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					Terasen Pipelines

2003 Progress Report
Canada’s Climate Change Voluntary
Challenge & Registry Program


October 2003
                                          Terasen Pipelines 2003 Progress Report


Terasen Pipelines – Corporate Overview

Terasen Pipelines (referred to as “Terasen” or the “Company”) is the liquid petroleum
transportation division of Terasen Inc. Terasen’s pipeline systems transport a variety of
petroleum products including crude oil, refined petroleum products and diluted bitumen.
Terasen Pipelines does not own the products in the pipeline but transports them on behalf
of over 35 shippers in Canada and the U.S.

Terasen’s pipelines are –

       TERASEN PIPELINES (TRANS MOUNTAIN) INC.

       This 1,150 km pipeline meets the needs of petroleum producers by transporting a
       variety of petroleum products from Edmonton, Alberta to Kamloops and Burnaby,
       British Columbia. Sophisticated technologies have been developed to transport
       batches of crude oil, condensate, synthetic crude, and refined products including
       gasoline, diesel fuels and aviation fuel through one pipeline.

       TERASEN PIPELINES (JET FUEL) INC.

       This 41 km line transports aviation turbine fuel from refineries and distribution
       facilities located in the Vancouver area to its terminal at the Vancouver
       International Airport.

       TERASEN PIPELINES (PUGET SOUND) CORPORATION

       This 110 km pipeline connects with the Trans Mountain mainline at Sumas,
       British Columbia and delivers Canadian crude oil to refineries in the northwestern
       United States.

       TERASEN PIPELINES (CORRIDOR) INC.

       This 493 km pipeline system commenced operations in 2003. It links the
       Athabasca Oil Sands Project to an upgrader plant and marketing terminals in the
       Edmonton area.

       EXPRESS AND PLATTE PIPELINES

       Terasen Pipelines owns 33% of the Express and Platte systems and operates both
       pipelines. The pipelines connect Canadian and American producers to refineries
       in the U.S. Rocky Mountain and Midwest regions along its approximately 2700
       km route. The Canadian portion of the system is 435 km in length.




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                                          Terasen Pipelines 2003 Progress Report




FAST FACTS

Total pipeline system length:                Total system capacity:
4544 km (2824 miles)                         148,000 m3/d (928,000 bpd)

Terasen Pipeline systems total oil movements in 2002:
                          m3/day              BBL/day
Trans Mountain            32,190              202,600
Jet Fuel                   2,935                18,500
Express/Platte            26,538              167,000
                          61,663              388,100

United States and other offshore markets:
                           m3/day                   BBL/day
Trans Mountain             10,063                    63,300
Express/Platte             26,538                   167,000
                           36,601                   230,300



Terasen Pipelines Inc. is a wholly owned subsidiary of Terasen Inc., a leading provider of
energy and utility services in Western Canada. Terasen Inc. is the new corporate identity
for the group of companies formerly known as BC Gas Inc. Terasen Inc. common shares
are traded on the Toronto Stock Exchange under the symbol “TER”. Information about
Terasen is available on the company’s website at www.terasen.com.




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Table of Contents


Terasen Pipelines – Corporate Overview             2

System Map                                         3

Table of Contents                                  4

Contact Information                                5

Company Commitment                                 6

Introduction                                       7

Terasen’s Approach to GHG Management               8

GHG Inventory
    Direct Emissions                               10
    Indirect Emissions                             13
    Component Greenhouse Gases                     15

GHG Emission Factors                               15

GHG Inventory Methodologies                        16

GHG Projection
    Direct Emissions                               18
    Indirect Emissions                             19

GHG Target                                         23

Measures to Achieve Target
    A: Results Achieved – 1990 through 2002        24
    B: Planned Measures – 2003 through 2007        26

Education, Training and Awareness                  28

Appendix A: Emission Factors                       29

Appendix B: Measure Estimates                      33



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Contact Information
For more information, please contact:

       Dan O’Rourke, P. Eng.
       Manager, Environmental Services
       Terasen Pipelines
       Suite 2700, 300 – 5th Ave., SW
       Calgary, AB
       T2P 5J2

       Phone: 403-514-6641
       Facsimile: 403-514-6627
       e-mail: dan.o’rourke@terasen.com

For more information on Terasen Pipelines, you can also visit Terasen’s web site at
www.terasen.com.




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                                          Terasen Pipelines 2003 Progress Report



Company Commitment
We are pleased to be submitting an updated and expanded submission to Canada’s
Voluntary Challenge and Registry (VCR) program. The VCR program provides an
important service that allows corporations, organizations and individual Canadians a
means with which to demonstrate and publicly report on their voluntary efforts to reduce
GHG emissions. We would also like to take this opportunity to renew Terasen’s
commitment to regularly report on Terasen’s own company’s efforts to manage GHG
emissions.

Terasen Pipelines has made considerable progress in controlling our direct GHG
emissions. These efforts include tank modifications to reduce evaporative hydrocarbon
losses and combustion of hydrocarbon vapour discharged during marine vessel loading.
However, Terasen faces some tough challenges in managing indirect emissions as
Terasen’s pipeline system continues to expand and throughput volumes rise. Unlike most
industries, where economies of scale often lead to efficiency improvements, in liquid
pipeline operations the reverse holds true. As the volume of liquid moved through a
pipeline increases, there is a corresponding exponential rise in the electrical energy
needed to power the pumps. In addition, the shift to proportionately more oil sands
production has led to heavier grades of crude oil, which are more viscous and require
more energy to transport.

As a result, not only are we challenged to reduce indirect emissions from Terasen’s
operations in absolute terms, we are also challenged to reduce emissions on a unit basis.
Fortunately, there are measures that can help improve the efficiency of Terasen’s pipeline
operations and minimize indirect emissions growth. Actions that improve operating
efficiencies deliver not only indirect emission reductions but competitive advantage as
well.

This submission describes the measures we have taken in the past and measures planned
for the future that will help us achieve the GHG target we have set for Terasen’s Trans
Mountain and Jet Fuel operations. In future VCR Progress Reports we will be
incorporating GHG emissions data for Terasen’s Corridor and Express pipeline
operations and looking at new targets for this broader operations base.

As Terasen Pipelines positions itself for growth and increased volumes of throughput in
the medium to long term, Terasen’s challenge will be to implement best GHG practices
and operate in a GHG efficient manner. This VCR report lays out the steps that will help
us achieve this goal.




