TERASEN GAS (VANCOUVER ISLAND) INC REVENUE REQUIREMENT. Workshop Presentation. August 31, 2005

TERASEN GAS (VANCOUVER ISLAND) INC. 2006 2007 REVENUE REQUIREMENT Workshop Presentation August 31, 2005

Review of Agenda Scott Thomson Vice President Finance and Regulatory Affairs

Workshop Agenda 1. Welcome & Introduction 2. Application Review 3. Proposed Review Process 4. Wrap-up 3

Application Review Approvals Sought in Application Background Information Key Planning Assumptions Core Sales and Transportation Demand and Revenue Capital Requirements Rate Base Financing and Capital Structure Gas Supply & Cost of Gas Utilities Strategy Project and O&M Requirements Accounting, Tax, and other Cost of Service Issues RDDA Customer Rates & Cost of Service Key Planning Assumption Sensitivities Application Review process Wrap-up Tom Loski Tom Loski Tom Loski James Wong Scott Barbour Tom Loski Tom Loski Tania Specogna Tom Loski Brian Noel Brian Noel Tom Loski Tom Loski Tom Loski Tom Loski 4

Review of Approvals Sought in Application Tom Loski Director of Regulatory Affairs

Application Requests and Specific Items Forecast Rates and Revenues for 2006 & 2007, Forecast Cost of Service for 2006 & 2007, Gross O&M Expenditures for 2006 & 2007, Approval of Capital Expenditure forecast for 2006 & 2007, Continuation of Deferral Accounts for Pension & Insurance variances, Approval of Deferral Account treatment for various items, including Recovery of LNG Development Costs, Approval of RDDA Balance to Dec 31, 2004, Overhead Capitalization rate of 16% of gross O&M Expenses, Departure from using portion of Uniform System of Accounts for recording its O&M expenses (Accts. 600 999) as per TGI, Review of Application via a Negotiated Settlement Process. 6

Background Information

Background Information Key Agreements VIGJV Transportation Services Agreement ( JV TSA ) Peaking Gas Management Agreement ( JV PGMA ) BC Hydro Transportation Services Agreement ( BCHTSA ) Peaking Gas Management Agreement ( BCHPA ) Compressor Facility Agreement ( CFA ) Capacity Assignment Agreement ( CAA ) Expire on October 31, 2005 Terasen Gas (Squamish) Inc. Transportation Service Agreement Special Direction and VINGPA 8

Background Information 2003-2005 Revenue Requirement Settlement Application Submitted in July 2002 Agreement reached via Negotiated Settlement (Order No. G-2-03) Set out several items including: Term of settlement, items at risk for TGVI, Gross allowed O&M expenditures, depreciation rates, amortizations, Capital expenditure forecasts, Gas Cost Variance Account ( GCVA ), capital structure and ROE, treatment of revenues in respect of the Revenue Deficiency Deferral Account ( RDDA ) Annual Review Process for rate setting and advising of forecast changes Held and approved in 2003 (G-81-03) and 2004 (G-113-04) 9

Background Information 2003 Rate Design Application Submitted in July 2002 Dec 02 - Participants unable to reach a Negotiated Settlement agreement Dec 02 - Interim Rate Application Filed and approved (G-97-02) Jan 03 Rate Design process established via Oral public hearing process June 03 Commission approved the following effective Jan 1/03: Core Class segmentation and Core Customer rates Firm and Interruptible Transportation rates Recovery of certain COSA and Rate Design Costs Appeals upheld Commission Decision 10

Background Information CPCN for LNG Storage Facility at Mt. Hayes In order to meet demand forecasts for electrical generation and core demand, TGVI submitted its CPCN for the Mt. Hayes LNG Storage Facility in June 2004 Approved on Feb 2005 subject to certain conditions: LNG Storage & Delivery Agreement ( LNG S&DA ) between TGI & TGVI EPC bid price will not exceed 110% of $75.9M (i.e. $83.5M) Long term TSA to serve IPC and Duke Point Power Project executed and approved prior to construction commencement CPCN terminates if construction has not begun by Dec 31, 2005 TGI & TGVI submitted its LNG S&DA, approved by Order G-44-05 April 2005 TGVI entered EPC Contract with HCBI within EPC bid price constraint Extensive discussions held with BC Hydro agreed to terms of long term TSA, however June 2005 BC Hydro abandoned Duke Point Power Project TGVI requesting approval for recovery of all costs incurred in the development of the LNG Facility 11

