    (2.4)   (1.4)   (0.8)    0.4      0.7    1.5    1.8    2.1    2.3    2.1    2.8    2.4    3.4    2.5    2.5    2.8    3.3    3.5    3.7
  Incremental Wheeling Cost                                        0.1      1.4      1.5     1.6     1.8     1.9      2.0    2.1    2.2    2.3    2.4    2.5    2.6    2.7    2.9    3.0    3.1    3.3    3.4    3.5    3.7

  Total Incremental Cost of Service            (0.7)      1.0     (1.8)   11.4     12.7     13.7    14.2    18.0   18.3     20.5   20.7   20.9   21.0   20.8   24.7   24.2   30.2   29.1   31.8   31.9   33.4   33.5   33.5

  Present Value Incremental Cost@6.1%          (0.6)      0.9     (1.5)    9.0      9.4      9.6     9.4    11.2   10.7     11.3   10.8   10.3    9.7    9.0   10.2    9.4   11.0   10.0   10.3    9.8    9.6    9.1    8.6
  Present Value Incremental Cost@10.0%         (0.6)      0.8     (1.4)    7.8      7.9      7.7     7.3     8.4    7.7      7.9    7.3    6.7    6.1    5.5    5.9    5.3    6.0    5.2    5.2    4.7    4.5    4.1    3.7

  Present Value Total (2004-26)                6.1% 10.0%
  Total                                         197  124



Rate Base Summary for Incremental TGVI Facilities
(Million Cdn Dollars)                                                              Calendar Year
                                              2004      2005      2006    2007     2008 2009 2010           2011 2012       2013   2014   2015   2016 2017     2018 2019     2020   2021 2022     2023 2024     2025   2026
                                                 1         2         3       4         5     6   7             8    9         10     11     12     13   14       15   16       17     18   19       20   21       22     23

  Incremental Capital                             0        16       2       88        0       1       1      27        1     17       1     1      1      1     34      1     52      1     22      1     12      2       2

  Gas Plant In Service                            0        16       18     106      107     107     108     135    136       152    153   154    155    156    190    191     243   244    267    268    281     282    284
  Accumulated Depreciation                        0         1        1       5        8      12      16      20     24        29     33    38     43     47     53     58      65    71     78     86     93     101    108

  Working Capital                                 0         0       0        0        0       0       0       0        0      0       0     0      0      0      0      0      0      0      0      0      0      0       0

  Average Plant in Service                        0        15       17     101       98      95      92     115    111       124    120   116    112    108    137    133     178   173    189    183    187     181    175




                                                                                                             - 19 -
                                                                            TERASEN GAS (VANCOUVER ISLAND) INC.

                                                  RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
                                                 CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                                                           DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                                                            RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2



Revised Base + 45 Forecast
Pipe & Compression & Curtailment (240 Hours) Portfolio

Cost of Service Summary for Incremental TGVI Facilities
(Million Cdn Dollars)                                                              Calendar Year
                                              2005     2006       2007    2008     2009 2010 2011           2012 2013       2014   2015   2016   2017 2018     2019 2020     2021   2022 2023     2024 2025     2026   2027
                                                 1        2          3       4         5     6   7             8    9         10     11     12     13   14       15   16       17     18   19       20   21       22     23

  Operating Expenses (excl Fuel)                0.0        0.0     0.4      2.3      2.3     2.4     2.4     2.5      2.5    2.6    2.6    2.7    2.7    2.8    2.9    2.9    3.0    3.1    3.1    3.3    3.3    3.5    3.5
  Other Taxes                                   0.0        0.0     0.0      0.3      0.2     0.3     0.3     0.3      0.3    0.3    0.3    0.3    0.3    0.3    0.4    0.4    0.5    0.5    0.5    0.7    0.8    1.0    1.1
  Depreciation                                  0.0        0.5     0.6      3.6      3.6     3.7     3.7     3.7      3.7    3.7    3.8    3.8    3.8    3.8    4.4    4.5    4.9    4.9    4.9    5.7    5.9    7.0    7.1
  Return on Rate Base                           0.0        1.1     1.3      7.6      7.4     7.1     6.9     6.7      6.4    6.2    5.9    5.7    5.5    5.2    7.2    7.0    8.0    7.7    7.4    9.9   10.3   14.1   13.6
  Income Taxes                                 (0.7)      (0.7)   (4.1)    (3.8)    (2.4)   (1.4)   (0.5)    0.1      0.7    1.1    1.4    1.7    1.9    1.7    2.4    2.3    2.7    2.7    2.4    3.0    2.6    3.7    3.7
  Incremental Wheeling Cost                                        0.7      1.0      1.1     1.2     1.3     1.4      1.5    1.6    1.7    1.8    1.9    2.1    2.2    2.3    2.4    2.5    2.7    2.8    3.0    3.1    3.3

  Total Incremental Cost of Service            (0.7)      1.0     (1.2)   11.1     12.3     13.3    14.1    14.7   15.1     15.5   15.7   15.9   16.1   15.9   19.5   19.4   21.5   21.5   21.1   25.3   25.9   32.4   32.3

  Present Value Incremental Cost@6.1%          (0.6)      0.9     (1.0)    8.7      9.1      9.3     9.3     9.1      8.9    8.5    8.2    7.8    7.4    6.9    8.0    7.5    7.9    7.4    6.8    7.7    7.5    8.8    8.3
  Present Value Incremental Cost@10.0%         (0.6)      0.8     (0.9)    7.6      7.6      7.5     7.2     6.8      6.4    6.0    5.5    5.1    4.7    4.2    4.7    4.2    4.3    3.9    3.5    3.8    3.5    4.0    3.6

  Present Value Total (2004-26)                6.1% 10.0%
  Total                                         162  103



Rate Base Summary for Incremental TGVI Facilities
(Million Cdn Dollars)                                                                            Calendar Year
                                              2005     2006       2007    2008     2009     2010 2011 2012 2013             2014   2015   2016   2017 2018     2019 2020     2021   2022 2023     2024 2025     2026   2027
                                                 1        2          3       4        5        6     7     8   9              10     11     12     13   14       15   16       17     18   19       20   21       22     23

  Incremental Capital Additions                   0        16       2       88        0       1       1       1        1      1       1     1      1      1     31      1     19      1      1     38     12      57      1

  Gas Plant In Service                            0        16       18     106      107     107     108     108    109       109    110   110    111    111    143    144     163   164    165    202    214     272    273
  Accumulated Depreciation                        0         1        1       5        8      12      16      19     23        27     31    34     38     42     46     51      56    61     66     71     77      84     91

  Working Capital                                 0         0       0        0        0       0       0       0        0      0       0     0      0      0      0      0      0      0      0      0      0      0       0

  Average Plant in Service                        0        15       17     101       98      95      92      89       86     82      79    76     73     69     96     93     107   103     99    131    137     187    182




                                                                                                             - 20 -
            TERASEN GAS (VANCOUVER ISLAND) INC.

 RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
          DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

     RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




                                                          BCUC IR 48.2


                                                  ATTACHMENT 5

 Gas Supply and LNG Mitigating Revenue Summary




                           - 21 -
                              TERASEN GAS (VANCOUVER ISLAND) INC.

                RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
               CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                         DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                       RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2



Attachment 5
Terasen Gas (Vancouver Island)
Vancouver Island Supply Alternatives

LNG Mitigation Revenues
(nominal Cdn$ millions)

Revised Base + 45

              TGVI Reserved          Terasen Gas                           Present     Present
                 Capacity           Storage Service                          Value       Value
Calendar    Sendout Capacity      Sendout Capacity       Value                          10.0%
Year         (TJ/d)      (TJ)      (TJ/d)      (TJ)    ($Million)   6.1% ($Million)   ($Million)


     2005                                                     0.0              0.0         0.0
     2006                                                     0.0              0.0         0.0
     2007         37        417         0         0           0.0              0.0         0.0
     2008         52        667        41       247           2.7              2.1         1.8
     2009         55        814        42       251           2.8              2.0         1.7
     2010         59        962        19       112           1.2              0.9         0.7
     2011         58        954        14        86           1.0              0.6         0.5
     2012         59      1,005         4        22           0.2              0.1         0.1
     2013         40        374        55       555           4.1              2.4         1.8
     2014         36        206        72       718           5.2              2.9         2.0
     2015         39        273        69       690           5.0              2.6         1.8
     2016         42        339        66       661           4.8              2.4         1.5
     2017         44        406        63       633           4.6              2.1         1.3
     2018         47        472        60       514           4.2              1.8         1.1
     2019         50        539        58       456           4.0              1.6         1.0
     2020         53        605        55       427           3.8              1.5         0.8
     2021         56        672        51       390           3.5              1.3         0.7
     2022         59        738        44       324           3.0              1.0         0.5
     2023         61        805        33       211           2.2              0.7         0.4
     2024         64        871        30       180           2.0              0.6         0.3
     2025         67        938        23       135           1.5              0.4         0.2
     2026         70      1,004        12        71           0.8              0.2         0.1
     2027         71      1,021         9        54           0.6              0.2         0.1

PV at January 2005$                                                          27.6         18.4




                                              - 22 -
                                             TERASEN GAS (VANCOUVER ISLAND) INC.

                         RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
                        CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                                  DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                                  RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2



BCUC IR 48.2
Attachment 5
Terasen Gas (Vancouver Island)
Vancouver Island Supply Alternatives

Core Market Gas Supply Costs
(nominal Cdn$ millions)

                                                                   Revised Base +45
Calendar        LNG          PV         PV          Pipe      PV       PV          Pipe      PV    PV         Pipe      PV    PV
  Year       Storage       6.1%        10%   Compression    6.1%     10% Compression       6.1%   10% Compression     6.1%   10%
                                                                            Curtailment                Curtailment
                                                                                53 Hrs                    240 Hrs
  2005            0           0          0            0       0         0            0       0      0           0       0      0
  2006            0           0          0            0       0         0            0       0      0           0       0      0
  2007           90          75         68           92      77        69           94      78     70          93      78     70
  2008           89          70         61           92      72        63           93      73     63          93      73     63
  2009           88          66         55           92      68        57           92      68     57          92      68     57
  2010           90          63         51           95      66        53           94      66     53          94      66     53
  2011           92          61         47           97      64        50           96      64     49          96      64     49
  2012           94          59         44          101      63        47           99      62     46          99      62     46
  2013          101          59         43          104      61        44          103      60     44         102      60     43
  2014          105          58         40          107      59        41          106      59     41         106      58     41
  2015          108          56         38          111      58        39          109      57     38         110      57     38
  2016          112          55         36          116      57        37          114      56     36         114      56     36
  2017          114          53         33          120      55        35          118      54     34         118      55     34
  2018          118          51         31          124      54        33          122      53     32         122      53     32
  2019          122          50         29          129      53        31          126      52     30         127      52     30
  2020          126          49         27          134      52        29          130      50     28         131      51     28
  2021          129          47         26          139      51        27          135      49     27         135      49     27
  2022          134          46         24          144      49        26          139      48     25         140      48     25
  2023          139          45         23          149      48        24          144      47     24         145      47     24
  2024          144          44         21          155      47        23          149      46     22         150      46     22
  2025          148          43         20          159      46        22          154      44     21         155      45     21
  2026          153          42         19          163      44        20          160      43     20         160      43     20
  2027          158          40         18          167      43        19          166      42     19         166      42     19

PV @ 6.1% 2005$           1,131                            1,188                          1,172                      1,174
PV @ 10% 2005$                         752                           788                          780                        781




                                                                   - 23 -
            TERASEN GAS (VANCOUVER ISLAND) INC.

 RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
          DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

     RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




                                                          BCUC IR 48.2


                                                  ATTACHMENT 6

                    System Costs and Customer Impacts




                           - 24 -
                                                         TERASEN GAS (VANCOUVER ISLAND) INC.

                                          RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
                                         CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                                                   DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                                               RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




                 Revised Base + 45 Scenario
                 Net Incremental Cost of Service
            40
                   Note:
                   Net incremental costs equals
                   Incremental Facility and Wheeling costs
                   less Gas Supply differentials
            35
                   less LNG mitigation revenues                                           Pipe &
                                                                                        Compression

            30
Million $




            25

                                                               Pipe,Compression
                                                             & Curtailment (53 HRs)
            20
                                                                                                        Pipe,Compression
                                                                                                      & Curtailment (240 HRs)

            15


                                                                                                                  LNG Storage
            10
                 2008       2010          2012         2014         2016        2018      2020        2022     2024      2026
                                                                        Calendar Year




                                                                           - 25 -
                                                                 TERASEN GAS (VANCOUVER ISLAND) INC.

                                             RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
                                            CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                                                      DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                                                    RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




                                    Demand Scenario - Base +45 LNG (System Wide)
                           $25.00
                                         Residential Customer (RGS)
                                         Allocated Cost $ per GJ


                           $20.00
$ per GJ Delivered




                           $15.00




                           $10.00




                            $5.00
                                                                                                               Average Cost of Gas
                                                                                                               Average Delivery Margin
                                                                                                               Heating Oil Equivalent
                                                                                                               90% Residential Electric
                             $-
                                     2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026




                                    Demand Scenario - Base + 45 LNG (System Wide)
                           $1.40
                                                                             Firm Transportation
                                                                             Allocated Cost $ per GJ/d Capacity

                           $1.20




                           $1.00
Demand Charge $ per GJ/d




                           $0.80




                           $0.60




                           $0.40


                                                                              Allocated Unit Cost / GJ
                           $0.20
                                                                              Allocated Unit Cost x 1.25 R/C


                           $-
                                    2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026




                                                                                         - 26 -
                                                         TERASEN GAS (VANCOUVER ISLAND) INC.

                                        RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
                                       CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                                                 DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                                            RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




     Revised Schedule 48.2 Base + 45, LNG
     Portfolio (System Wide)                    2006          2007       2008            2009       2010       2011       2012       2013       2014       2015

 1   TGVI Annual Revenue Requirement
 2    Cost of Gas net of Royalty Revenue    $ 64,322      $ 52,543 $ 52,414 $ 52,795 $ 55,574 $ 57,131 $ 94,462 $ 100,669 $ 104,815 $ 108,017
 3    Cost of Service                         107,928       111,054   133,871   136,612   139,339   132,045   132,076   133,299   138,072   140,119
 4    LNG Mitigating Revenue                        -              -   (2,680)   (2,753)   (1,225)     (950)     (229)   (4,133)   (5,223)   (5,019)
 5   Total Annual Revenue Requirement       $ 172,249     $ 163,597 $ 183,604 $ 186,654 $ 193,688 $ 188,226 $ 226,309 $ 229,835 $ 237,664 $ 243,117
 6
 7   Allocation of Annual Revenue Requirement (LNG System Wide)
 8   Core Market
 9    Cost of Gas net of Royalty Revenue        $ 64,322 $ 52,543 $ 52,414 $ 52,795 $ 55,574 $ 57,131 $ 94,462 $ 100,669 $ 104,815 $ 108,017
10    Cost of Service                              89,349    90,880    99,446   102,227   105,092    99,565    99,582   100,751   103,910   106,132
11    LNG Mitigating Revenue                            -          -   (1,369)   (1,425)     (642)     (503)     (123)   (2,228)   (2,839)   (2,752)
12   Total Allocated Revenue Requirement        $ 153,670 $ 143,423 $ 150,491 $ 153,597 $ 160,024 $ 156,193 $ 193,921 $ 199,192 $ 205,886 $ 211,397
13
14   Firm Transportation
15    Cost of Service                       $ 12,905      $ 14,837 $ 28,982 $ 28,894 $ 28,713 $ 27,021 $ 26,924 $ 26,949 $ 28,246 $ 28,055
16    LNG Mitigating Revenue                       -              -  (1,095)  (1,106)    (485)    (371)     (88)  (1,576)  (1,969)  (1,870)
17   Total Allocated Revenue Requirement    $ 12,905      $ 14,837 $ 27,887 $ 27,789 $ 28,228 $ 26,650 $ 26,835 $ 25,373 $ 26,277 $ 26,185
18
19   Other Transportation (JV, Squamish)
20    Cost of Service                       $    5,674    $    5,337 $    5,443 $         5,491 $    5,534 $    5,459 $    5,570 $    5,602 $    5,922 $    5,945
21    LNG Mitigating Revenue                         -              -      (217)           (221)       (98)       (76)       (18)      (329)      (414)      (397)
22   Total Allocated Revenue Requirement    $    5,674    $    5,337 $    5,226 $         5,269 $    5,436 $    5,383 $    5,552 $    5,273 $    5,507 $    5,548




                                                                                - 27 -
                                                            TERASEN GAS (VANCOUVER ISLAND) INC.