Richard Ballantyne, President
Terasen Pipelines Inc.
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2003 Submission to the Climate Change Voluntary Challenge and Registry Program
                                                             Terasen Pipelines 2003 Progress Report


Introduction
This year’s submission has been prepared in accordance with the May 2003 VCR
guidelines and covers the Canadian operations of Terasen Pipelines Inc., referred to as
Terasen in this report. The scope of the report includes the operations of Terasen (Trans
Mountain) Inc., referred to as the Trans Mountain system, and Terasen (Jet Fuel) Inc.,
referred to as the Jet Fuel system. Due to its recent acquisition in 2003, the Canadian
portion of the Express system is not covered in this year’s submission. Similarly, the
Corridor pipeline did not begin operations until 2003 and is therefore excluded from this
submission.

This report includes GHG emission data from operations for 1990 through 2002. It is
important to note that the Company implemented measures prior to 1990 which resulted
in significant reductions in GHG emissions. Until the early 1980’s the Trans Mountain
system included a total of 18 diesel powered pump stations. Many of these facilities have
been shut down and in 1990 there were only 10 pump stations in operation. In 2002 there
were eleven. In 1983 and 1984 the diesel motors powering the pumps were removed and
replaced with electric units. A significant decrease in total emissions from the motor
replacement occurred as much of the electricity used on the system is from clean
hydroelectric sources.

Figure 1 shows the GHG emissions profile from Terasen pipeline operations since the
1990 base year. In this report, further detail is provided as to the emission sources and
emission factors used to develop these GHG estimates. As can be seen from Figure 1, the
majority of the Company’s GHG emissions are due to indirect emissions from electricity
production. Electricity is used to power the pumps that move product through the
pipeline system and is the Company’s largest source of energy consumption and GHG
emissions.


                          Figure 1: GHG Emissions from Terasen Operations (t CO2e)

                 90,000
                 80,000
                 70,000
   tonnes CO2e




                 60,000
                 50,000                                                                     Direct (t CO2e)
                 40,000                                                                     Indirect (t CO2e)
                 30,000
                 20,000
                 10,000
                      0
                      90

                             91

                                  92

                                        93

                                             94

                                                  95

                                                        96

                                                             97

                                                                  98

                                                                       99

                                                                             00

                                                                                  01

                                                                                       02
                     19

                           19

                                19

                                       19

                                            19

                                                 19

                                                       19

                                                            19

                                                                 19

                                                                      19

                                                                            20

                                                                                 20

                                                                                      20




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While GHG emissions have increased over 1990 levels, the Company has implemented
GHG efficiency improvements that have helped reduce this emissions growth. Had these
measures not been implemented, emissions would have been 5,100 t CO2e above the
actual levels shown here. These reduction measures are described and quantified in this
report. The Company’s target to reduce GHG emissions by 6% below business as usual
levels by 2007 and the actions that will help meet this target are also discussed.

The report also discusses Terasen’s energy and GHG management system, employee
GHG training and community-based tree planting initiatives.


Terasen’s Approach to GHG Management
The Company’s Environmental Management System (EMS) is based on ISO 14001. The
Company’s internal Health, Safety and Environment Committee, which includes
members of senior management and executives, oversees decisions with respect to the
EMS, including those pertaining to GHG issues. There is also a Board of Directors’
Environment and Safety Committee responsible for oversight of the Company’s
environmental management. Both of these committees are updated on a regular basis
with regard to climate change matters.

Terasen is also actively engaged in the climate change issue through its membership in
the Canadian Energy Pipelines Association (CEPA), where company representatives sit
on both the Environmental Committee and Climate Change Sub-Committee.

The Company environmental awareness training materials contain a section on
greenhouse gas emissions, and although Terasen’s operations are not a significant source
of direct GHG emissions, employees are encouraged to conserve energy in their use of
the Company’s buildings and vehicles.

Indirect emissions from the production of electricity used in Company operations account
for approximately 96% of the total emissions inventory. Purchased electricity also
represents the largest cost item in the operating budget. Consequently, any actions that
reduce electrical consumption improve both the GHG performance and business
competitiveness. In addition, Terasen is mid-way through a five-year toll settlement with
shippers that provides shippers with toll stability while offering incentives to the
company to benefit from any realized efficiencies and savings associated with pipeline
operations.

Electrical energy efficiency is a critical driver for Terasen’s GHG management program
and the Company has recently formed a Power Management Committee with the
mandate to reduce power costs and energy consumption. Part of this committee’s work
will involve a review of equipment and operating procedures to identify areas where
electrical energy consumption and demand costs can be reduced. This initiative should
identify associated GHG reduction benefits as well.

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Besides Terasen’s own efforts to manage electricity consumption, electricity suppliers are
also undertaking actions to reduce the GHG intensity of electricity supply through the use
of lower emitting and more energy efficient fossil fuel generation and alternative energy
production such as wind power. For example, since 1990, the GHG intensity of Alberta’s
power grid has decreased 6 %1, primarily due to the increasing proportion of natural gas-
fired power generation in the mix. Additionally, the Company’s electricity suppliers have
implemented GHG offset programs and are pursuing the use of offsets as another means
to reduce the GHG intensity of their electricity supply2.


GHG Inventory
This section provides an overview of GHG emissions from Terasen’s operations. Table 1
shows a breakdown of these emissions by direct and indirect emission categories. Direct
emissions are emissions released at Company owned facilities or from the operation of
Company vehicles. Indirect emissions are “those associated with an outside organization
that supplies energy or services”3. Purchased electricity is the predominant source of
indirect emissions in Company operations. The total operating emissions are also shown
before and net of offset reductions4.

Table 1: GHG Emissions from Operations (t CO2e)

                                                                                Total
    Year      Direct        Indirect          Total         Offsets         (net Offsets)
    1990         2,698           50,997         53,695                0               53,695
    1991         2,329           59,854         62,184                0               62,184
    1992         2,331           64,261         66,592                0               66,592
    1993         2,296           71,642         73,938                0               73,938
    1994         2,176           72,944         75,120                0               75,120
    1995         2,394           75,288         77,682                0               77,682
    1996         2,481           81,786         84,267                0               84,267
    1997         2,457           69,276         71,733                0               71,733
    1998         2,582           81,473         84,055                0               84,055
    1999         2,572           52,055         54,626               53               54,573
    2000         2,513           57,333         59,845              107               59,739
    2001         2,865           78,271         81,136              138               80,997
    2002         3,067           67,015         70,083              147               69,936


1
  The KEFI-Exchange report for Alberta Environment, “Alberta Electrical Generation System’s Average
Greenhouse Gas Emission Intensity” notes that system intensity was 1.045 kg CO2e per kWh in 1990,
0.985 kg CO2e per kWh in 2001.
2
  The indirect emissions GHG inventory numbers in this report do not factor in any GHG offsets acquired
by the electricity suppliers.
3
  VCR’s 2003 “Guide to Entity & Facility-Based Reporting”, p. 1
4
  A GHG offset occurs when a company invests in GHG reduction or sequestration activities outside its
own operation and uses these emission reductions or removals to “offset” its own internal emissions.
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                                                    Terasen Pipelines 2003 Progress Report


Direct Emissions:
The direct GHG emissions sources from Terasen’s operations include:
   • Fugitive losses from vessel loading and tankage due to evaporation – a small
       percentage (about 2%) of these fugitive emissions are methane (CH4) emissions.
   • Combustion emissions from the vapour destruction unit (installed in 1999), which
       burns the VOC5 evaporative emissions from vessel loading.
   • Combustion emissions from the natural gas or propane used for space heating at
       the Company’s terminals, pumping stations and maintenance bases. This category
       also captures fuel used for miscellaneous purposes such as domestic hot water,
       water treatment, etc. The inventory does not include emissions from the energy
       used in leased offices.
   • Combustion emissions from the Company’s vehicles including one helicopter,
       which is used to patrol pipeline rights-of-way.
   • Combustion emissions from the Company’s natural gas and diesel fueled engines,
       which were used to produce power at the Jasper pumping station until February
       1990. Subsequently, Terasen has purchased electricity for this pumping station.