Key Planning Assumptions

Key Planning Assumptions Demand Assumptions Revised Customer Additions and Use-Rate forecasts Transportation Agreements BC Hydro Service Agreements Firm contract demand for ICP of 45,000 GJ/day Peaking gas quantity of approximately 23 TJ in 06 & 29 TJ in 07 TGVI will purchase Texada Compressor end of 2006 No pressure support at Eagle Mountain ROE and Capital Structure Return on Equity @ 9.04% (current benchmark +75 bps premium) Capital structure of 60% Debt / 40% Common Equity Long Term Debt issue of $250 million Cost of Gas Based on long term price forecast by GLJA (July 8/05) + $0.51/GJ for Midstream costs Royalty Revenue Credit calculated as per VINGPA Schedule 29 Section 11 Inflation 3% per year Alternative Fuels Electricity increases of 1% per year Oil based on July 13 of NYMEX forward strip, using current discounting factors for rate classes 13

Core Sales and Transport Demand and Revenue James Wong Manager, Market Planning and Development

Outline BC Economy New Housing Outlook Customer Additions - 2005/06/07 Key Drivers 2005 Projection and 2006 / 2007 Forecasts Total Demand and Revenue Forecast Forecast Risks 15

BC Economy Five year conventional mortgage rate Unemployment rate 9.0% 10.0% 8.0% 9.0% 7.0% 6.0% 5.0% 8.0% 7.0% 6.0% 5.0% 4.0% 4.0% 3.0% 3.0% 2.0% 2.0% 1.0% 1.0% 0.0% 1997 1998 1999 2000 2001 2002 2003 2004 2005 Fcst 2006 Fcst 2007 Fcst 0.0% 1997 1998 1999 2000 2001 2002 2003 2004 2005 Fcst 2006 Fcst 2007 Fcst Gross domestic product Housing starts $160,000 $150,000 $140,000 $130,000 $120,000 $110,000 ~ 3% per year 6.00% 5.00% 4.00% 3.00% 2.00% 1.00% 40,000 35,000 30,000 25,000 20,000 15,000 $100,000 1997 1998 1999 2000 2001 2002 2003 2004 2005 Fcst GDP (1997 millions) 2006 Fcst GDP (1997 millions) - annual growth rate 2007 Fcst 0.00% 10,000 5,000-1997 1998 1999 2000 2001 2002 2003 2004 2005 Fcst 2006 Fcst 2007 Fcst 16

2005 CMHC Housing Starts by region (June 2005) TOTAL - 33,600 (previous 32,400) 8,275 Starts All Other Areas 2,550 Starts Victoria 2,425 Starts Kelowna 19,400 Starts Vancouver 950 Starts - Abbotsford 17

Drivers of Gas Installation Activity New Construction New Housing Starts New Housing Mix Single Family Dwelling Multi Family Dwelling 60% 40% 18

Drivers of Gas Installation Activity Conversions 6,000 5,000 4,000 # of Conversions 3,000 2,000 1,000-1997 1998 1999 2000 2001 2002 2003 2004 19

TGVI Service Areas Housing Starts Mix of Dwellings Forecast 3,000 # of Housing Starts - TGVI Service Area 2,500 2,000 1,500 1,000 500-1997 1998 1999 2000 2001 2002 2003 2004 2005 Fcst 2006 Fcst 2007 Fcst Single Family Dwelling Multi Family Dwelling 20

TGVI Customer Additions Forecast 10,000 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000-1997 1998 1999 2000 2001 2002 2003 2004 2005 Fcst 2006 Fcst 2007 Fcst Net Customer Additions Housing Starts 21

Residential Customer Additions History Residential Customers Comparison Actuals vs Forecast - 1998 to 2004 TGVI 20,000 18,000 # of Residential Customer Additions 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2,000-1998 1999 2000 2001 2002 2003 2004 Budget Actual 22