                                             RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
                                            CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                                                      DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                                                 RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2



     Revised Schedule 48.2 Base + 45, LNG
     Portfolio (System Wide)                         2006       2007         2008            2009       2010       2011         2012         2013       2014       2015

23   Calculation of Allocated Unit Cost (LNG System Wide)
24   Residential Customer (Figure IR41.7 - Base + 0, LNG Portfolio)
25    Allocated Cost of Gas                    $ 24,393 $ 19,943         $ 19,902       $ 20,060 $ 21,134 $ 21,736          $ 35,960     $ 38,364 $ 39,963 $ 41,182
26    Net Allocated Cost of Service              49,713     50,925         54,146         55,677   57,597   55,000            55,195       55,066   56,348   57,647
27   Total Allocated Costs                     $ 74,106 $ 70,868         $ 74,048       $ 75,737 $ 78,731 $ 76,736          $ 91,155     $ 93,429 $ 96,312 $ 98,829
28   Annual Demand                                 4,582      4,736         4,884          5,025    5,156    5,279             5,391        5,499    5,609    5,721
29
30    Allocated Unit Cost of Gas                 $     5.32 $     4.21   $     4.07     $      3.99 $     4.10 $     4.12   $     6.67   $     6.98 $     7.13 $     7.20
31    Allocated Unit Cost of Service                  10.85      10.75        11.09           11.08      11.17      10.42        10.24        10.01      10.05      10.08
32   Total Allocated Unit Cost of Service        $    16.17 $    14.96   $    15.16     $     15.07 $    15.27 $    14.54   $    16.91   $    16.99 $    17.17 $    17.28
33
34   Firm Transportation (Figure IR48.2 - Base + 45, LNG Portfolio)
35   Contract Demand                              38,000    46,667         90,000         90,000   90,000   90,000            90,000       90,000   90,000   90,000
36   Net Allocated Cost of Service             $ 12,905 $ 14,837         $ 27,887       $ 27,789 $ 28,228 $ 26,650          $ 26,835     $ 25,373 $ 26,277 $ 26,185
37   Allocated Unit Cost                       $     0.93 $    0.87      $   0.85       $   0.85 $   0.86 $   0.81          $   0.82     $   0.77 $   0.80 $   0.80




                                                                                    - 28 -
                                                                   TERASEN GAS (VANCOUVER ISLAND) INC.

                                              RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
                                             CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                                                       DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                                                      RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




                                      Demand Scenario - Base + 45 LNG to CDS
                             $25.00

                                          Residential Customer (RGS)
                                          Allocated $ per GJ

                             $20.00
$ per GJ Delivered




                             $15.00




                             $10.00


                                                                                                               Average Cost of Gas
                                                                                                               Average Delivery Margin
                              $5.00                                                                            Heating Oil Equivalent
                                                                                                               90% Residential Electric



                               $-
                                      2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026




                                      Demand Scenario - Base + 45 LNG to CDS
                             $1.40
                                         Firm Transportation
                                         Allocated Cost $ per GJ/d Capacity

                             $1.20




                             $1.00
  Demand Charge $ per GJ/d




                             $0.80




                             $0.60




                             $0.40



                                                                              Allocated Unit Cost / GJ
                             $0.20                                            Allocated Unit Cost x 1.25 R/C




                              $-
                                      2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026




                                                                                                - 29 -
                                                           TERASEN GAS (VANCOUVER ISLAND) INC.

                                            RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
                                           CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                                                     DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                                                RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2



     Schedule 48.2 Base + 45, LNG Portfolio
     (Core)                                         2006          2007          2008        2009       2010       2011       2012       2013       2014       2015

 1   TGVI Annual Revenue Requirement
 2    Cost of Gas net of Royalty Revenue        $ 64,322      $ 52,543      $ 52,414 $ 52,795 $ 55,574 $ 57,131 $ 94,462 $ 100,669 $ 104,815 $ 108,017
 3    Cost of Service                             107,928       111,031       133,853   136,649   139,436   132,461   131,521   136,399   139,054   141,220
 4    LNG Mitigating Revenue                             -             -       (2,680)   (2,753)   (1,225)     (950)     (229)   (4,133)   (5,223)   (5,019)
 5   Total Annual Revenue Requirement           $ 172,249     $ 163,573     $ 183,586 $ 186,692 $ 193,784 $ 188,642 $ 225,754 $ 232,936 $ 238,646 $ 244,218
 6
 7   Allocation of Annual Revenue Requirement (LNG to CDS)
 8   Core Market
 9    Cost of Gas net of Royalty Revenue         $ 64,322 $ 52,543          $ 52,414 $ 52,795 $ 55,574 $ 57,131 $ 94,462 $ 100,669 $ 104,815 $ 108,017
10    Cost of Service                               89,349    90,250          100,895   103,635   106,321   100,914    99,758   102,666   105,099   107,422
11    LNG Mitigating Revenue                              -         -          (2,680)   (2,753)   (1,225)     (950)     (229)   (4,133)   (5,223)   (5,019)
12   Total Allocated Revenue Requirement         $ 153,670 $ 142,793        $ 150,629 $ 153,678 $ 160,670 $ 157,095 $ 193,991 $ 199,202 $ 204,691 $ 210,419
13
14   Firm Transportation
15    Cost of Service                           $ 12,905      $ 15,284      $ 27,731 $ 27,727 $ 27,756 $ 26,243 $ 26,317 $ 27,902 $ 28,041 $ 27,870
16    LNG Mitigating Revenue                            -             -             -        -        -        -        -        -        -        -
17   Total Allocated Revenue Requirement        $ 12,905      $ 15,284      $ 27,731 $ 27,727 $ 27,756 $ 26,243 $ 26,317 $ 27,902 $ 28,041 $ 27,870
18
19   Other Transportation (JV, Squamish)
20    Cost of Service                           $    5,674    $    5,496    $    5,227 $     5,287 $    5,358 $    5,304 $    5,447 $    5,835 $    5,919 $    5,942
21    LNG Mitigating Revenue                              -             -             -           -          -          -          -          -          -          -
22   Total Allocated Revenue Requirement        $    5,674    $    5,496    $    5,227 $     5,287 $    5,358 $    5,304 $    5,447 $    5,835 $    5,919 $    5,942




                                                                                   - 30 -
                                                         TERASEN GAS (VANCOUVER ISLAND) INC.

