Mt. Hayes LNG Storage Facility

Transcription

1 Mt. Hayes LNG Storage Facility IN THE MATTER OF the Utilities Commission Act, R.S.B.C. 1966, Chapter 473 (the "Act") AND IN THE MATTER OF an Application by Terasen Gas (Vancouver Island) Inc. for a Certificate of Public Convenience and Necessity and for Approval to enter into a Storage and Delivery Services Agreement AND IN THE MATTER OF an Application by Terasen Gas Inc. for Approval to enter into a Storage and Delivery Services Agreement Submitted to the BRITISH COLUMBIA UTILITIES COMMISSION JUNE 5, 2007

2 Mt. Hayes LNG Storage Facility TABLE OF CONTENTS 1. APPLICATIONS Applicants Name, Address and Nature of Business Financial Capability of Applicants Technical Capability of Applicants Name, Title and Address of Contact Name, Title and Address of Legal Counsel Project Description Project Justification Regulatory Review of CPCN Application OVERVIEW Introduction Resource Plans History of Mt. Hayes LNG Project Development of Current Proposal PROJECT DESCRIPTION Introduction Description of the LNG Storage Facility Mt. Hayes Project Site Substation and Power Line Description of the System Facilities Pipeline Laterals and Measurement/Odourization Station Transmission System Modifications Pre-Construction Development Activities Project Management...20 Page i

3 Mt. Hayes LNG Storage Facility 3.6. Environmental Assessment Other Approvals Public and Stakeholder Consultation Public Consultation Program First Nations Resource Plan Consultation Socio Economic Assessment Project Schedule LNG Storage Facility Project Schedule System Facilities Project Schedule Project Description Summary PROJECT COSTS Capital Cost Forecast EPC Cost Development LNG Storage Facility Capital Cost Estimates System Facilities Capital Cost Estimates Capital Cost Approvals Operating Costs Project Operating Costs Project Cost Summary LNG STORAGE FACILITY COST RECOVERY Overview A Fair Return on Equity LNG Storage Facility Cost of Service Adjusted Depreciation Schedule Annual Revenue Requirement Present Value Assessment Capital Cost Impact TGI Storage Revenues...45 Page ii

4 Mt. Hayes LNG Storage Facility Terms and Conditions TGVI AND TGI CUSTOMER DEMAND TGVI Demand Forecast Core Demand Squamish and Whistler Demand Industrial Transport Demand Design Year Temperature Variability TGI Demand Forecast for the Lower Mainland Region Lower Mainland Core and Transportation Demand Lower Mainland Generation Demand Lower Mainland Load Duration Peak Period Temperature Uncertainty Lower Mainland Winter 2006/07 Cold Weather Event PROJECT JUSTIFICATION Gas Supply Portfolio Assessment Introduction Summary of Resource Plan - Gas Supply Portfolio Planning Findings Combined TGI and TGVI Portfolio Evaluation New Resource Alternatives Impact of Storage Availability on Gas Supply Portfolio Value of LNG Storage Service Gas Supply Portfolio Summary Resource Portfolio Development System Description of CTS and TGVI System TGVI System Capacity Requirements TGVI Portfolio Development Comparison with 2006 Resource Plan Results TGI CTS Portfolio Development BC Hydro Bypass Transportation Agreement Transportation Service for TGVI TGI System Future Expansion Requirements...85 Page iii

5 Mt. Hayes LNG Storage Facility Flexibility of LNG Portfolio Resource Portfolio Summary Additional Benefits Incremental Transportation Revenue Security of Supply Improved System Reliability Reduced Rate Volatility Operational Flexibility and Efficiency Summary of Additional Benefits ECONOMIC JUSTIFICATION AND CUSTOMER IMPACTS TGVI Portfolio Comparison Financial Assumptions TGVI Baseline Scenario Sensitivity Scenarios Impact of Additional Benefits Incremental Transportation Revenues Additional Benefits TGI Portfolio Analysis TGI Benefit TGI Benefit TGVI Customer Rate Impact System Cost Allocation Assumptions Expected Core Market Unit Cost Impact Firm Transportation Service Levelized Cost Comparison CONCLUSIONS GLOSSARY Page iv