Total Demand and Revenues 40,000 35,000 30,000 Terajoules 25,000 20,000 15,000 Residential Commercial Transportation 10,000 5,000-2003 2004 2005 Fcst 2006 Fcst 2007 Fcst $200,000 $180,000 Total Demand Revenues $160,000 $140,000 $120,000 $100,000 $80,000 $60,000 $40,000 $20,000 Residential Commercial Transportation $- 2003 2004 2005 Fcst 2006 Fcst 2007 Fcst Total Revenues 23

Forecast Risks Increase in interest rates, slow down in new construction Rising construction costs, shortage of skilled trades workers Stronger Canadian dollar and decreased competitiveness in export market i.e. forest industry Effects of sustained high natural gas and energy prices and on the economy Real estate bubble bursting? 24

Capital Requirements Scott Barbour Capital Management Office (CMO) Manager

2006 and 2007 Capital Requirements Estimated capital requirements for 2006 and 2007 are presented under the following categories: Regular Capital Additions (Mains, Services, and Meters) Transmission and Distribution Systems (Integrity and Reliability) Non-IT Capital IT Projects CPCN s (Certificates of Public Convenience and Necessity) Other (Overheads Capitalized and Contribution in Aid of Construction ("CIAC")) 26

5.4 Regular Capital Additions - Units Table 5.4a - Mains, Services and Meters Forecast Units 2005 2006 2007 PROJECTED FORECAST FORECAST Mains (Metres) 60,848 61,392 55,776 Services (1 per addition) 3,803 3,837 3,486 New Meters (1 per customer addition) 3,803 3,837 3,486 Meter Recalls 2,250 2,216 2,567 Table 5.4b - Mains, Services and Meters Forecast Unit Costs 2005 2006 2007 PROJECTED FORECAST FORECAST Mains ($/Metre) $ 46.35 $ 47.74 $ 49.17 Services ($/Service) $ 1,246.30 $ 1,283.69 $ 1,322.20 Meters ($/Meter) $ 183.60 $ 189.11 $ 194.78 27

5.4 Regular Capital Additions - Units Table 5.4c - Mains, Services and Meters Forecast Costs ($000) 2005 2006 2007 PROJECTED FORECAST FORECAST Mains $ 2,820 $ 2,931 $ 2,743 Services $ 4,740 $ 4,926 $ 4,609 Meters $ 1,111 $ 1,151 $ 1,185 Regulator Evergreening $ 77 $ 79 $ 81 Total $ 8,748 $ 9,086 $ 8,618 28

5.5 Transmission and Distribution System (Integrity and Reliability) Extract from Table 5.5 Forecast of Capital Expenditures for System Integrity and Reliability ($000) 2005 2006 2007 PROJECTED FORECAST FORECAST Transmission Plant Population Encroachment - Ladysmith $ - $ 3,060 $ - Haslam River Directional Drill $ - $ 1,020 $ - Relocate Coquitlam Dam Crossing (Delayed from 2004) $ - $ 1,020 $ - Englishman River Directional Drill (Delayed from 2004) $ - $ 1,020 $ - V1 Coquitlam Compressor Unit 2 Upgrade (Nox emissions) $ - $ 1,185 $ - Secondary Containment $ - $ 1,836 $ 1,891 All other Transmission (Integrity & Reliability) $ 5,255 $ 1,276 $ 1,759 Total Transmission (Integrity & Reliability) $ 5,255 $ 10,417 $ 3,650 2005 2006 2007 PROJECTED FORECAST FORECAST Distribution Plant All other Distribution (Integrity & Reliability) $ 180 $ 389 $ 399 Total Distribution (Integrity & Reliability) $ 180 $ 389 $ 399 TOTAL INTEGRITY & RELIABILITY $ 5,435 $ 10,806 $ 4,049 29

5.6 Non-IT Capital Non-IT Capital Forecast Costs ($000) 2005 2006 2007 PROJECTED FORECAST FORECAST Vehicles, Tools & Equipment $ 1,037 $ 1,056 $ 1,227 Renewals - Mains & Services $ 261 $ 36 $ 36 Facilities $ 232 $ 271 $ 296 Total $ 1,530 $ 1,363 $ 1,559 30