                                       RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
                                      CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                                                DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                                             RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2



   Schedule 48.2 Base + 45, LNG Portfolio
   (Core)                                         2006         2007         2008         2009         2010         2011         2012         2013         2014         2015

23 Calculation of Allocated Unit Cost (LNG to CDS)
24 Residential Customer (Figure IR48.2 - Base + 45, LNG Portfolio)
25 Allocated Cost of Gas                      $ 24,393     $ 19,943     $ 19,902     $ 20,060     $ 21,134     $ 21,736     $ 35,960     $ 38,364     $ 39,963     $ 41,182
26 Net Allocated Cost of Service                49,713       50,620       54,199       55,702       57,892       55,424       55,182       54,914       55,797       57,190
27 Total Allocated Costs                      $ 74,106     $ 70,563     $ 74,100     $ 75,761     $ 79,027     $ 77,160     $ 91,142     $ 93,277     $ 95,761     $ 98,372
28 Annual Demand                                 4,582        4,736        4,884        5,025        5,156        5,279        5,391        5,499        5,609        5,721
29
30 Allocated Unit Cost of Gas                 $     5.32   $     4.21   $     4.07   $     3.99   $     4.10   $     4.12   $     6.67   $     6.98   $     7.13   $     7.20
31 Allocated Unit Cost of Service                  10.85        10.69        11.10        11.09        11.23        10.50        10.24         9.99         9.95        10.00
32 Total Allocated Unit Cost of Service       $ 16.17 $ 14.90           $    15.17   $    15.08   $    15.33   $    14.62   $    16.91   $    16.96   $    17.07   $    17.20
33
34 Firm Transportation (Figure IR48.2 - Base + 45, LNG Portfolio)
35 Contract Demand                               38,000     46,667          90,000       90,000       90,000       90,000       90,000       90,000       90,000       90,000
36 Net Allocated Cost of Service              $ 12,905     $ 15,284     $ 27,731     $ 27,727     $ 27,756     $ 26,243     $ 26,317     $ 27,902     $ 28,041     $ 27,870
37 Allocated Unit Cost                        $   0.93     $   0.90     $   0.84     $   0.84     $   0.84     $   0.80     $   0.80     $   0.85     $   0.85     $   0.85




                                                                                - 31 -
                                                            TERASEN GAS (VANCOUVER ISLAND) INC.

                                        RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
                                       CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                                                 DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                                               RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




                                     Demand Scenario - Base + 45 P&C
                           $25.00
                                       Residential Customer (RGS)
                                       Allocated Cost $ per GJ


                           $20.00
$ per GJ Delivered




                           $15.00




                           $10.00



                                                                                                         Average Cost of Gas
                                                                                                         Average Delivery Margin
                            $5.00
                                                                                                         Heating Oil Equivalent
                                                                                                         90% Residential Electric



                             $-
                                     2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026




                                    Demand Scenario Base + 45 P&C
                           $1.40
                                        Firm Transportation
                                        Allocated Cost $ per GJ/d Capacity

                           $1.20




                           $1.00
Demand Charge $ per GJ/d




                           $0.80




                           $0.60




                           $0.40

                                                                        Allocated Unit Cost / GJ

                           $0.20                                        Allocated Unit Cost x 1.25 R/C




                           $-
                                    2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026




                                                                                         - 32 -
                                                            TERASEN GAS (VANCOUVER ISLAND) INC.

                                            RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
                                           CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                                                     DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                                                RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




     Schedule 48.2 Base + 45, P&C Portfolio        2006         2007          2008            2009       2010          2011       2012          2013       2014          2015

 1   TGVI Annual Revenue Requirement
 2    Cost of Gas net of Royalty Revenue       $ 64,322     $ 54,835      $ 55,181       $ 56,147 $ 60,000         $ 62,600 $ 100,605       $ 103,872 $ 107,391      $ 111,342
 3    Cost of Service                            107,881      109,275       130,427        136,620   144,588         138,454   133,084        136,731   143,954        148,289
 4    LNG Mitigating Revenue                           -            -             -              -          -              -          -             -         -              -
 5   Total Annual Revenue Requirement          $ 172,203    $ 164,110     $ 185,608      $ 192,767 $ 204,589       $ 201,054 $ 233,689      $ 240,603 $ 251,345      $ 259,631
 6
 7   Allocation of Annual Revenue Requirement
 8   Core Market
 9    Cost of Gas net of Royalty Revenue      $ 64,322      $ 54,835      $ 55,181       $ 56,147 $ 60,000         $ 62,600 $ 100,605       $ 103,872 $ 107,391      $ 111,342
10    Cost of Service                            89,451        89,446        97,390        101,814   107,083         102,672    99,365        102,119   108,954        113,345
11    LNG Mitigating Revenue                          -              -            -              -          -              -          -             -         -              -
12   Total Allocated Revenue Requirement      $ 153,773     $ 144,281     $ 152,571      $ 157,960 $ 167,083       $ 165,272 $ 199,970      $ 205,991 $ 216,344      $ 224,687
13
14   Firm Transportation
15    Cost of Service                          $ 12,801     $ 14,581      $ 27,794       $ 29,226 $ 31,425         $ 29,772 $ 27,937        $ 28,629 $ 29,018        $ 28,980
16    LNG Mitigating Revenue                          -             -            -              -         -               -         -              -         -              -
17   Total Allocated Revenue Requirement       $ 12,801     $ 14,581      $ 27,794       $ 29,226 $ 31,425         $ 29,772 $ 27,937        $ 28,629 $ 29,018        $ 28,980
18
19   Other Transportation (JV, Squamish)
20    Cost of Service                          $    5,628   $    5,247    $    5,242     $     5,581 $    6,080    $    6,011 $    5,782    $    5,986 $    5,989    $    5,977
21    LNG Mitigating Revenue                            -             -            -               -           -            -           -            -           -            -
22   Total Allocated Revenue Requirement       $    5,628   $    5,247    $    5,242     $     5,581 $    6,080    $    6,011 $    5,782    $    5,986 $    5,989    $    5,977




                                                                                     - 33 -
                                                             TERASEN GAS (VANCOUVER ISLAND) INC.

                                             RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
                                            CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                                                      DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                                                 RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




     Schedule 48.2 Base + 45, P&C Portfolio         2006         2007         2008            2009       2010         2011       2012         2013       2014         2015

23   Calculation of Allocated Unit Cost
24   Residential Customer (Figure IR48.2 - Base + 45, P&C Portfolio)
25    Allocated Cost of Gas                   $ 24,393 $ 20,813 $ 20,952                 $ 21,333 $ 22,818        $ 23,817 $ 38,298       $ 39,584 $ 40,945       $ 42,450
26    Net Allocated Cost of Service             49,763     50,137    53,607                55,822   58,369          56,354   54,860         56,277    59,732         62,002
27   Total Allocated Costs                    $ 74,156 $ 70,950 $ 74,559                 $ 77,155 $ 81,187        $ 80,170 $ 93,159       $ 95,861 $ 100,677      $ 104,452
28   Annual Demand                                4,582     4,736     4,884                 5,025    5,156           5,279    5,391          5,499     5,609          5,721
29
30    Allocated Unit Cost of Gas                $     5.32   $     4.39   $     4.29     $      4.25 $     4.43   $     4.51 $     7.10   $     7.20 $     7.30   $     7.42
31    Allocated Unit Cost of Service            $    10.86   $    10.59   $    10.98     $     11.11 $    11.32   $    10.68 $    10.18   $    10.23 $    10.65   $    10.84
32   Total Allocated Unit Cost of Service       $    16.19   $    14.98   $    15.27     $     15.36 $    15.74   $    15.19 $    17.28   $    17.43 $    17.95   $    18.26
33
34   Firm Transportation (Figure IR48.2 - Base + 45, P&C Portfolio)
35   Contract Demand                             38,000     46,667          90,000         90,000   90,000          90,000   90,000         90,000   90,000         90,000
36   Net Allocated Cost of Service            $ 12,801 $ 14,581           $ 27,794       $ 29,226 $ 31,425        $ 29,772 $ 27,937       $ 28,629 $ 29,018       $ 28,980
37   Allocated Unit Cost                      $     0.92 $    0.86        $   0.85       $   0.89 $   0.96        $   0.91 $   0.85       $   0.87 $   0.88       $   0.88




                                                                                     - 34 -
                                                           TERASEN GAS (VANCOUVER ISLAND) INC.