Table 2 provides a summary of these direct GHG emissions for Terasen’s base year,
1990, through 2002.

Table 2: Direct GHG Emissions from Company Operations (t CO2e)


                  Fugitive Emissions Emissions from                 Space                         Total
       Year          from Tanks      Vessel Loading1                Heating       Vehicles        Direct
       1990                       50              105                     415          1,667         2,6982
       1991                       50              197                     415          1,667          2,329
       1992                       50              199                     415          1,667          2,331
       1993                       50              164                     415          1,667          2,296
       1994                       50               44                     415          1,667          2,176
       1995                       50               74                     509          1,761          2,394
       1996                       50              117                     556          1,757          2,481
       1997                       50               81                     504          1,821          2,457
       1998                       50              144                     532          1,856          2,582
       1999                       50              134                     532          1,856          2,572
       2000                       50                 5                    567          1,889          2,513
       2001                       50              305                     620          1,889          2,865
       2002                       50              525                     668          1,823          3,067
Data in italics has been extrapolated from other years’ data.
      1.   Prior to 1999, loading of oil tankers and barges at the Westridge Terminal in Burnaby involved the
           release of significant amounts of evaporative emissions (VOCs), of which about 2% were CH4,
           shown here in terms of CO2 equivalents. In 1999, a vapour destruction unit was installed to
           combust these VOC and CH4 fugitive emissions. This measure, intended to reduce the release of

5
    VOC = volatile organic compounds
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                                                 Terasen Pipelines 2003 Progress Report

        local air contaminants, also eliminated the CH4emissions from vessel loading. From 1999 and
        onward, the emissions shown for this category are the CO2 emissions occurring from combustion
        of the VOCs and the propane fuel used to feed the combustion process.
   2.   1990 direct emissions also include 460 t CO2e from the use of diesel and natural gas to run engines
        for power production at the Jasper pumping station in early 1990. Subsequently, ATCO Electric
        has provided electricity for this station.

Trends in Direct GHG Emissions

   • The 50 t CO2e annual emissions estimate for tank fugitives was developed for
     1990 facilities and does not include any tank upgrades that have occurred in the
     intervening years. It is therefore somewhat conservative for later years, but the
     amounts involved are relatively small.
   • The year to year variability in emissions from vessel loading reflect year to year
     variability in numbers of tankers and barges loaded, as well as a changeover to the
     use of the vapour destruction unit in 1999.
   • Energy used for space heating varies slightly from year to year depending on
     weather conditions. Emissions in this category have also increased due to a water
     treatment system at the Jasper station and conversion of the Gainford station from
     electric to natural gas heating.
   • On the whole however, the Company’s direct emissions are relatively small and
     do not vary substantially from year to year.

Indirect Emissions:
Indirect emissions occur from the Company’s use of purchased electricity. All of the
pipeline pumps use electric drivers and about 99% of electricity use is for pumping
petroleum products. Tank mixers, cathodic protection, lighting, space heating, computer
systems and miscellaneous use consume the remaining 1% of electricity.

The indirect emissions from purchased electricity are summarized in Table 3 for the
period 1990 through 2002. Terasen purchases electricity from three main sources- the
BC electricity grid, the Alberta grid and a plant in Jasper, which is not connected to the
Alberta grid. Emissions have been calculated based on electricity emission factors that
do not account for any GHG offsets that the electricity suppliers may have acquired.




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                                          Terasen Pipelines 2003 Progress Report


Table 3: Indirect (Electricity) Emissions from Company Operations (t CO2e)


                                         Indirect
                      Year        Electricity Emissions
                      1990                50,997
                      1991                59,854
                      1992                64,261
                      1993                71,642
                      1994                72,944
                      1995                75,288
                      1996                81,786
                      1997                69,276
                      1998                81,473
                      1999                52,055
                      2000                57,333
                      2001                78,271
                      2002                67,015
Includes purchased electricity used at all Trans Mountain and Jet Fuel facilities.


Trends in Indirect GHG Emissions

The electricity needed to power the pipeline’s pumps varies with three key variables:

   1. The total quantity of product moved: in other words, the more product moved, the
      more electricity consumed.

   2. The characteristics of the product moved: that is, the weight and viscosity of the
      oil; heavier crude is more viscous and dense than lighter crude and substantially
      more energy is required to move the same volume of heavy crude as lighter crude.

   3. The relationship between volumes moved and the pipeline’s capacity: as
      throughput increases, power requirements increase by multiples of this throughput
      increase. As a pipeline’s throughput nears its maximum capacity, this rise in
      power is even more severe.

This linkage between throughput volumes and associated indirect GHG emissions can be
seen in Figure 2. The higher emissions in recent years can also be attributed to higher
volumes of heavier crude being shipped.




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                                 Figure 2: Indirect GHG Emissions versus
                                                Throughput

                        50,000                                                                 90,000




                                                                                                        Indirect Emissions (tonnes
                        45,000                                                                 80,000
  Throughput (m3/day)




                        40,000                                                                 70,000
                        35,000                                                                 60,000
                        30,000




                                                                                                                  CO2e)
                                                                                               50,000
                        25,000
                                                                                               40,000
                        20,000
                        15,000                                                                 30,000
                        10,000                                                                 20,000
                         5,000                                                                 10,000
                             0                                                                 0
                             90
                                  91
                                       92
                                            93
                                                 94
                                                      95
                                                           96
                                                                97
                                                                     98
                                                                          99
                                                                               00
                                                                                     01
                                                                                          02
                           19
                                 19
                                      19
                                           19
                                                19
                                                     19
                                                          19
                                                               19
                                                                    19
                                                                         19
                                                                              20
                                                                                    20
                                                                                         20
                                            Throughput              Indirect Emissions




Component Greenhouse Gases:

Table 4 contains a further breakdown of the Company’s emissions by component
greenhouse gases, which have been compiled using the EFs listed in Appendix A.