5.7 IT Projects IT Capital Forecast Costs ($000) 2005 2006 2007 PROJECTED FORECAST FORECAST Business Integration $ 4,147 $ - $ - SAP R3 Core Application Upgrade $ - $ 250 $ - Other IT Applications $ 270 $ 169 $ 191 IT infrastructure $ 404 $ 351 $ 244 Total $ 4,821 $ 770 $ 435 31

5.8 CPCN Applications Extract from Table 5.10a Total Capital Requirement for 2006 and 2007 ($000) 2005 2006 2007 PROJECTED FORECAST FORECAST Customer Care CPCN (Approved) $ 3,060 $ 3,060 $ - Mount Hayes LNG Plant $ - $ - $ - Pipe, Compression, Spares $ - $ 14,093 $ 3,752 Total $ 3,060 $ 17,153 $ 3,752 32

5.9 Other Extract from Table 5.10a Total Capital Requirement for 2006 and 2007 ($000) 2005 2006 2007 PROJECTED FORECAST FORECAST O&M Capitalized $ 4,626 $ 4,859 $ 5,218 Contributions In Aid of Construction (CIAC) $ (122) $ (107) $ (103) Repayment of Loans $ 7,183 $ 5,089 $ 2,758 Total $ 11,687 $ 9,841 $ 7,873 33

5.10 Total Capital Requirement for 2006 and 2007 Table 5.10a Total Capital Requirement for 2006 and 2007 ($000) 2005 2006 2007 PROJECTED FORECAST FORECAST Customer Additions Capital $ 8,050 $ 8,354 $ 7,933 System Integrity & Reliability Capital $ 5,435 $ 10,806 $ 4,049 Non-IT Capital $ 1,530 $ 1,363 $ 1,559 IT Capital $ 4,821 $ 770 $ 435 Customer Care CPCN $ 3,060 $ 3,060 $ - Mount Hayes LNG Plant $ - $ - $ - Pipe, Compression, Spares $ - $ 14,093 $ 3,752 O&M Capitalized $ 4,626 $ 4,859 $ 5,218 Contributions In Aid of Construction (CIAC) $ (122) $ (107) $ (103) Total $ 27,400 $ 48,287 $ 25,601 Repayment of Loans $ 7,183 $ 5,089 $ 2,758 34

Rate Base Tom Loski

Rate Base (2003 2007) $510,000 $500,000 $490,000 $480,000 $470,000 Rate Base ($000) $460,000 $450,000 $440,000 $430,000 $420,000 $410,000 $400,000 2003 2004 2005 2006 2007 Settlement Actual Projection Forecast 36

Financing and Capital Structure Tom Loski

Return on Equity ( ROE ) and Capital Structure TGVI and Terasen Gas submitted its ROE and Capital Structure Application June 30, 2005. Revenue Requirement Application assumptions based on that submission ROE 9.04% 75 bps premium Current Benchmark of 8.29% (as at June, 2005) Capital structure 60% Debt (current is 65%) 40% Common Equity (current is 35%) 38

Financing Activities and Requirements (2006-7) Jan 2006 - TGVI required to repay $176M of long term debt TGVI refinancing its total long term debt portfolio and will be applying for approval later in 2005 $250M in long term debentures at 6.13% $150M revolving bank facility at 4.25% (funding working capital and expansion from 2006-2008) $20M subordinated revolving facility used to fund annual repayment of federal/provincial repayable contributions until 2012 at 6% 39

Gas Supply and Cost of Gas Tania Specogna Commodity Supply Manager

Natural Gas vs. Crude Oil $13.00 $12.00 $11.00 Natural Gas vs. Nym ex Crude Oil Forward Prices as at August 30, 2005 Forward Prices $75.00 $65.00 $10.00 $55.00 $9.00 US$/MMBtu $8.00 $7.00 $45.00 US$/bbl $6.00 $35.00 $5.00 $25.00 $4.00 Nymex Natural Gas (US$/MMBtu) Sumas (US$/Mmbtu) Nymex Crude Oil (US$/bbl) $3.00 $15.00 Dec-03 Feb-04 Mar-04 May-04 Jul-04 Sep-04 Nov-04 Jan-05 Mar-05 May-05 Jul-05 Oct-05 41