                                        RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
                                       CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                                                 DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                                               RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




                                    Demand Scenario - Base + 45 PCC 53 Hours Curtailment
                           $25.00

                                       Residential Customer (RGS)
                                       Allocated Cost $ per GJ


                           $20.00




                           $15.00
$ / GJ Delivered




                           $10.00



                                                                                                       Average Cost of Gas
                                                                                                       Average Delivery Margin
                            $5.00
                                                                                                       Heating Oil Equivalent
                                                                                                       90% Residential Electric



                             $-
                                     2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026




                                   Demand Scenario Base + 45 PCC 53 Hours Curtailment
                           $1.40
                                                       Firm Transportation
                                                       Allocated Cost $ per GJ/d Capacity

                           $1.20




                           $1.00
Demand Charge $ per GJ/d




                           $0.80




                           $0.60




                           $0.40
                                                                    Allocated Unit Cost / GJ

                                                                    Allocated Unit Cost x 1.25 R/C

                           $0.20




                           $-
                                    2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026




                                                                                          - 35 -
                                                            TERASEN GAS (VANCOUVER ISLAND) INC.

                                            RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
                                           CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                                                     DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                                                RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




     Schedule 48.2 Base + 45, PCC Portfolio 53
     hours Curtailment                               2006         2007         2008            2009          2010         2011         2012          2013       2014         2015

 1   TGVI Annual Revenue Requirement
 2    Cost of Gas net of Royalty Revenue         $ 64,322     $ 55,949     $ 56,351        $ 56,644      $ 59,787     $ 61,682     $ 99,444      $ 102,585   $ 105,923   $ 109,478
 3    Cost of Service                              107,697      109,196      125,042         128,060       130,894      124,645      125,497       127,052     130,252     131,609
 4    LNG Mitigating Revenue                             -             -           -                -             -           -             -            -           -            -
 5   Total Annual Revenue Requirement            $ 172,019    $ 165,146    $ 181,394       $ 184,704     $ 190,681    $ 186,327    $ 224,941     $ 229,637   $ 236,175   $ 241,087
 6
 7   Allocation of Annual Revenue Requirement
 8   Core Market
 9    Cost of Gas net of Royalty Revenue         $ 64,322     $ 55,949     $ 56,351        $ 56,644      $ 59,787     $ 61,682     $ 99,444      $ 102,585   $ 105,923   $ 109,478
10    Cost of Service                              89,350       89,411       90,652          93,717        96,592       92,024       92,247         94,113      96,506      98,230
11    LNG Mitigating Revenue                            -             -           -                -            -            -             -             -           -            -
12   Total Allocated Revenue Requirement         $ 153,672    $ 145,360    $ 147,003       $ 150,361     $ 156,379    $ 153,706    $ 191,691     $ 196,698   $ 202,430   $ 207,708
13
14   Firm Transportation
15    Cost of Service                            $ 12,744     $ 14,548     $ 28,940        $ 28,846      $ 28,756     $ 27,145     $ 27,549      $ 27,244    $ 27,869    $ 27,524
16    LNG Mitigating Revenue                            -             -           -                -            -            -             -            -           -            -
17   Total Allocated Revenue Requirement         $ 12,744     $ 14,548     $ 28,940        $ 28,846      $ 28,756     $ 27,145     $ 27,549      $ 27,244    $ 27,869    $ 27,524
18
19 Other Transportation (JV, Squamish)
20 Cost of Service                               $    5,603   $    5,237   $    5,451      $    5,497    $    5,546   $    5,476   $    5,702    $    5,697 $    5,883   $    5,868
21 LNG Mitigating Revenue                                 -            -            -                -            -            -             -            -          -             -
22 Total Allocated Revenue Requirement           $    5,603   $    5,237   $    5,451      $    5,497    $    5,546   $    5,476   $    5,702    $    5,697 $    5,883   $    5,868




                                                                                  - 36 -
                                                           TERASEN GAS (VANCOUVER ISLAND) INC.

                                           RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
                                          CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                                                    DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                                               RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2



   Schedule 48.2 Base + 45, PCC Portfolio 53
   hours Curtailment                                2006         2007         2008            2009         2010         2011         2012         2013         2014         2015

23 Calculation of Allocated Unit Cost
24 Residential Customer (Figure IR48.2 - Base + 45, PCC Portfolio 53 hours Curtailment)
25 Allocated Cost of Gas                        $ 24,393     $ 21,236     $ 21,397        $ 21,522     $ 22,737     $ 23,467     $ 37,856     $ 39,094     $ 40,386     $ 41,739
26 Net Allocated Cost of Service                  49,723       50,143       50,872          52,611       54,246       52,090       52,229       53,349       54,609       55,615
27 Total Allocated Costs                        $ 74,116     $ 71,378     $ 72,269        $ 74,134     $ 76,983     $ 75,557     $ 90,086     $ 92,443 $ 94,995         $ 97,354
28 Annual Demand                                   4,582        4,736        4,884           5,025        5,156        5,279        5,391        5,499    5,609            5,721
29
30 Allocated Unit Cost of Gas                   $     5.32   $     4.48   $     4.38      $     4.28   $     4.41   $     4.45   $     7.02   $     7.11 $       7.20   $     7.30
31 Allocated Unit Cost of Service               $    10.85   $    10.59   $    10.42      $    10.47   $    10.52   $     9.87   $     9.69   $     9.70 $       9.74   $     9.72
32 Total Allocated Unit Cost of Service         $    16.18   $    15.07   $    14.80      $    14.75   $    14.93   $    14.31   $    16.71   $    16.81 $      16.94   $    17.02
33
34 Firm Transportation (Figure IR48.2 - Base + 45, PCC Portfolio 53 hours Curtailment)
35 Contract Demand                                38,000     46,667     90,000     90,000                90,000       90,000       90,000       90,000       90,000       90,000
36 Net Allocated Cost of Service               $ 12,744 $ 14,548 $ 28,940 $ 28,846                     $ 28,756     $ 27,145     $ 27,549     $ 27,244     $ 27,869     $ 27,524
37 Allocated Unit Cost                          $     0.92   $     0.85   $     0.88      $     0.88   $     0.88   $     0.83   $     0.84   $     0.83   $     0.85   $     0.84




                                                                                 - 37 -
                                                            TERASEN GAS (VANCOUVER ISLAND) INC.

                                        RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
                                       CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                                                 DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                                               RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




                                     Demand Scenario - Base + 45 PCC 240 hours Curtailment
                           $25.00

                                        Residential Customer (RGS)
                                        Allocated Cost $ per GJ


                           $20.00
$ per GJ Delivered




                           $15.00




                           $10.00




                                                                                                  Average Cost of Gas
                           $5.00                                                                  Average Delivery Margin
                                                                                                  Heating Oil Equivalent
                                                                                                  90% Residential Electric


                            $-
                                     2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026



                                    Demand Scenario - Base + 45 PCC 240 Hours Curtailment
                           $1.40

                                                                                                  Firm Transportation
                                                                                                  Allocated Cost $ per GJ/d Capacity
                           $1.20




                           $1.00
Demand Charge $ per GJ/d




                           $0.80



                           $0.60




                           $0.40
                                                        Allocated Unit Cost / GJ
                                                        Allocated Unit Cost x 1.25 R/C

                           $0.20



                           $-
                                    2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026




                                                                                         - 38 -
                                                           TERASEN GAS (VANCOUVER ISLAND) INC.