6 Mt. Hayes LNG Storage Facility LIST OF APPENDICES Appendix A Appendix B Appendix C Appendix D Appendix E Appendix F LNG Storage Facility Project Information A Fair Return for Natural Gas Storage Facilities TGVI TGI Storage Service & Delivery Agreement TGVI Demand Gas Market Information Financial Schedules Page v

7 Mt. Hayes LNG Storage Facility 1. APPLICATIONS Terasen Gas (Vancouver Island) Inc. ( TGVI ) hereby applies to the British Columbia Utilities Commission (the BCUC or the Commission ) pursuant to Section 45 of the Utilities Commission Act, R.S.B.C. 1996, Chapter 473, (the Act ) for a Certificate of Public Convenience and Necessity ("CPCN") to build the Mt. Hayes liquefied natural gas ( LNG ) storage facility ( LNG Storage Facility ) on Vancouver Island and the facilities required to connect the LNG Storage Facility to TGVI s natural gas transmission system and associated upgrades ( System Facilities ) (collectively the Application or Project ). As part of this Application for a CPCN, TGVI also applies for approval of a return on equity based on its allowed return on equity plus 50 basis points to be applied on the rate base associated with the LNG Storage Facility and pursuant to Section 56 of the Act TGVI applies for approval of the adjusted depreciation schedule set out in this Application associated with the annual depreciation expense for the LNG Storage Facility. TGVI also requests approval to recover pre-construction development costs associated with the LGN Storage Facility and the System Facilities. TGVI also applies for approval, pursuant to Section 61 of the Act, of a long-term agreement (the Storage and Delivery Agreement ) with TGI by which TGVI will provide LNG storage, liquefaction and vaporization service, and gas delivery and re-delivery service to TGI. TGI hereby applies for approval, pursuant to Section 71 of the Act, to enter into the Storage and Delivery Agreement with TGVI Applicants Name, Address and Nature of Business TGVI is a company incorporated under the laws of the Province of British Columbia and is a wholly-owned subsidiary of Terasen Inc. TGVI maintains an office and place of business at Fraser Highway, Surrey, British Columbia, V4N 0E8. TGVI operates a natural gas transmission system and distributes natural gas to over 87,000 customers on Vancouver Island Page 1

8 Mt. Hayes LNG Storage Facility and the Sunshine Coast. TGVI will own and operate the LNG Storage Facility and the System Facilities. TGVI will also provide natural gas storage and deliverability services to TGI. TGI is a company incorporated under the laws of the Province of British Columbia and is a wholly-owned subsidiary of Terasen Inc. TGI maintains an office and place of business at Fraser Highway, Surrey, British Columbia, V4N 0E8. TGI operates natural gas transmission systems and distributes natural gas to over 810,000 customers in the Interior and Lower Mainland of British Columbia including Squamish Financial Capability of Applicants TGVI is capable of financing this LNG Storage Facility and the System Facilities, either directly or through its parent Terasen Inc. Terasen Inc has credit ratings for senior unsecured debentures from Dominion Bond Rating Service and Moody s Investors Service of BBB (High) and Baa2 respectively. Terasen Inc has, through its subsidiary companies, completed largescale system implementation projects. Terasen Inc. has the financial capacity to undertake them by means of borrowing and from funds internally generated from business operations Technical Capability of Applicants TGVI and TGI are managed and operated by a common management team and employees. Together the utilities operate more than 30,000 kilometres of gas transmission and gas distribution mains and service lines in British Columbia. In addition, TGI has owned and operated a 0.6 Bcf LNG storage facility located at Tilbury Island, Delta, B.C. since TGVI delivers natural gas to approximately 87,000 homes and businesses on the Sunshine Coast and Vancouver Island. TGVI also provides gas transportation service to six pulp mills and a gas fired generation facility connected to its system, TGVI designed and constructed its highpressure and pipeline (completed in 1991), and has operated the integrated high-pressure and low-pressure transmission and distribution system since TGI has designed, constructed and operated its high pressure pipeline system and distribution network since 1957, and delivers natural gas to more than 810,000 customers in the Interior and Lower Mainland of B.C. Page 2