Table 4: Component Greenhouse Gases for 1990 through 2002 (tonnes)

                                                     Direct                                       Indirect

        Year                          CO2             CH4             N2O                 CO2                 CH4                         N2O
        1990                             2,316                  8             0.7            50,423                                   6         1.4
        1991                             1,856                 12             0.7            59,222                                   6         1.7
        1992                             1,856                 12             0.7            63,534                                   9         1.8
        1993                             1,856                 10             0.7            70,838                                  10         1.9
        1994                             1,856                  5             0.7            72,063                                  10         2.0
        1995                             2,024                  6             0.8            74,466                                  10         2.0
        1996                             2,067                  8             0.8            80,847                                  12         2.2
        1997                             2,074                  6             0.8            68,482                                  11         1.9
        1998                             2,127                  9             0.8            80,512                                  16         2.1
        1999                             2,261                  3             0.8            51,409                                  10         1.4
        2000                             2,193                  3             0.8            56,539                                  17         1.4
        2001                             2,545                  3             0.8            77,263                                  18         2.0
        2002                             2,930                  3             0.3            66,128                                  16         1.7



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GHG Emission Factors

Appendix A provides a detailed listing, by year, of the emission factors and emission
factor sources used to compile Terasen’s GHG inventory. These EFs have been applied
to the energy use and fugitive emissions data described below to develop GHG inventory
estimates for the Company’s operations.


GHG Inventory Methodology
This section describes the GHG inventory methodology used to quantify both the base
year and subsequent years’ inventory.

Fugitive Emissions from Tanks

Although the pipeline is a closed system and the petroleum products are transported in a
liquid state, there are small amounts of fugitive CH4 from evaporative loss of product
stored in tanks or during vessel loading. In the case of fugitive methane emissions from
tanks, the primary sources of the loss are roof seals and fittings from external and internal
floating tank roofs. Losses also occur from the thin film of product left on the side walls
of the tank when the tank roof descends on delivery. An inventory estimate was
developed for 1990 tank facilities using API methodology for calculating evaporative
losses from internal and external floating roof tanks. As the volumes involved are
relatively small, this estimate has been applied to subsequent year inventory numbers as
well and represents a conservative estimate that does not factor in tank upgrades that have
been done since 1990.

Evaporative losses of Jet A (kerosene-based) fuel from the Jet Fuel system tankage are
negligible due to the low vapour pressure of this type of petroleum.

Fugitive and Combustion Emissions from Vessel Loading

Ocean-going tankers and barges are loaded with crude oil and condensates at the Trans
Mountain Westridge dock in Burnaby, BC. During loading operations, hydrocarbons are
displaced from the cargo tanks of the vessels into the air. Total hydrocarbon emissions
from a typical tanker loading are approximately 10 tonnes and from a typical barge
loading, approximately 1.4 tonnes.6 Based on an independent analysis of cargo vent
emissions from two tanker loadings in 1994, about 4% of these hydrocarbon emissions
are methane. Thus, CH4 emissions per tanker and barge loading are estimated to be 0.4
tonnes CH4 and 0.06 tonnes CH4 respectively. These unit estimates have been multiplied

6
    Source: API Publication 2514A “Atmospheric Emissions From Marine Vessel Transfer Operations”
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by annual activity data on tanker and barge loadings to develop annual fugitive emissions
estimates for this source from 1990 through 1999.

In 1999, Terasen installed a vapour destruction unit designed to burn the hydrocarbon
(VOC) emissions from vessel loading, thereby eliminating a source of local air
contaminant emissions. Propane is used as the fuel to feed this combustion process. The
1999 and later emissions from vessel loading have been calculated based on the
combustion of propane (billed quantities) and chemical composition of the evaporative
emissions.

Vehicle Emissions

Vehicle emission estimates for earlier years have been developed by applying GHG
factors to the total kilometres driven by fuel type. In 2002, vehicle emissions have been
based on actual fuel purchases by type. The estimate for helicopter fuel consumption is
based on the hours of operation times and hourly fuel use rates. Estimates for some years
have been extrapolated. 1990 baseline year vehicle emissions are assumed to equal 1994
vehicle emissions.

Space Heating

The natural gas and propane fuel used in space heaters and furnaces in the Company’s
facilities is metered and this metered consumption data has been multiplied by the
appropriate emission factors from the VCR Guidelines to estimate emissions from this
category. As noted earlier, estimates for some years have been extrapolated. 1990
baseline year emissions for space heating are assumed to equal 1994 emissions.

Electricity Emissions

The Company has data on billed electricity consumption in kWh, by utility, for all years,
1990 through 2002, with two relatively small exceptions. Data on the consumption of
electricity at non-pumping station sites located in Alberta could not be readily obtained in
time for this report and the estimate for these sites has therefore been pro-rated based the
consumption rates in BC for this category. Estimates of some earlier year Jet Fuel system
pumping stations and three Jet Fuel pumps located at third party locations have been
extrapolated from other years’ data. Both these categories are minor relative to total
electricity emissions.




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                                                 Terasen Pipelines 2003 Progress Report


GHG Projection

Direct Emissions:
The Company’s direct emissions profile does not vary much from year to year and no
significant changes are anticipated going forward. It has been assumed that 2003 through
2007 direct emissions remain at 2002 levels except for emissions from vessel loading.
These are projected based on the average of vessel loading activity levels experienced
from 1990 through 2002.

“Business as Usual” (BAU)7 and “Actual” direct emissions for 1990, and 1999 through
2007 are listed in Table 5. The BAU emissions have been obtained by adding past and
planned measure reductions to the Actual inventory. Although further activities are
planned (see “Measures To Achieve Targets”), we have not included any future direct
emission reduction measures as there are no specific projects identified at this time.
Terasen plans to continue its support of Tree Canada’s tree planting projects and these are
projected to provide a growing quantity of CO2 sequestration credits that will help offset
the Company’s direct emissions.

Table 5: Direct Emissions - BAU, Actual and Reduction from BAU (t CO2e)


                                           Actual                  Reduction
    Year     BAU         Actual         (net Offsets)              from BAU
      1990    2,698         2,698                  2,698                            0
      1999    2,602         2,572                  2,518                           84
      2000    2,514         2,513                  2,406                          108
      2001    2,933         2,865                  2,726                          207
      2002    3,185         3,067                  2,921                          264
      2003    3,103         3,000                  2,831                          272
      2004    3,103         3,000                  2,829                          274
      2005    3,103         3,000                  2,813                          290
      2006    3,103         3,000                  2,797                          306
      2007    3,103         3,000                  2,781                          322
The years 1991 through 1998 have been omitted; no reduction measures have been quantified for
these years and hence BAU equals Actual for those years.