                                         RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
                                        CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                                                  DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                                                RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




     Schedule 48.2 Base + 45, PCC Portfolio
     240 hours Curtailment                          2006         2007       2008         2009       2010         2011       2012         2013       2014       2015

 1   TGVI Annual Revenue Requirement
 2    Cost of Gas net of Royalty Revenue        $ 64,322     $ 55,797 $ 56,173       $ 56,467 $ 59,941       $ 61,778 $ 99,385       $ 102,352 $ 105,870 $ 109,841
 3    Cost of Service                             108,002      109,034   124,363       127,387   130,226       122,296   122,357       124,127   125,210   126,361
 4    LNG Mitigating Revenue                             -            -        -             -          -             -        -             -         (0)      (0)
 5   Total Annual Revenue Requirement           $ 172,323    $ 164,831 $ 180,536     $ 183,854 $ 190,167     $ 184,073 $ 221,743     $ 226,478 $ 231,079 $ 236,203
 6
 7   Allocation of Annual Revenue Requirement
 8   Core Market
 9    Cost of Gas net of Royalty Revenue        $ 64,322     $ 55,797 $ 56,173       $ 56,467 $ 59,941       $ 61,778 $ 99,385       $ 102,352 $ 105,870 $ 109,841
10    Cost of Service                              88,728       88,493    87,064        90,224    93,186        87,479    88,546        90,589    92,104    93,687
11    LNG Mitigating Revenue                             -            -        -             -          -             -        -             -         (0)      (0)
12   Total Allocated Revenue Requirement        $ 153,050    $ 144,290 $ 143,237     $ 146,691 $ 153,126     $ 149,256 $ 187,932     $ 192,941 $ 197,974 $ 203,529
13
14 Firm Transportation
15 Cost of Service                              $ 13,390     $ 15,106 $ 31,390       $ 31,218 $ 31,054       $ 28,937 $ 28,014       $ 27,740 $ 27,340 $ 26,943
16 LNG Mitigating Revenue                               -            -       -              -         -              -       -              -        (0)     (0)
17 Total Allocated Revenue Requirement          $ 13,390     $ 15,106   $ 31,390     $ 31,218 $ 31,054       $ 28,937   $ 28,014     $ 27,740 $ 27,340     $ 26,943
18
19 Other Transportation (JV, Squamish)
20 Cost of Service                              $    5,884   $    5,435 $    5,909   $    5,945 $    5,986   $    5,879 $    5,798   $    5,801 $    5,772 $    5,745
21 LNG Mitigating Revenue                                -             -         -            -          -             -         -            -          (0)       (0)
22 Total Allocated Revenue Requirement          $    5,884   $    5,435 $    5,909   $    5,945 $    5,986   $    5,879 $    5,798   $    5,801 $    5,772 $    5,745




                                                                               - 39 -
                                                            TERASEN GAS (VANCOUVER ISLAND) INC.

                                             RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
                                            CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                                                      DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                                                 RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2



     Schedule 48.2 Base + 45, PCC Portfolio
     240 hours Curtailment                           2006         2007         2008         2009       2010         2011         2012         2013         2014         2015

23 Calculation of Allocated Unit Cost
24 Residential Customer (Figure IR48.2 - Base + 45, PCC Portfolio 240 hours Curtailment)
25 Allocated Cost of Gas                         $ 24,393     $ 21,178     $ 21,329     $ 21,455 $ 22,795       $ 23,504     $ 37,834     $ 39,005 $ 40,366         $ 41,878
26 Net Allocated Cost of Service                   49,414       49,704       49,348       51,127   52,795         50,047       50,811       52,012   52,922           53,839
27 Total Allocated Costs                         $ 73,807     $ 70,883     $ 70,677     $ 72,582 $ 75,590       $ 73,550     $ 88,645     $ 91,017 $ 93,288         $ 95,716
28 Annual Demand                                      4,582        4,736        4,884        5,025      5,156        5,279        5,391        5,499        5,609        5,721
29
30 Allocated Unit Cost of Gas                    $     5.32   $     4.47   $     4.37   $     4.27 $     4.42   $     4.45   $     7.02   $     7.09   $     7.20   $     7.32
31 Allocated Unit Cost of Service                     10.79        10.49        10.10        10.18      10.24         9.48         9.43         9.46         9.44         9.41
32   Total Allocated Unit Cost of Service        $    16.11   $    14.97   $    14.47   $    14.45 $    14.66   $    13.93   $    16.44   $    16.55 $      16.63   $    16.73
33
34   Firm Transportation (Figure IR48.2 - Base + 45, PCC Portfolio 240 hours Curtailment)
35   Contract Demand                               38,000     46,667     90,000     90,000   90,000               90,000       90,000       90,000   90,000           90,000
36   Net Allocated Cost of Service              $ 13,390 $ 15,106 $ 31,390 $ 31,218 $ 31,054                    $ 28,937     $ 28,014     $ 27,740 $ 27,340         $ 26,943
37   Allocated Unit Cost                        $    0.97 $     0.89 $     0.96 $     0.95 $   0.95             $   0.88     $   0.85     $   0.84 $   0.83         $   0.82




                                                                                  - 40 -
                      TERASEN GAS (VANCOUVER ISLAND) INC.

        RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
       CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                 DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

             RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




48.3   Please provide a table that is broadly similar to Tables 6.5.1, 6.5.2 and 6.5.3 for
       each of the Base +0, Base +20 and Base +45 forecasts showing the revised
       costs and benefits for the LNG, Pipe and Compression and PCC portfolios, and
       comparing the incremental costs and present values of the portfolio options for
       each load forecast.

Response

This requested information has been prepared for the Revised Base + 45 scenario
based on the information provided in the response to BCUC IR 48.2. The results are
shown in the attached Tables IR43.3a, IR 48.3b, and IR 48.3c.

The following conclusions can be made from these results and the information provided
in IR 48.2:

   •   The LNG storage portfolio is the least cost solution for meeting future system
       requirements for the expected demand scenario.

   •   An on-system storage facility results in lower cost gas supply for sales customers
       than does the use of peaking/curtailment resources

   •   In the absence of a storage facility, curtailment/peaking gas arrangements could
       allow deferral of facility additions. However, facility additions are still required in
       2007 to meet the expected demand requirements in all portfolios, regardless of
       the level of curtailment available from ICP.

   •   Expansion of ICP distillate fuel storage capacity from the existing 53 hours to 240
       hours would be required to allow TGVI to effectively use the full curtailment
       capacity without requiring ICP to either shut down or run at reduced capacity.

   •   The average plant in service (ie undepreciated rate base) at the end of the
       planning period is approximately $100 million lower in the LNG portfolio than any
       of the other portfolios. (Refer to schedules in IR48.2, Attachment 4)

   •   In the case of physical interruption, an on island LNG storage facility improves
       the security of supply over the Pipe and Compression and PCC portfolios for
       TGVI customers that do not have fuel switching capability.




                                        - 41 -
                  TERASEN GAS (VANCOUVER ISLAND) INC.

       RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
      CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

           RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




Table IR 48.3a                                Revised Base + 45
                                           LNG              Pipe
(PV 2005-2027 @ 6.1%, $M)                 Storage       Compression
Incremental Facilities                           212                243
Transport Fuel Differential                       14                   -
Gas Supply Differential                          (57)                  -
LNG Mitigation                                   (28)
Incremental Wheeling Costs                         11                31
Total (PV@6.1%)                                  153                274



Table IR 48.3b                                Revised Base + 45
                                           LNG              Pipe
                                          Storage       Compression
(PV 2005-2027 @ 6.1%, $M)                                Curtailment
                                                          53 hours
Incremental Facilities                           212              175
Transport Fuel Differential                        14                7
Gas Supply Differential                           (57)            (16)
LNG Mitigation                                    (28)                -
Peaking Gas Mitigation                                -               -
Incremental Wheeling Costs                          11             21
Total (PV@6.1%)                                   153             188



Table IR 48.3c                                Revised Base + 45
                                           LNG              Pipe
                                          Storage       Compression
(PV 2005-2027 @ 6.1%, $M)                                Curtailment
                                                          240 hours
Incremental Facilities                           212              144
Transport Fuel Differential                        14                8
Gas Supply Differential                           (57)            (14)
LNG Mitigation                                    (28)                -
Peaking Gas Mitigation                              (8)               -
Incremental Wheeling Costs                          11              17
Total (PV@6.1%)                                   145             156




                                 - 42 -
                     TERASEN GAS (VANCOUVER ISLAND) INC.

         RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
        CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                  DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

             RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




48.4   The Commission understands that TGVI intends to file an update to the financial
       analysis and information in the CPCN Application using updated data and
       parameters in several areas. Please use such updated data and parameters
       when responding to this Information Request, and provide a summary of
       changes that have been made to the assumptions and other data from the CPCN
       Application in order to generate the updated information. Please explain briefly
       why each updated parameter is appropriate.