TGVI Royalty Adjusted Cost of Gas-2005 Compared to Sumas Price Forecast $10.00 $9.00 $8.00 $7.00 $6.00 Cdn$/GJ $5.00 $4.00 $3.00 $2.00 $1.00 $0.00 2005 Approved 2005 Forecast July 2005 Application 2005 Forecast at August 10th 2005 TGVI Royalty Adjusted Cost of Gas Calendar Year Weighted Average Sumas Price Forecast Rest of Year Sumas Price Forecast 42

TGVI Royalty Adjusted Cost of Gas-2005 Compared to Sumas Price Forecast $10.00 $9.00 $8.00 $7.00 $6.00 Cdn$/GJ $5.00 $4.00 $3.00 $2.00 $1.00 $0.00 2005 Approved 2005 Forecast July 2005 Application 2005 Forecast at August 10th 2005 TGVI Royalty Adjusted Cost of Gas Calendar Year Weighted Average Sumas Price Forecast Rest of Year Sumas Price Forecast 43

TGVI Royalty Adjusted Cost of Gas-2005 Compared to Sumas Price Forecast $10.00 $9.00 $8.00 $7.00 $6.00 Cdn$/GJ $5.00 $4.00 $3.00 $2.00 $1.00 $0.00 2005 Approved 2005 Forecast July 2005 Application 2005 Forecast at August 10th 2005 TGVI Royalty Adjusted Cost of Gas Calendar Year Weighted Average Sumas Price Forecast Rest of Year Sumas Price Forecast 44

TGVI Royalty Adjusted Cost of Gas 2005 $120 $100 $80 $60 $51.8 $51.9 $53.05 Cdn$ Millions $40 $20 $0 ($20) ($40) ($60) Gross Cost of Gas Royalties Mitigation Royalty Adjusted Cost of Gas Jan 2005 forecast July 2005 Forecast August 10th 2005 Forecast 45

TGVI Royalty Adjusted Cost of Gas-2006 Compared to Sumas Price Forecast $10.00 $9.00 $8.00 $7.00 $6.00 Cdn$/GJ $5.00 $4.00 $3.00 $2.00 $1.00 $0.00 2006 Forecast July 2005 Application 2006 Forecast August 10 2005 Application TGVI Royalty Adjusted Cost of Gas Calendar Year Sumas Price Forecast 46

TGVI Royalty Adjusted Cost of Gas 2006 $150 $100 $56.9 $59.0 Cdn$ Millions $50 $0 ($50) ($100) Gross Cost of Gas Royalties Mitigation Royalty Adjusted Cost of Gas July 2005 forecast August 10th 2005 Forecast 47

Utilities Strategies Project and O&M Requirements Tom Loski

Utilities Strategies Project ( USP ) - Background Major integration initiative between TGVI and Terasen Gas commenced in September 2003 Goal of achieving high degree of operational integration Single management team created for Terasen Natural Gas utilities Shared Services Management Agreement filed in 2004 approved by Commission (Order No. G-112-05 and G-113-05) CPCN for Customer Care conversion from Banner to CustomerWorks filed spring 2005 approved by Commission (order No. C-15-05) Anticipate Implementation Spring of 2006 49

USP Costs and Benefits USP planned and implemented a single management team working toward common work practices and IT platforms Economies of scale combine management and back office support activities of two companies Costs: (Application Table 7.1.2) One time charges of $4.945M incurred in 2003 & 2004 of which $3.8M is severance. Benefits: (Application Table 7.1.2a) O&M savings commenced in 2004 Gross O&M Savings of $6.4M in 2004 & $6.7M thereafter Reduced by Shared Services Costs and SAP costs Net USP O&M savings for settlement period = $868K Forecast net savings of $1.945M in 2005 and future years 50