7
 In keeping with the VCR’s 2003 “Guide to Entity & Facility-Based Reporting”, “Business As Usual” or
“BAU” is used to refer to the projection of performance “as if no emission reduction activities had taken
place. This is also called a ‘Reference Case’, ‘Without Emission Reductions’ or ‘Frozen Efficiency
Forecast’”. (2003 VCR Guide, p. 20)
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                                                Terasen Pipelines 2003 Progress Report


Indirect Emissions:

(a) 1990 through 2002

In Table 6, the Actual versus estimated BAU emissions for 1990, and 1996 through 2002
are compared. This BAU estimate has been calculated by adding the reductions from
past measures to estimates of the Company’s actual (with actions) GHG inventory. In
other words, the BAU estimate includes the emissions that would have occurred had
these measures not been implemented. Table 10, in the “Results Achieved” section,
provides further details on these past reduction efforts.

To facilitate comparison, all years have been calculated using 2002 electricity emission
factors. This approach allows better tracking of performance improvement and removes
the variability introduced by changes in the electricity system’s GHG emission
intensities.8

Table 6: Indirect Emissions - BAU, Actual and Reduction from BAU (t CO2e)

    Year             BAU               Actual           Reduction from BAU
       1990             49,282             49,282                                 0
       1996             84,414             79,903                             4,510
       1997             71,177             66,667                             4,510
       1998             83,474             78,759                             4,715
       1999             55,859             51,145                             4,715
       2000             61,164             56,449                             4,715
       2001             81,689             76,972                             4,717
       2002             71,828             67,015                             4,813
 To facilitate comparison, all years have been calculated using 2002 electricity emission factors.
 The years 1991 through 1995 have been omitted; no reduction measures have been quantified
for these years and hence BAU equals Actual for those years.




8
  The VCR’s “Challenge Registry: Guide To Entity & Facility-Based Reporting”, p.2, notes: “This
[approach] meets two important goals:
    • For the current reporting year, it shows the most accurate emissions.
    • For all reporting years, it shows the level of performance improvement over time.
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                                           Terasen Pipelines 2003 Progress Report


It is important to note that there have been other past actions that have not been
quantified as reduction measures but which have contributed to the ability of Terasen’s
system to operate more efficiently and reduced the average kWh per m3 delivered.
Typically these improvements have been associated with station upgrades and expansions
designed to deliver both increased capacity and improved delivery efficiency. These
actions have included:
     • The installation of VFD (variable frequency drive) pump motors at two stations
        on the line; with VFD units you can adjust motor speed to control flow rates and
        this eliminates the need for main-line control valves at stations with VFD motors.
        Control valves introduce friction losses on the line and increase the electrical
        power required to move product.
     • The installation of energy efficient electric motors and transformers as older units
        have been replaced with larger capacity units and in new pumping stations.
     • Replacing HSB pumps with HSD pumps; the latter pump style has a diffuser
        assembly that can be changed out along with an impeller to give different pump
        characteristics. The Trans Mountain pipeline moves a variety of products from
        lighter weight refined products and crude to heavier crude. Depending on the
        duration of product batches running through the system, it can sometimes be cost-
        effective to change impellers to match product flow characteristics.

It is difficult to isolate and quantify the effect of many of these measures. The
characteristics of the product in the line at any time impact power requirements. Also, as
throughput increases, the power required to pump a given volume of petroleum also
increases. Therefore, a pipeline operating at a lower flowrate will be much more efficient
with respect to electrical consumption per unit throughput than a similar pipeline
operating at a higher flowrate. The 1990 through 2002 BAU estimate is therefore a
conservative (under) estimate of BAU emissions.

(b) 2003 through 2007

Looking forward, expansion of the Trans Mountain pipeline system to increase capacity
for both light crude and mixtures of light and heavy crude is being contemplated. This
will enable Terasen to meet the growing transportation needs of producers who are
expanding their markets to the west and offshore. Depending on shipper and regulatory
approval, the first phase of this two-phase expansion will be operational in late 2004 and
involve reactivating an inactive loop between Darfield and Kamloops, “repowering”
existing pump stations, and modifying tankage. In Phase two, new pump stations will be
added, subject to shipper agreement. The two-phase expansion project will result in
capacity increases of 45,000 barrels per day, a 16% increase in existing capacity.

It is anticipated that future electricity consumption and indirect emissions will increase as
this planned expansion allows throughput volumes to increase although unit energy
consumption (kWh/m3) may improve. There will also be an increase in emissions as the
business moves proportionately more heavy crude in future. Higher heavy crude volumes
will result in GHG increases even if the planned expansion does not proceed.
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                                              Terasen Pipelines 2003 Progress Report


For this report, a simplified approach for the projection has been used, shown in Table 7,
which assumes that throughput volumes will increase (with the proposed expansion) and
that proportionately more heavy crude will be shipped; however this projection does not
attempt to model the system hydraulics under these new operating conditions. This
preliminary projection has been developed as follows:

    1. Energy consumption is based on historical data of energy use per unit of
       throughput and not on new system hydraulics.

    2. The estimate has been adjusted to account for increasing proportions of heavier
       crude throughput, which increases energy use.

    3. Past and planned electricity reduction measures are incorporated into the BAU
       and Actual projections, and the associated indirect GHG emissions are allocated
       based on supplier (BC grid, Alberta grid, or Jasper power plant.)

Table 7: Indirect Emissions Projection- BAU, Actual and Reduction from BAU
(t CO2e)

    Year             BAU               Actual          Reduction from BAU
       2003                71,904          66,916                       4,988
       2004                83,269          78,106                       5,163
       2005                90,412          85,074                       5,338
       2006                94,731          89,218                       5,513
       2007                99,050          93,362                       5,688
To facilitate comparison, all years have been calculated using 2002 electricity emission factors.


It should be noted that this projection relies on several simplifying assumptions, which
makes the projection somewhat uncertain and subject to change. The projection of both
direct and indirect emissions has been graphed in Figure 3. Table 8 provides a further
breakdown of the projection into component GHGs.




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2003 Submission to the Climate Change Voluntary Challenge and Registry Program
                                                          Terasen Pipelines 2003 Progress Report




                          Figure 3: GHG Emissions Projection (Actual) -
                                    Indirect and Direct (t CO2e)

                120,000

                100,000
  tonnes CO2e




                 80,000
                                                                                 Direct (net Offsets)
                 60,000
                                                                                 Indirect
                 40,000

                 20,000

                     0
                            2003         2004      2005     2006      2007




Table 8: GHG Projection By Component Greenhouse Gases (tonnes)

                                          Direct                                  Indirect

     Year                   CO2             CH4           N2O          CO2             CH4              N2O
     2003                         2862             3            0.2          66,030          16               1.7
     2004                         2862             3            0.2          77,072          18               2.0
     2005                         2862             3            0.2          83,947          20               2.2
     2006                         2862             3            0.2          88,036          21               2.3
     2007                         2862             3            0.2          92,125          22               2.4




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                                             Terasen Pipelines 2003 Progress Report


GHG Target
As noted in the previous section, GHG emissions from Terasen’s operations are projected
to increase as throughput increases and proportionately more heavy crude is transported
through the system; however, it is planned to continue efforts to minimize emissions
growth through internal energy efficiency efforts and offsets. These efforts are described
in the next sections.