Response

The update to the financial analysis and the information in the CPCN application has
been provided in the previous response to BCUC IR 48.2. The principle changes are as
a result of the new resource portfolios that have been developed for the Revised Base
+0 and Revised Base +45 demand scenarios. A revised list of operational, financial and
economic assumptions is also included in the response to BCUC IR 48.2.


48.5   For the foregoing Revised Base forecast, and making full use of the assumed
       curtailment available from ICP, what is the maximum amount of firm capacity that
       the existing TGVI system could provide for 2007 to serve new gas-fired
       generation resulting from BC Hydro’s Call for Tenders (“CFT Generation”)?
       Please provide a System Flow Diagram demonstrating this situation. If the
       System Flow Diagram does not assume 700 psig delivery pressure at Victoria,
       please explain.

Response

For the Revised Base +45 forecast and the assumption of up to 240 hours of ICP
curtailment in 2007 the existing system could only provide 27 TJ/d to the CFT project
when service to ICP is fully curtailed. In other words, without expansion of the existing
system only 27 TJ/d of firm service net of curtailment would be available to meet the
requirements of both ICP and the CFT generation.

While the volume of curtailment available is greater than previous assumptions,
available curtailment capacity is limited to 45 TJ/d from ICP since VIGJV curtailment is
no longer available. In this case the minimum level of firm service available is defined by
the Design Day demand net of ICP curtailment. This condition is shown on the following
diagram with Victoria pressure at 700 psig.




                                       - 43 -
            TERASEN GAS (VANCOUVER ISLAND) INC.

 RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
          DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

     RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




                           - 44 -
49.0   Reference: Exhibit B-3, Response to BCUC IR 34.9; Exhibit B-6, Tab 3, MEM IR
             4.3, 21.3, 27.4

       49.1   Please confirm that the Revised Base forecast in the foregoing question is the
              most likely scenario. If not, please indicate what other revisions are necessary to
              develop the most likely scenario and provide the resulting present value costs for
              each portfolio using this Base forecast.

       Response

       The Revised Base +45 scenario shown in the BCUC IR 48.1 response is the most likely
       demand scenario for the combination of Core, VIGJV, and generation demand given BC
       Hydro’s recent announcement regarding the proposed Duke Point Power project. The
       Revised Base +0 forecast represents the most likely outcome if the Commission does
       not approve the new generation resulting from the CFT.

       Please refer to IR 48.2 for response to what other revisions are necessary to develop the
       most likely scenario and provide present value costs for the Base +0 forecast.



       49.2   If BC Hydro has announced the results of its Call for Tenders (“CFT”), how much
              additional firm TGVI capacity has TGVI assumed will be needed for the CFT
              Generation? Please indicate which Revised Base forecast scenario would
              accommodate the CFT outcome.

       Response

       An additional 45 TJ/d of firm capacity is assumed to be needed for the CFT generation
       project. The Revised Base +45 forecast represents the expected demand if the CFT
       generation proceeds. Please see IR 48.1.




                                             - 45 -
                     TERASEN GAS (VANCOUVER ISLAND) INC.

         RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
        CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                  DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

             RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




49.3   When does TGVI expect BC Hydro to commit to using firm service at ICP?
       When does TGVI expect BC Hydro to commit to using firm service for the CFT
       Generation?

Response

TGVI believes that BC Hydro must commit to firm service for ICP and for the 252 MW
facility resulting from the CFT by the end of 2004. TGVI expects that such commitments
will be subject to Commission approval.

In the press release announcing the outcome of the CFT it was stated that construction
of the new plant will begin in March 2005. BC Hydro’s CFT schedule indicated that an
application for Commission approval of the Electricity Purchase Agreement (EPA)
pursuant to section 71 of the Utilities Commission Act will be filed by November 19.
TGVI assumes a decision regarding gas transportation will have to be made by BC
Hydro before the Commission can approve the EPA. TGVI will require firm commitments
from BC Hydro in order to provide the firm gas transportation that BC Hydro will require
to meet the needs of its generating plants. The construction schedule of the LNG facility
requires that the Commission grant a CPCN by January 2005 in order to have the LNG
facility in place to meet BC Hydro's requirements for the winter of 2007/08. TGVI expects
that the Commission will render a decision on the CPCN in that timeframe, as the
Commission, in its Decision dated September 8, 2003 regarding the VIGP CPCN stated,
on page 77 that “Based on the results of the CFT, the Commission is prepared to
consider any future application for CPCN approval or Electricity Purchase Agreement
approval on an expedited basis.” In addition, the current transport agreement to serve
ICP expires on December 31, 2004. As a result, TGVI expects to have firm commitments
in place for both ICP and the Duke Point Power Project by the end of 2004.




                                      - 46 -
                     TERASEN GAS (VANCOUVER ISLAND) INC.

         RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
        CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                  DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

             RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




49.4   BCUC IR 34.9 states “TGVI has informed both VIGJV and BC Hydro that without
       firm long-term commitments TGVI will not proceed with any expansion.” MEM IR
       27.4 states “With the exception of Terasen Gas (Squamish) Inc., there are no
       contractual arrangements for firm capacity with any customer extending beyond
       2005 at this time.”

When does TGVI expect to have contractual arrangements in place for sufficient firm
capacity to justify the proposed system expansion?

Response

Since the response to MEM IR 27.4 was prepared, TGVI has put an agreement in place
with the VIGJV for firm transport service through to December 31 2012. In addition,
BC Hydro recently announced the outcome of the Vancouver Island call for tenders, the
252 MW Duke Point Power Project. As a result approximately 90 TJ/d of transport
requirements associated with generation facilities located on Vancouver Island will be
required by 2007. As indicated in the response to IR 49.3, TGVI expects to have
associated contractual arrangements for the generation requirements before the end of
2004. TGVI also expects that it will have a firm commitment from Terasen Gas for
storage services before the end of 2004.

The expected transport requirements associated with the VIGJV and BC Hydro, and the
firm storage service contract with Terasen Gas are sufficient to justify the proposed
expansion.

While TGVI continues to take the position that it will not proceed with any expansion
without firm long-term commitments from BC Hydro, the Commission must understand
that this CPCN Application must proceed in the absence of those long-term
commitments. The LNG storage facility is the most cost effective means of enabling the
TGVI system to supply the gas requirements on Vancouver Island and the Sunshine
Coast (including ICP and the new generating facility at Duke Point). The construction
schedule for the LNG storage facility requires that TGVI enter into a contract with
Chicago Bridge & Iron early in 2005. Construction of the Duke Point generating plant is
to commence in March 2005. Both of these events require that a CPCN be granted for
the expansion of the TGVI system by January 2005.

If a CPCN is not granted by January 2005 then the in-service date of the LNG facility will
not meet BC Hydro’s requirements. If a CPCN is not granted then TGVI will not be able
to commit to providing firm service to BC Hydro. If TGVI cannot commit to providing firm
service to BC Hydro then it would be difficult for the Commission to approve an EPA that
assumes that there will be firm gas transportation service in place by the fall of 2007.




                                       - 47 -
                      TERASEN GAS (VANCOUVER ISLAND) INC.

         RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
        CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                  DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

              RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




49.5   If BC Hydro does not commit to using firm service at ICP in 2007, how does that
       affect TGVI’s scenarios?

Response

TGVI has evaluated the facility requirements on its system based on meeting firm
demands. If BC Hydro does not commit to using firm service at ICP, TGVI will re-
evaluate its portfolios. If BC Hydro only commits to firm service for the proposed facility
at Duke Point and not for ICP, TGVI will need to re-evaluate the requirement and/or
timing for the LNG facility. Given the revised forecast associated with the long-term
requirements of the VIGJV, the need for new facilities will depend on the requirements to
meet the firm service associated with the proposed facility at Duke Point. This may result
in a preferred resource portfolio that does not include the LNG facility. In this case, it is
expected that the LNG facility will not be required in 2007 and that the preferred
resource portfolio will not include any facilities to provide service to ICP.