9 Mt. Hayes LNG Storage Facility Name, Title and Address of Contact Communications with respect to this Application should be addressed to the TGVI and TGI contact: Scott A. Thomson, C.A. Vice President, Finance and Chief Financial Officer Fraser Highway Surrey, B.C. V4N 0E8 Phone: (604) Facsimile: (604) Name, Title and Address of Legal Counsel Legal Counsel for this Application is: Cal Johnson, Q.C. Fasken Martineau DuMoulin LLP 21st Floor, 1075 West Georgia Street Vancouver, B.C. V6E 3G2 Phone: (604) Facsimile: (604) Project Description TGVI proposes to construct and own a 1.5 Bcf LNG Storage Facility, at a location referred to as Mt. Hayes, in the Cowichan Valley Regional District ("CVRD") near Ladysmith, and the System Facilities required to connect the LNG Storage Facility to TGVI s natural gas transmission system. The LNG Storage Facility will allow TGVI to provide both system capacity and a gas peaking resource for the benefit of TGVI s customers on Vancouver Island and the Sunshine Coast. The Project will also allow TGVI to provide storage and delivery services to TGI. Page 3

10 Mt. Hayes LNG Storage Facility The Mt. Hayes location in the CVRD is approximately 6 km northwest of Ladysmith. Rezoning of the site for LNG storage use was approved by the CVRD on May 26, 2004 after a comprehensive consultation process. TGVI has an option to purchase the property from Island Timberlands, under an agreement that expires July 31, A cost estimate for the LNG Storage Facility has been developed based on information supplied by consultants and contractors and TGI and TGVI s own experience in project management of major capital projects. The major portion of the LNG Storage Facility will be constructed under a turnkey price engineering, procurement and construction ( EPC ) contract which TGVI expects to have in place by December 1, At that time TGVI will have greater cost certainty as the EPC contract will include a firm price for a major portion of the equipment procurement and construction activities performed by the EPC contractor. Based on the work performed to date, the direct capital cost for a 1.5 Bcf LNG Storage Facility at Mt. Hayes is currently estimated at $165 million in 2007 dollars based on P50 estimate and $186 million based on the current P90 estimate. As part of the Project, TGVI will also construct 5 km of connecting facilities including transmission pressure supply and tail gas pipelines from its transmission system near Ladysmith to the LNG Storage Facility and install gas measurement and odourization facilities. TGVI will also install extra valving at its Texada Compressor Station and on its marine crossing to accommodate potential flow reversing due to the presence of the LNG Storage Facility. The estimated direct P50 to P90 capital cost range is $10.7 million in 2007 dollars for these System Facilities. Operating costs for the Project have been determined from TGI experience operating the Tilbury LNG Facility in Delta, B.C. and from TGVI and TGI experience operating transmission facilities throughout B.C. The estimated annual fixed operating costs are approximately $1.56 million in 2007 dollars. Variable costs include electricity and fuel usage for liquefaction and vaporization and will depend on the volume throughputs from year to year. The current project schedule is based on finalising the EPC contract by December 1, 2007, which would allow the LNG Storage Facility to be constructed and commissioned by April This will allow the LNG tank to be filled over the summer months and be ready for core market heating season requirements beginning November 1, The construction of the System Page 4

11 Mt. Hayes LNG Storage Facility Facilities is not on the critical path and TGVI is confident that they can be readily completed to meet the overall project schedule requirements Project Justification In July 2006, TGVI and TGI filed their 2006 Resource Plans 1 which provide a long term view of customer growth and evaluate the options available to the utilities to meet the forecast customer needs. The TGVI Resource Plan identifies the need for expansion of its transmission capacity to serve current and the forecast loads on Vancouver Island and compare the benefits of an LNG Storage Portfolio to a Pipe and Compression Portfolio approach. In addition, both Resource Plans discuss the need and potential costs for new regional storage facilities to support TGVI and TGI s growing requirement for cost effective resources to meet core market peaking requirements. The Resource Plans conclude that the development of a 1.5 Bcf LNG peak shaving facility on Vancouver Island is the major component of the preferred portfolio for meeting the requirements of both utilities over the 25 year planning period. The LNG Storage Facility will provide both utilities a peaking gas storage resource for which they would otherwise have to contract for service at Huntingdon/Sumas. By locating the facility on Vancouver Island, it will also provide TGVI with additional system capacity to serve core customers during cold weather events and allow it to avoid or significantly defer the expansion of its system through construction of new compressor stations. Similarly, access to the LNG Storage Facility will allow TGI to avoid future expansions of the Coastal Transmission System ( CTS ) to continue to provide service to Burrard Thermal if required. The Project will also improve overall system reliability in the event of transmission system or upstream outages and provide other benefits For TGVI, the LNG Storage Portfolio has benefits of avoided costs for storage downstream of Huntingdon/Sumas and avoided or deferred transmission system capacity expansion. The results presented in Section 8 of this Application demonstrate a clear preference for the LNG portfolio over the Pipe and Compression ( P&C ) Portfolio. Having the LNG Storage Facility in the TGVI market area, and on Vancouver Island in particular, provides a number of other 1 The TGVI and TGI Resource Plans can be found on the Terasen Gas web site as follows: Page 5