USP Costs and Benefits Table 7.1.2a Summary of USP Related Benefits and Costs ($ 000 s) 2003 2004 2005 2006 2007 ACTUALS ACTUALS PROJECTED FORECAST FORECAST Gross O&M Savings $ - $ 6,400 $ 6,700 $ 6,700 $ 6,700 less: Shared Services costs allocated & Direct (3,211) (3,211) (3,211) (3,211) Less 10% of SAP transfer (459) (406) (406) (406) Net Gross O&M Savings 2,730 3,083 3,083 3,083 USP Restucturing Charges (2,403) (2,542) - - - Net USP O&M Savings (costs) $ (2,403) $ 188 $ 3,083 $ 3,083 $ 3,083 Capital Investment related costs (164) (1,138) (1,137) (1,136) Net USP Savings (costs) $ (2,403) $ 24 $ 1,945 $ 1,946 $ 1,947 51

O&M 2003 2005 Settlement Period O&M expenditures for 2003 2005 period as per Revenue Requirement Settlement (Order No. G-2-03) Gross O&M set at $31.7M, $32.5M, and $32.6M in 2003, 2004, and 2005 respectively Subsequently increased by $22K in 2004 & 2005 to reflect impact of Sooke main extension Deferral account for Pension & Insurance variances Forecast Pension expense was $2,536,911, $2,720,781, & $2,720,541 in 03, 04, & 05 respectively Forecast Insurance expense was $634,713, $646,137, & $659,060 in 03, 04 & 05 respectively 52

O&M 2003 2005 Settlement Period Table 7.3 Summary of Allowed versus Achieved O&M for Settlement Period ($ 000 s) 2003 2004 2005 ACTUALS ACTUALS PROJECTED Gross Allowed O&M Expense $ 31,722 $ 32,522 $ 32,622 USP Savings - (2,881) (3,083) USP One-time costs 2,403 2,542 - Other Savings (2,749) (1,881) (475) Achieved O&M $ 31,376 $ 30,302 $ 29,064 53

O&M 2006 2007 Forecast Period Proposing to rebase 2005 Gross O&M to take into consideration: USP benefits ($3,083M) other savings ($475K) Pension ($478,000) in 2006 and ($6,000) in 2007 Insurance ($5,000) in 2006 and $66,000 in 2007 Customer Conversion (400,000) in 2006 and ($200,000) in 2007 The Re-based Gross O&M to be increased in 2006 & 2007 to reflect: Other Cost items identified $28K in 2006 & $250K in 2007) customer growth (as per customer addition forecast) inflation of 3% 54

Proposed Gross O&M 2006 2007 Table 7.4 ($000s) 2006 2007 FORECAST FORECAST Previous year allowed O&M $ 32,622 $ 30,368 Deduct forecast USP Savings - 2005 (3,083) - Other forecast Savings - 2005 (475) sub-total 29,064 30,368 Pension Variance - 2006 (478) (6) Insurance Variance - 2006 (9) 66 CIS Conversion Savings - 2006 (400) (200) Re-based Gross O&M $ 28,177 $ 30,228 Add Cost Items $ 28 $ 250 Add Customer Growth 1,279 1,194 Add Inflation 884 943 Forecast O&M expense $ 30,368 $ 32,615 55

O&M Costs per Customer Table 7.5 Summary of Gross O&M Expenses per Customer Allowed versus Achieved 2003 2005 and Forecast 2006 & 2007 2003 2004 2005 2006 2007 ACTUALS ACTUALS PROJECTED FORECAST FORECAST Gross Allowed O&M Expense $ 31,722 $ 32,522 $ 32,622 $ 30,368 $ 32,615 CPI 2.1% 2.0% 2.1% 3.0% 3.0% Average Customers 75,255 78,618 82,601 86,421 90,082 O&M/Customer $ 422 $ 414 $ 395 $ 351 $ 362 Gross O&M Customer (2005$) $ 439 $ 423 $ 395 $ 341 $ 341 % Reduction (2005$) Vs. 2003-10.02% -22.32% -22.32% % Reduction (2005$) Vs. 2005-13.67% -13.67% 56