                                        - 48 -
                            TERASEN GAS (VANCOUVER ISLAND) INC.

               RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
              CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                        DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                    RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2



50.0   Reference: Exhibit B-6, Tab 3, MEM IR 3.2

       TGVI states that the scenarios labeled as High-High and Low-Low are intended to
       bracket the full range of possible forecasts and are therefore unlikely.

       50.1   Given the foregoing Revised Base forecast, do the High-High and Low-Low
              scenarios in the Resource Plan still bracket the full range of possible forecasts?

       Response

       Given the new agreement, the uncertainty previously associated with VIGJV demand
       has been reduced. Based on previous consultation with the VIGJV, the forecasts used in
       the Resource plan contemplated a low of 20 TJ/d and a high of 40 TJ/d. With the new
       agreement TGVI now expects a much narrower range of between 8 to 16 TJ/d for this
       component. In addition, BC Hydro has announced the results of the Vancouver Island
       CFT which should result in an additional 45 TJ/d of demand. With these revisions the
       High-High and Low-Low forecasts would still bracket the full range of expected
       forecasts.


       50.2   Which scenario is now the least likely?

       Response

       Due to the reduction in the forecasted VIGJV demand, the High High forecast would be
       the least likely. However the recent CFT announcement also makes the Low-Low
       forecast unlikely.




                                              - 49 -
                              TERASEN GAS (VANCOUVER ISLAND) INC.

                RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
               CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                         DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

                     RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2



51.0   Reference: Exhibit B-6, Response to BC Hydro IR 22.0 (a)

       51.1    Please provide the most recent information that TGVI has on the status of back-
               up firing of ICP on distillate oil.

       Response

       The most recent information provided to TGVI by BC Hydro is contained in response to
       BC Hydro IR22(a) and is based on “…available data as of February 25, 2004 and is
       subject to change based on testing and commissioning yet to be performed.”

       TGVI has not received any notice from BC Hydro confirming the status of back-up firing
       of ICP on distillate oil. However, TGVI understands through informal discussions that the
       distillate firing capability was installed and commissioned this past summer.



       51.2    Please provide any information that TGVI has about the ability of BC Hydro to
               increase the distillate storage capacity at ICP to provide for greater long-term fuel
               flexibility?

       Response

       Based on discussions with technical personnel involved in the design and construction of
       the ICP facility and on TGVI’s own assessment of ICP’s air permits, TGVI understands
       the following with regard to the ability to increase distillate storage capacity at ICP:

       The existing 2.7 million litre tank allows 53 hours of operation on distillate and the
       existing facilities are limited to ‘batched’ operation on distillate. In other words, the tank
       must be emptied before being refilled and operation on distillate is not possible during
       the refill process. The refill process takes up to 15 days and involves cleaning the tank,
       filling the tank, allowing the fuel to settle, and having a fuel sample tested and approved.
       ICP can run on either distillate or natural gas but not a mixture of both. If BC Hydro relies
       on distillate to maintain dependable capacity during periods of curtailment, TGVI expects
       that curtailment will be limited to the capacity of on-site distillate storage since
       curtailment during the refill period would result in reduced output or loss of service from
       ICP. For these reasons increased use of curtailment would require additional on-site
       storage of distillate.

       To supply ICP, distillate is barged into Nanaimo then certified and stored at a Chevron
       facility before being transported by truck to ICP. TGVI is uncertain whether increased
       use of distillate would require an expansion of the Chevron facilities. The availability of
       truck transportation for distillate fuel on Vancouver Island is limited so it is unlikely that
       the current turnaround time can be reduced. Barge delivery may be an alternative,



                                                 - 50 -
                      TERASEN GAS (VANCOUVER ISLAND) INC.

         RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
        CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                  DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

              RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




however TGVI is uncertain as to the requirements for handling facilities and permitting, if
any, associated with this means of delivery.

In response to a BCUC staff IR dated March 21, 2003 related to the VIEC CPCN
Application for VIGP BC Hydro stated that:

       …any distillate not consumed within an approximate time frame of one year
       would become stale and may not be useable in the ICP turbine. This would
       require disposal, which has costs and risks associated with fuel handling.

Increasing the amount of distillate storage would compound these fuel handling
problems. If distillate storage is increased to maintain dependable capacity during
periods of curtailment the fuel must be consumed whether or not curtailment occurs. If
curtailment does not occur, due to a warm winter for example, the distillate would have
to be used anyway or removed from the site. Disposing of the distillate through use in
the ICP turbine would increase average use of this fuel which may contravene
restrictions of either the air permit or the EPA with Calpine. TGVI is uncertain as to the
handling requirements and disposal cost that would be associated with increased
distillate storage at ICP

The ability to add additional tanks may be limited due to space constraints. The existing
tank is located on the southern portion of the ICP site. The storage tank is situated on a
concrete slab that is positioned on top of pilings. A lined brim surrounds the storage tank
to contain any spills or leaks. TGVI understands that it may be possible to install a 1
million litre (20 hours) storage tank with secondary containment within ICP property if
offices near the existing storage tank are relocated. As with the site of the existing
storage tank, the surrounding area also displays poor geotechnical conditions. In the ICP
Application for a Project Approval Certificate, a preliminary geotechnical investigation
indicated that the extensive fill cover within the southern portion of the site would require
deep pile foundations and/or replacement with structural fills. The western portion of the
southern area would require special consideration in terms of settlement and earthquake
loading due to the relatively sensitive soils at depth. Larger or additional storage tanks
would have to be located in nearby lay-down areas on property owned by the Elk Falls
mill.

Air quality emissions are increased under distillate-fired operation. In the ICP application
for a Project Approval Certificate, maximum predicted 1-hour emissions from the ICP
only for NOx, Total Suspended Particulates (TSP), SO2, and CO under distillate oil-fired
operation are 87%, 3700%, 152%, and 12% higher respectively than those under natural
gas-fired operation.




                                        - 51 -
                      TERASEN GAS (VANCOUVER ISLAND) INC.

         RESOURCE PLAN REPORT DATED JULY 8, 2004 (“RESOURCE PLAN”)
        CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION
                  DATED AUGUST 4, 2004 (“CPCN APPLICATION”)

              RESPONSE TO COMMISSION INFORMATION REQUEST NO. 2




ICP operates under Air Permit PA-16080 issued by the Ministry of Water, Land and Air
Protection. Section 2.6.1 of this permit stipulates that, “Oil shall be used as a backup fuel
only during periods when the natural gas supply is curtailed. These periods shall not
exceed a total of 10 days in any calendar year.” The original Permit allowed the Regional
Waste Manager to use his discretion to allow the burning of distillate oil in excess of the
allowable 10 days. In 2001, the Sierra Club of B.C. and Reach for Unbleached! made an
appeal under the Waste Management Act to the BC Environmental Appeal Board to
ensure that the Regional Waste Manager did not use his discretion to authorize the use
of distillate oil as a cost-saving measure. The Panel overseeing the matter concluded
that the Regional Manager should amend Air Permit PA-16080 to allow for the burning of
distillate oil in excess of 10 days only in the case of an emergency; the current Air Permit
reflects this decision. Planned use of distillate in excess of 10 days would require a
revision to the current permit. The air permit allows 10 days in a calendar year; TGVI is
uncertain whether this means calendar days or whether it can be interpreted as 240
hours. In addition, if the maximum number of days was used in the January to March
period of a certain year, this may limit the availability of curtailment for November and
December of the same year.

Should the fuel storage be expanded BC Hydro can, under the terms of the EPA with
Calpine, request fuel switching for up to 240 hours in any continuous 12 month period,
as long as such periods of distillate operation do not exceed 120 hours per year on a 20-
year average. While up to 240 hours per year would be available, to the degree that use
exceeds 120 hours per year the amount available in subsequent years is reduced.
Increased use of distillate may require changes to the EPA.




                                        - 52 -

				
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