12 Mt. Hayes LNG Storage Facility benefits to TGVI customers and to the region. Examples of these are improved TGVI system reliability, mitigation of upstream system and supply outages, and reduced price volatility in the region. For TGI, storage services will be acquired from TGVI under the terms of the proposed Storage and Delivery Agreement between TGI and TGVI. Since TGI has the alternative of acquiring additional storage downstream of Huntingdon/Sumas, the charges from TGVI to TGI for LNG services are based on a forecast of the avoided costs of Huntingdon/Sumas market area storage. The primary value to TGI of the LNG Storage Facility will be avoided costs for storage downstream of Huntingdon/Sumas in its gas supply portfolio. The LNG Storage Facility on Vancouver Island also creates the potential benefit in deferring capacity expansion on the TGI CTS Regulatory Review of CPCN Application This Application builds on the LNG Storage Project Application reviewed by the Commission through a comprehensive regulatory proceeding, including an oral hearing, which concluded in February In that proceeding, there were no significant issues or concerns expressed by party regarding technical, operational, environmental, safety and siting issues. Accordingly, the Applicants propose that the appropriate review of this Application be a in a written public proceeding. ALL OF WHICH is respectfully submitted. June 5, 2007 On behalf of the Applicants, TERASEN GAS (VANCOUVER ISLAND) INC. and TERASEN GAS INC. Original signed by: Tom Loski For: Scott A. Thomson VP, Finance & Regulatory Affairs and Chief Financial Officer Page 6

13 Mt. Hayes LNG Storage Facility 2. OVERVIEW 2.1. Introduction In this Application TGVI is seeking approval to develop, construct, own and operate an LNG storage facility to be located at Mt. Hayes near Ladysmith in the Cowichan Valley Regional District on Vancouver Island. The estimated P50 to P90 capital cost range for the 1.5 Bcf LNG Storage Facility is $165 to $186 million (direct 2007$) and the target in-service date is April 1, The LNG Storage Facility will provide substantial benefits to TGVI s customers and other gas consumers by providing new storage capacity to the region to alleviate supply and infrastructure capacity constraints and to improve reliability. In addition, the facility will allow TGVI to avoid expanding its transmission system to serve its customers by providing capacity to meet winter load requirements. TGVI s alternative to the LNG Storage Facility is to continue to grow its dependence on third party storage providers and to expand its transmission system as required. In support of TGVI s investment in this important natural gas infrastructure project, TGVI is requesting a return on equity be applied on the rate base associated with the LNG Storage Facility which is more comparable to allowed returns for similar investments elsewhere in North America while remaining attractive to ratepayers. TGVI is also seeking approval to construct, own and operate facilities to connect the LNG Storage Facility to its transmission system. As part of the System Facilities, minor upgrades of the existing transmission system will also be put in place. The expected total cost of the interconnecting facilities and other equipment upgrades is approximately $10.7 million (2007$) and will be in-service to meet the requirements of the LNG Storage Facility construction and commissioning schedule. TGVI and TGI are seeking approval for a services agreement (the Storage and Delivery Agreement ) under which TGVI will provide storage and delivery services to TGI. The LNG Storage Facility provides TGVI and its customers with a new storage resource as part of TGVI s gas supply portfolio. In addition, the LNG Storage Facility allows TGVI to avoid the costs of increasing the capacity of its transmission system to meet load growth through the Page 7