Cost of Service Margin per Customer Figure 7.6 Cost of Service Margin per Customer Actual versus Revenue Requirement 2003 2005 and Forecast 2006 & 2007 $1,300 $1,250 $1,200 $1,150 $1,100 $1,050 $1,000 2003 2004 2005 2006 2007 Settlement $1,253 $1,278 $1,249 Actual/Projected $1,252 $1,209 $1,196 Forecast - Nominal $ $1,163 $1,191 Forecast - 2005 $ $1,129 $1,123 57

Accounting, Tax, other Cost of Service Issues and RDDA Brian Noel Manager of Regulatory Reporting

Accounting Issues Deferral Accounts Regulatory Expenses incremental $250,000 in 2005 to be amortized in 2006 and 2007. Marketing Programs request $650,000/year for Customer grants for 2006 and 2007 to be amortized the year after the costs are incurred. Compressor Fired Hours scheduled overhaul of Coquitlam Unit 2 in 2006 and Coquitlam Unit 3 in 2007. Pension Expense Variance continuation of the deferral mechanism for 2006 and 2007. Insurance Expense Variance continuation of the deferral mechanism for 2006 and 2007. 59

Accounting Issues - Deferral Accounts (continued) OSC Compliance Certification Costs estimated $40,000/year for 2006 and 2007 to be amortized in the year the costs are incurred. 2005 Long-Term Debt Issue Cost estimated $2,500,000 to be amortized over the 10 year term of the debt. LNG Storage Facility Development Costs forecast balance at December 31, 2005 of $2,095,000 to be amortized over 5 year period commencing 2006. 60

Accounting Issues Depreciation Expense TGVI depreciation review completed in 2002. Revised depreciation rates were accepted as part of 2003-2005 Settlement and implemented in 2003. A detailed depreciation study would be required to support harmonization of depreciation rates between TGVI and Terasen Gas. Current depreciation rates are reasonable and TGVI requests continuation of current depreciation rates for 2006 and 2007. 61

Accounting Issues Income and Other Taxes Prior years income tax loss carry forward amount was fully utilized in 2003 as forecast in the 2003-2005 Revenue Requirement Application. Income taxes for 2006 and 2007 represent approx. 5% of revenue requirement. Federal Large Corporation Tax included at prescribed rates and fully phased out after 2007. Forecast property taxes: 2005 - $6.4 million 2006 - $7.2 million 2007 - $7.4 million 62

Accounting Issues Changes in Accounting Policies Requesting approval to depart from the BCUC Uniform System of Accounts for O&M reporting. Consistent with Terasen Gas O&M reporting and administratively efficient. Requesting approval to standardize O&M Capitalization Policy and to set O&M capitalization at 16% of Allowed O&M commencing 2006. Consistent with Terasen Gas Capitalization Policy. Avoids need for annual capitalization study. Capital activity stabilizing. 63

2004 RDDA Approval Required Summary of Revenue Deficiency Deferral Account Actual vs. Test Year Results ($000s) 2004 2004 Calculation of RDDA Test Year Actual Variance Opening Balance $ 77,901 $ 75,288 $ (2,613) Current Year Def/(Surplus) (17,675) (20,631) (2,956) Subordinated Debt Financing 6,217 6,264 47 Closing Balance $ 66,443 $ 60,921 $ (5,522) Annual Net Surplus $ (11,458) $ (14,367) 64

2005 RDDA Projection Summary of Revenue Deficiency Deferral Account Projected vs. Test Year Results ($000s) 2005 2005 Calculation of RDDA Test Year Projected Variance Opening Balance $ 59,395 $ 60,921 $ 1,526 Current Year Def/(Surplus) (18,021) (15,087) 2,934 Subordinated Debt Financing 5,184 4,908 (276) Closing Balance $ 46,558 $ 50,742 $ 4,184 Annual Net Surplus $ (12,837) $ (10,179) 65

2006 and 2007 RDDA Forecast Summary of Revenue Deficiency Deferral Account 2006 and 2007 Forecast Results ($000s) 2006 2007 Calculation of RDDA Forecast Forecast Opening Balance $ 50,742 $ 45,225 Current Year Def/(Surplus) (9,046) (12,017) Subordinated Debt Financing 3,529 3,259 Closing Balance $ 45,225 $ 36,467 Annual Net Surplus $ (5,517) $ (8,758) 66