Table 9 summarizes the future projection of direct and indirect emissions and notes that
the target is to reduce total GHG emissions by just over 6,000 t CO2e (or 6%) below
BAU levels by 2007. Through the Power Management Committee, annual GHG
inventory work and VCR reporting, Terasen will monitor its performance to this target
and the GHG target will be reviewed each year and revised if warranted.

Table 9: GHG Emissions Projection- BAU and Actual (tonnes CO2e)


                                                             Reduction from Reduction from
                        Actual                 Actual              BAU             BAU
Year BAU           (before Offsets)        (after Offsets)   (before Offsets) (after Offsets)
2003 74,983                    69,892                 69,723            5,091            5,260
2004 86,348                    81,082                 80,911            5,266            5,437
2005 93,491                    88,049                 87,863            5,441            5,628
2006 97,810                    92,194                 91,991            5,616            5,819
2007 102,129                   96,338                 96,119            5,791            6,010
Includes both direct and indirect emissions. All future years have been projected using 2002
electricity EFs.




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                                             Terasen Pipelines 2003 Progress Report


Measures To Achieve Target

A: Results Achieved - 1990 through 2002

Since 1995, Terasen has implemented several GHG reduction measures. These are
summarized by category and source in Table 10 and described in more detail below. As
can be seen from Table 10, measures have already been implemented that achieve 84% of
the 2007 target. Appendix B provides further details on how these measure estimates
have been calculated.

Table 10: Cumulative Annual GHG Emissions Reduction from Business as
Usual- Results Achieved From 1996 through 2002 (t CO2e)

                                   1996     1997     1998      1999     2000     2001     2002
Direct Emission
Reductions                              0        0         0      30         1       68     118
Reduce CH4 emissions
from vessel loading
Indirect (Electricity)
Emission Reductions
Installation of energy                  0        0      205      205      205      207      209
efficient control valve
actuators
Operate system to
minimize control valve             4,510 4,510 4,510 4,510 4,510 4,510 4,510
throttling
Convert station from
electric to natural gas                 0        0         0        0        0        0       94
space heating
External (Offset)
Reduction Measures                      0        0         0      53      107      138      147
Tree planting
Total                              4,510 4,510 4,715 4,798 4,823 4,923 5,078
Total as a % of 2007
Reduction Target                    74%      74%       77%      79%      79%      82%       84%
Note that no reduction measures have been quantified for years 1990 through 1995 and therefore
these years have been omitted from the above table. To facilitate comparison, all years’ indirect
GHG reductions are calculated using the 2002 EFs.




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                                          Terasen Pipelines 2003 Progress Report


Reduction Measure Information

   •   Reducing CH4 from vessel loading: As noted earlier, the installation of the
       vapour destruction unit at Terasen’s vessel loading facilities has allowed for the
       destruction (i.e., combustion) of VOC emissions, including CH4, that were
       previously vented from vessels for safety reasons before loading could take place.
       The estimated impact of this reduction measure varies with the number of vessel
       loadings each year.
   •   Installing more energy efficient valve actuators: Unlike their older counterparts,
       energy efficient control valve actuators require minimal electricity to operate and
       do not require heaters; each valve actuator replacement saves an estimated 67,000
       kWh per year. At this time, over 60% of the Company’s valve actuators have
       been upgraded.
   •   Reducing control valve throttling: In late 1996, the Company introduced an
       internal operating practice to reduce the use of control valve throttling as a means
       of controlling flow rate. Previously, station control valves would be partially
       closed in order to match daily flow requirements. Under current practice, when
       operating at less than full capacity, it is attempted to keep all control valves open
       and “trim” the flow rate through either balancing power using one of the VFD
       (variable frequency drive) motors on the pipeline or by adding or removing
       pumping units as required. This practice reduces both the pressure losses at the
       valve locations and power consumption. However, when the pipeline nears
       capacity, all pumping units are typically operating to maximize throughputs and
       this often results in control valves being partially closed as a means of controlling
       excess pressure.
   •   Tree Canada tree planting projects: Terasen has been a sponsor of Tree Canada’s
       tree planting projects since 1998. In that time, Tree Canada has planted over
       15,000 trees on Terasen’s behalf in a mix of afforestation, rural and urban tree
       planting projects.




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                                                 Terasen Pipelines 2003 Progress Report


B: Planned Measures- 2003 through 2007
Measures to Reduce Direct Emissions

In the past, Terasen has participated in electrical efficiency programs such as Power
Smart and JEEP (Jasper Energy Efficiency Project), converted facilities to less GHG-
intensive energy sources, insulated buildings as required, and taken other similar
measures. The opportunity for further reductions in direct emissions is not thought to be
significant; however, it is planned to continue looking for energy reduction opportunities
and to implement those that make economic sense.

It is also planned to continue participating in Tree Canada’s tree planting projects. By
2007, the GHG sequestration from these new projects is estimated to be approximately 90
t CO2e per year, bringing the total estimated carbon sequestration rate from past and
future projects to over 200 t CO2e per year.

Measures to Reduce Indirect Emissions

The newly formed Power Management Committee is undertaking a review of operating
practices and equipment with the view to identifying potential electricity cost-saving
opportunities. While finding any major untapped opportunities is not anticipated, even
small efficiencies can translate into cost savings and GHG reductions when applied
throughout the system. The following are some of what will likely be a broader portfolio
of measures to be considered for implementation over the next 5 years.

Potential measures include:

    •   Tank mixer use optimization: Most of the Trans Mountain petroleum storage
        tanks have mixers, which operate regularly to keep product blended and to
        prevent wax build up in the tanks. The Company is currently investigating the
        operational feasibility of changing tank mixing operations with the aim of saving
        electricity. As part of this study, a new jet nozzle tank cleaning system to remove
        wax build-up that might occur if tank mixers were removed or operated less
        frequently is being considered. While this study has not been completed, it is
        estimated that even a 5% annual savings in tank mixer energy consumption could
        potentially reduce emissions by over 200 t CO2e9 per year.

    •   Additional installations of energy efficient control valve actuators: Each
        additional valve actuator upgrade could reduce annual GHG emissions by 35 t
        CO2e.