14 Mt. Hayes LNG Storage Facility addition of compression facilities and pipeline looping. Through the arrangements between TGVI and TGI, the LNG Storage Facility also provides TGI and its customers with a new storage resource, as part of TGI s gas supply portfolio, at a price competitive with its alternative storage options considered in its gas portfolio. As demonstrated by the analyses in this Application, the LNG Storage Facility, along with the proposed arrangements between TGVI and TGI, is the most cost effective option for meeting the expected growth in demand for natural gas on Vancouver Island and the Sunshine Coast. In addition, there is significant security of supply and other benefits associated with the location of an LNG storage facility on TGVI s system on Vancouver Island. Figure 2-1 Project Location Proposed LNG Storage Facility Resource Plans This Application for the Project should be reviewed in the context of TGVI and TGI s 2006 Resource Plans. TGVI and TGI completed and filed their respective 2006 Resource Plans with the BCUC in July The Resource Plans provide a long-term view of customer growth and evaluate the options available to the utilities to meet the forecast customer needs. Both Resource Plans discuss the need for new regional storage resources to support TGVI and TGI s Page 8

15 Mt. Hayes LNG Storage Facility growing requirement for cost effective alternatives to meet core market peaking requirements. The TGVI Resource Plan also discusses the need for expansion of its system capacity to serve current and forecast loads on Vancouver Island. In TGI s case, the Resource Plan identifies that a major expansion may be required on its CTS as early as 2011 depending on the timing of the proposed retirement of Burrard Thermal. The Resource Plans conclude that the development of an LNG peak shaving facility with up to 1.5 Bcf of storage on Vancouver Island offers the most cost effective solution for meeting the requirements of both utilities over the planning period. The facility would primarily be used to provide to both utilities a peaking gas storage resource as part of their gas supply portfolios. An on-system storage resource will allow the utilities to reduce their dependence on contracted services at facilities located in Washington and/or Oregon states and also provide higher reliability and security of supply benefits. By locating the facility on Vancouver Island, it will also provide TGVI with additional system capacity to serve core market customers during cold weather events and allow it to avoid the construction of new compressor stations to meet future customer peak day growth. The capacity available from an LNG storage facility will also provide TGVI greater flexibility to continue to serve the existing Island Cogeneration Plant ( ICP ) without putting customers at risk for stranded capacity. The LNG Storage Facility will also reduce TGVI s future transport demands on TGI s CTS during peaking periods, which in turn will also allow TGI to defer future transmission system expansions and manage the uncertainty regarding the long-term operation of Burrard Thermal History of Mt. Hayes LNG Project TGVI has been investigating the potential to locate an LNG peak shaving facility on Vancouver Island since At that time TGVI was assessing transmission system expansion alternatives to the proposed Georgia Strait Crossing ( GSX ) to meet expected new baseload generation demand on Vancouver Island. BC Hydro was developing GSX to provide transportation capacity to Vancouver Island to serve both the existing Island Cogeneration Project at Campbell River, and the proposed Vancouver Island Generation Project ( VIGP ) being advanced by BC Hydro at Duke Point. A joint BC Hydro/Williams pipeline project, GSX was proposed to connect from Sumas across Whatcom County and Georgia Strait to Vancouver Island and was expected to cost approximately $300 million. Page 9