Customer Rates, Alternative Fuel Comparisons and Allocated Cost of Service Tom Loski

Approach for 2006 and 2007 Rate Proposals 2006-7 Application consistent with 2003-2005 Rate Design methodology & principles: Soft-Cap mechanism RDDA balance recovery allocated to each customer class except VIGJV and TGS Competitive marketplace evaluated for each customer class & segment 68

Rate Proposals Core Rate Classes - Rate Change Logic For classes where the current effective rates are at or above their cost of service and below their competitive cap, effective rates will be held at current levels for the forecast period. For classes where the current effective rates are at or above their competitive cap, effective rates will be held at current levels for the forecast period. If the current effective rate for a class is below its cost of service and is below the competitive cap, then a rate increase is calculated to the lesser of the competitive cap or the cost of service for that class. Resulting rate changes are made to variable delivery rates, with the basic monthly charges remaining unchanged for the forecast periods. The Effective Rate is calculated as follows: (Annual Basic Monthly Charges + Annual Use-Rate * Variable Unit Rate) Annual Use-Rate 69

Transportation Service Rates VIGJV Rates set according to its amended and approved agreement. BC Hydro Firm Rates set on assumption of 45 TJ/day Firm service, with total system capacity of 144.7TJ/day, consistent with past practice IT rate based on system load factor applied to Firm rate, consistent with past practice No demand charges for Peaking service, consistent with past practice TG Squamish As per TSA @ $1.05 per GJ. 70

Allocated Cost of Service Transmission vs. Distribution $200,000 $171,408 $150,000 $131,395 $131,094 $100,000 $50,000 $40,013 $45,378 $0 2006 2007 $176,472 71 Transmission Transmission Distribution Total Distribution Allocated Costs ($000) Total

Allocated Cost of Service Transportation vs. Core $200,000 $171,408 $176,472 $152,504 $155,663 $150,000 Allocated Costs ($000) $100,000 Core Total Core Total $50,000 $18,904 $20,809 Transport Transport $0 2006 2007 72

System Capacity Allocation (2006) VIGJV (8.6%) Squamish (3.4%) Transport (31.1%) Core Sales (56.8%) 73

Rate Comparison (2005 vs. 2006) $30.000 $25.000 $20.000 Rates ($/GJ) $15.000 $10.000 $5.000 $0.000 RGS AGS SCS1 SCS2 LCS1 LCS2 LCS3 HLF ILF 2005 Rate 2006 Rate 74

Rate Comparison vs. Allocated Unit Costs 2006 $30.000 $25.000 $20.000 Rates ($/GJ) $15.000 $10.000 $5.000 $0.000 RGS AGS SCS1 SCS2 LCS1 LCS2 LCS3 HLF ILF 2005 Rate 2006 Rate AUC 75

Rate Comparison vs. Alternate Fuels (2006) $30.000 $25.000 $20.000 Rates ($/GJ) $15.000 $10.000 $5.000 $0.000 RGS AGS SCS1 SCS2 LCS1 LCS2 LCS3 HLF ILF 2005 Rate 2006 Rate Oil Electricity AUC 76

Key Planning Assumptions Sensitivities

Gas Costs Sensitivity Revenue Requirement Impact 2006 2007 August 10, 2005 Strip +$3.1M N/A 78

ROE and Capital Structure Sensitivities Revenue Requirement Impact 2006 2007 25 Basis Point Premium $721K $775K 5% Equity $2.7M $2.4M Long Term Debt, $50M $950K $963K 79

Proposed Review Process

Proposed Review Process Regulatory Calendar (Order G-77-05) September 20 Procedural Conference September 27 Commission issues Information Request No. 1 to TGVI September 29 Budget estimates for PACA submitted September 30 Intervenors provide Information Requests to TGVI October 12 TGVI responds to Information Requests October 26 Revenue Requirement Negotiations commence (pending decision from BCUC on NSP process) 81

Wrap-up