9
 There is a considerable range in the GHG benefits from saving a kWh of energy depending on the source
of electricity supply- i.e., the Alberta grid, BC grid or Jasper Palisades Power Plant. For simplicity, a
weighted average 2002 electricity factor of 0.552 kg CO2e per kWh to estimate possible savings from
future measures has been used.
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2003 Submission to the Climate Change Voluntary Challenge and Registry Program
                                          Terasen Pipelines 2003 Progress Report


   •   Energy efficient operating practices: Terasen will continue to implement
       operating procedures such as minimizing control valve throttling and changing
       out pump impeller and diffuser assemblies when conditions permit. Potential
       savings from these practices are difficult to predict and quantify, but savings from
       operating practices that have already been implemented (such as reduced control
       valve throttling) are assumed to persist.
   •   The station upgrades and repowering and looping of a section of the pipeline
       associated with the proposed system expansion will also deliver electrical
       efficiency benefits should it proceed.

Although plans for specific measures have yet to be finalized, we have set a future target
to implement new electricity reduction measures to achieve an 875 t CO2e reduction
below BAU levels by 2007 has now been set. On average, this will require implementing
new measures equal to 175 t CO2e per year. The ability to meet this target will depend on
the operational and economic feasibility of the measures being investigated and larger
project investments may require shipper and/or regulatory approval. Additionally, these
targets may have to be modified in future years to reflect new expansion plans.

Table 11 summarizes the planned direct, indirect and offset emission reduction measures
planned for 2003 through 2007.

Table 11: Cumulative Annual GHG Emissions Reduction from Business as
Usual- Planned New Measures for 2003 through 2007 (t CO2e)

                                               2003 2004 2005 2006 2007
Direct Emission Reductions                        0    0    0    0    0

Indirect Emission Reductions                     175     350     525     700     875

External (Offset) Reduction Measures              22      24      40      56      72
Tree Canada projects
Total                                            197     375     565     756     947

Total as a % of 2007 Reduction Target            3%      6%      9%     13%     16%




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2003 Submission to the Climate Change Voluntary Challenge and Registry Program
                                          Terasen Pipelines 2003 Progress Report


Education, Training and Awareness
Since 1998, the Company’s environmental training program for all employees has
included a discussion about greenhouse gas emissions. An article on the climate change
issue has also been added to Terasen’s internal intranet site.

To encourage GHG efficient transportation, Terasen covers the cost of monthly bus
passes for Calgary employees. The Company head office, located in the Stock Exchange
Tower in Calgary, is also undergoing an energy efficiency retrofit. The building’s
managers have recently upgraded fluorescent lighting and further work is planned-
including photocells to control exterior lighting and light wipe systems that automatically
turn off lights on a schedule. To complement this initiative, Terasen’s intranet posted
climate change information will feature information for how employees can save energy
at the office, on the road and in their homes.




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                                               Terasen Pipelines 2003 Progress Report


Appendix A: Emission Factors

Global Warming Potentials:
Some greenhouse gases have a greater ability to trap heat in the atmosphere than others.
In order to compare GHG’s on a common basis they are typically converted to carbon
dioxide equivalents (CO2e) by multiplying their mass by a factor referred to as “Global
Warming Potential” or GWP. GWP is “a measure of the relative radiative effect of a
given substance compared to CO2, integrated over a chosen time horizon.”10

As per the 2003 VCR Guide, the following GWPs (based on a 100-year period) have
been used:

CO2: GWP = 1

CH4: GWP = 21

N2O: GWP = 310

Direct GHG Emission Factors:
Fugitive Emissions:

        Tank Evaporative Emissions:
        For tank evaporative emissions, API protocols11 for calculating tank evaporative
        losses have been applied to develop estimates of evaporative emission rates.
        These in turn have been adjusted to reflect the estimated percent CH4 composition
        in fugitive emissions based on sampling at the Company’s facilities.

        Vessel Loading Evaporative Emissions:
        Total hydrocarbon emissions from a typical tanker loading is approximately 10
        tonnes and from a typical barge loading, approximately 1.4 tonnes.12 Based on an
        independent chemical analysis of cargo vent emissions from two tanker loadings
        in 1994, about 4% of these hydrocarbon emissions are methane. Thus, CH4
        emissions per tanker and barge loading are estimated to be 0.4 tonnes CH4 and
        0.06 tonnes CH4 respectively.




10
   IPCC Working Group 1, Technical Summary, 2001, p.46
11
   API Publication 2517 “Evaporative Loss from External Floating-Roof Tanks” and API Publication 2519
“Evaporative Losses from Internal Floating-Roof Tanks.”
12
   Source: API Publication 2514A “Atmospheric Emissions from Marine Vessel Transfer Operations”.
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                                             Terasen Pipelines 2003 Progress Report


Combustion Emissions:

       Vapour Destruction Unit:
       In 1999, Terasen installed a vapour destruction unit designed to burn the
       hydrocarbon (VOC) emissions from vessel loading. Propane is used as the fuel to
       feed this combustion process. Combustion emissions from vessel loading have
       been calculated based on the combustion of propane (billed quantities) and
       chemical composition of the evaporative emissions, assuming 100% conversion to
       CO2. The emission factors used are:
       Propane: 1.500 kg CO2/litre (2003 VCR Guide)
       VOC evaporative emissions: 3.03 kg CO2/kg VOC (based on chemical
       composition of field samples)

       Vehicles:

       Vehicle emissions for earlier years’ have been developed by applying the
       following GHG factors to the total kilometres driven by vehicle fuel type.

               Fuel             CO2     CH4    N2O       CO2e
                             (kg/km) (g/km) (g/km)    (kg/km)
       Light duty (gasoline)      0.39   0.07    0.28     0.47827
       Heavy duty (diesel)        1.09   0.15    0.08     1.11795
       Source: Mr. A. Jaques, Environment Canada, based on "Canada's Greenhouse Gas
       Emissions: Estimate for 1990", Report EPS 5/AP/4, December, 1992

       In 2002, vehicle emissions have been based on actual fuel purchases by type. The
       estimate for helicopter fuel consumption is based on the hours of operation and
       hourly fuel use rates. The following emission factors by fuel type have been used:

                                 CO2            CH4       N2O           CO2e
       Vehicle fuel              kg/l           kg/l      kg/l           kg/l
       Light truck (gasoline)         2.36      0.00019    0.00041            2.491
       Heavy truck (diesel)           2.73      0.00012    0.00008            2.757
       Propane vehicle                 1.5      0.00052   0.000028            1.520
       Jet fuel                       2.55      0.00008    0.00025            2.629
       Source: 2003 VCR Guide




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                                          Terasen Pipelines 2003 Progress Report


       Space Heating:

       The emission factors for the natural gas and propane used in the Company’s space
       heating equipment have been taken from the 2003 VCR Guide and are listed
       below:

       Fuel                CO2                CH4                N2O                CO2e
       Natural Gas         1.891 kg/m3        0.000037 kg/m3     0.000033 kg/m3     1.902 kg/m3
       Natural Gas         50.79 kg/GJ        0.00099 kg/GJ      0.00089 kg/GJ      51.088 kg/GJ
       Propane             1.500 kg/l         0.000024 kg/l      0.000108 kg/l      1.534 kg/l
        Adapted from Table 3, 2003 VCR Guide; natural gas per m3 EFs have been multiplied by
       26.86 to convert to EFs in kg/GJ; component gas EFs have been multiplied by their
       respective GWPs to obtain kg CO2e EFs.

       Self-Generation:
       A small quantity of natural gas and diesel fuel was burned in early 1990 to
       produce electricity from company-owned engines, before the change-over to
       using purchased electricity took place. The natural gas EF’s for this fuel use are
       assumed to be the same as for space heating above. The diesel engine emissions
       have been estimated using the EF 2.819 kg CO2e/litre. (Source: “Global Climate
       Change Voluntary Challenge Guideline, June 2000, CAPP Pub. #2000-0004, p.
       13, posted on the VCR website)




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Indirect (Electricity) Emission Factors

The following tables denote the electricity emission factors used to estimate the Company’s indirect GHG emission

                            1990     1991   1992    1993    1994    1995   1996    1997    1998    1999    2000    2001     2002
Alberta grid (kg CO2e/kWh) 1.0447 1.05485 1.06095 1.05905 1.063211.05788 1.04883 1.05406 1.03141 1.02183 1.00056 0.985430.992788
  CO2/kWh                     1.033 1.044     1.049   1.047    1.05 1.046    1.037   1.042   1.019   1.009   0.986   0.972 0.97922
  CH4/kWh                 0.000107 0.000090.0001340.0001360.0001350.000120.0001360.0001490.0001990.0001870.000309 0.000240.000238
  N20/kWh                 0.000029 0.00003 0.000030.000029 0.000030.000030.0000290.0000290.0000280.0000280.0000260.0000260.000026
BC grid (kg CO2e/kWh)        0.019 0.012       0.02   0.045   0.044 0.059    0.012   0.021   0.035  0.025    0.042   0.056 0.0325
BC grid (w line loss)
(kg CO2e/kWh)                 0.020 0.013     0.021   0.048   0.047 0.062    0.013   0.022   0.037  0.026    0.044   0.059   0.034
Jasper Palisades plant
(kg CO2e/kWh)                 0.790 0.790     0.790   0.790   0.790 0.790    0.790   0.790   0.790  0.790    0.790   0.790   0.790
  CO2                         0.779 0.779     0.779   0.779   0.779 0.779    0.779   0.779   0.779   0.779   0.779   0.779    0.779
  CH4                      0.00020 0.00020 0.00020 0.00020 0.000200.00020 0.00020 0.00020 0.00020 0.00020 0.00020 0.00020 0.00020
  N2O                      0.00002 0.00002 0.00002 0.00002 0.000020.00002 0.00002 0.00002 0.00002 0.00002 0.00002 0.00002 0.00002
Table Notes:
   1. The Alberta grid EFs are from spreadsheets prepared by the KEFI-Exchange for Alberta Environment for the report: “Alberta
       Electrical Generation System’s Average Greenhouse Gas Emission Intensity.” These EFs include an allowance for delivery
       losses of about 5.7%. 2002 EFs are taken as the mid-point between the high and low EF forecasts in the KEFI-Exchange report
       for 2002.
   2. The BC grid EFs are assumed to be the same as the BC Hydro system EFs taken from BC Hydro’s 2002 VCR report. The 2002
       EF is estimated based on the unweighted average of the 1990 through 2001 EFs.
   3. For comparability to the Alberta factors, these BC factors have been adjusted to include delivery losses (estimated at 5.7% as
       in the KEFI-Exchange estimates).
   4. Because no breakout of BC electricity factors is available and because the amounts of CH4 and N2O emissions from electricity
       purchased in BC would be very small (not material), it has been assumed that BC grid electricity is 100% CO2.
   5. The Jasper Palisades Plant EFs are for 2002 and were obtained from ATCO Electric. Prior years are estimated at the 2002 rate.
       Since the Jasper plant is not on the Alberta power grid, emissions from it have been treated separately. No allowance has been
       made for delivery losses since this power plant is located adjacent to the Jasper pumping station.
   6. For future years, all EFs for all three systems are projected at 2002 rates.
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                                               Terasen Pipelines 2003 Progress Report


Appendix B: Measure Estimates
Table B-1 provides a brief description of the methodologies

Reduction Measure                  Quantification Methodology
Reduce CH4 emissions               Field sampling and chemical analyses of vessel
from vessel loading                loading VOC emissions provided a baseline of the
                                   CH4 emissions per unit volume of VOC emissions.
                                   CH4 emissions avoided by using the vapour
                                   destruction unit are based on this unit estimate,
                                   vessel and tanker loading activity in each year and
                                   API factors for volumes vented.
Installation of energy             The estimated average annual electricity savings for
efficient control valve            each actuator replacement is based on
actuators                          manufacturers’ data. This estimate is applied to the
                                   number of upgrades multiplied by the appropriate
                                   electricity EF.
Operate system to                  The estimated system-wide HP savings from this
minimize control valve             measure is based on the judgment of Operations
throttling                         staff based on pre- and post- measure operating
                                   experience and this estimated HP savings is
                                   assumed to occur for all hours of operations.
Convert station from               The 2002 natural gas consumption for the Gainford
electric to natural gas            station is used as the basis for this estimate.
space heating                      Assuming end-use efficiencies for natural gas and
                                   electricity of 75% and 98% respectively, the pre-
                                   conversion electricity consumption is estimated
                                   based on this energy data and converted to GHG
                                   emissions using the appropriate electricity EF. The
                                   difference in pre and post conversion emissions is
                                   the estimated reduction.
Tree Canada tree                   For 1999 and 2000, estimated annual CO2 removals
planting projects                  is based on the certificate issued by Tree Canada for
                                   an 80 year lifespan. A simplifying assumption is
                                   made that each year sequesters an equal amount of
                                   carbon. For 2001 and later years, estimated annual
                                   CO2 removals are estimated using Tree Canada’s
                                   formula for urban tree planting projects which also
                                   assumes an equal annual sequestration rate.13

Although there has been no third party verification of these results, with access to the
original data sets, these documented reduction estimates could be replicated.


13
     “What Trees Can Do To Reduce Atmospheric CO2”, Tree Canada Foundation, www.TreeCanda.ca
______________________________________________________________ 31
2003 Submission to the Climate Change Voluntary Challenge and Registry Program

				
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