16 Mt. Hayes LNG Storage Facility The VIGP project had been proposed by BC Hydro to meet the expected firm electric capacity requirements on Vancouver Island by the winter of 2007/08 when the existing HVDC transmission system was expected to be downgraded. Following the September 2003 Commission decision denying BC Hydro s CPCN for VIGP, BC Hydro suspended direct development of VIGP and commenced a Call for Tenders ( CFT ) process to solicit proposals from independent power producers to develop new generation facilities on Vancouver Island. An Electricity Purchase Agreement ( EPA ) was subsequently awarded to the proponents of the Duke Point Power ( DPP ) project in November 2004 supporting the development of a 252 MW gas-fired combined cycle power plant at Duke Point. BC Hydro subsequently terminated the GSX project in December 2004 and began exploring gas transportation alternatives for ICP and the DPP project. In its 2004 Resource Plan, TGVI concluded that the resource portfolio that included an LNG storage facility located at Mt. Hayes near Ladysmith was the preferred option to meet growing gas demand on Vancouver Island, including the expected new generation loads. The facility would be used to meet the winter peaking capacity requirements of TGVI s core market, thereby releasing pipeline capacity to be used by new and existing baseload demand on the system. Depending on the outcome of BC Hydro s plans for additional gas-fired power generation, the resource portfolio contemplated that in addition to the LNG peak shaving facility further pipeline capacity would have been added through compression and pipeline looping additions to firm up ICP and to meet the new generation load. The facility would have also provided gas supply benefits to TGVI s core customers and any unused capacity could be used to provide storage services to TGI. TGVI subsequently applied for a CPCN for the LNG storage facility to meet a November 2007 in-service date and in February 2005 received conditional approval from the Commission. The approval conditions were as follows: a maximum EPC price for facility construction; an agreement for storage services provided to TGI; a long-term firm transportation service agreement with BC Hydro for the existing ICP and the proposed DPP project; and the commencement of construction by December 31, The first two conditions were satisfied; however despite approval of the DPP project by the Commission in February 2005, BC Hydro terminated the DPP project in July 2005 and Page 10

17 Mt. Hayes LNG Storage Facility subsequently pursued the option to meet Vancouver Island s electrical requirements through replacement of the HVDC electric transmission lines. A long-term transportation service agreement for both gas-fired generation facilities therefore could not be reached and construction of the LNG storage facility did not proceed by December 31, Development of Current Proposal As described above, the 2004 proposal by TGVI for the 1.0 Bcf Mt. Hayes LNG facility was justified primarily on the system capacity benefits that would allow TGVI to cost effectively meet forecasted customer demands including significant increases expected from new generation loads. If the DPP project had proceeded, the proposed 1.0 Bcf facility would have been the one component of a LNG Portfolio that also included new compressor stations to increase the base load capacity of the transmission system to meet the new generation loads. The availability of an on-system storage resource would also have provided benefits to TGVI s gas supply portfolio, however the primary justification for the 1.0 Bcf project at that time was based on meeting system capacity requirements. A major distinction between this Application for the LNG Storage Facility and the 2004 project proposal, is that the principal justification for the development of the 1.5 Bcf LNG Storage Facility is the provision of a firm gas supply portfolio resource to both TGVI and TGI. The availability of an on-system resource will reduce the dependence on other off-system storage or pipeline capacity resources available to serve the Lower Mainland and Vancouver Island service areas. As a secondary benefit, the availability of an on-system resource will also provide system capacity benefits by allowing TGVI to avoid or significantly defer facility additions on its transmission system across a broad range of customer demand. The proposal in this Application will also provide TGVI and TGI flexibility to manage the uncertainty regarding future generation loads in their service areas with no additional risk to other customers. TGVI and TGI customers will benefit from the enhanced security of supply, system reliability, operational flexibility and other benefits that can be realized through the addition of an on-system storage resource. The 2006 Resource Plans provided an assessment of the benefits of developing an LNG storage facility on Vancouver Island based on facility sizes ranging from 0.5 to 1.5 Bcf of LNG Page 11

18 Mt. Hayes LNG Storage Facility storage and assuming a 2010 in-service date. The assessment concluded that the development of a storage facility was in the best interest of TGVI s customers across a broad range of customer demand. It also concluded that economies of scale could be realized through the construction of a larger facility thereby allowing TGVI to offer competitive storage services to TGI and reduce the cost impact to its own customers. Based on the conclusions from the 2006 Resource Plan, this Application is based on the development of a 1.5 Bcf facility. The Application also updates the expected Project cost and schedule based on the current information reasonably available to TGVI, taking into account the very high level of construction activity occurring in British Columbia and in the North American energy industry in general. Based on this information, the earliest in-service date that TGVI can reasonably expect to attain is April This allows liquefaction to take place over the summer months and storage services to be available to meet 2011/12 winter requirements. Page 12

19 Mt. Hayes LNG Storage Facility 3. PROJECT DESCRIPTION 3.1. Introduction The Project involves the construction of an LNG Storage Facility on the Mt. Hayes site on Vancouver Island and upgrades to TGVI s transmission system including the connecting pipeline laterals to connect to the storage facility. This Section provides descriptions of the Project components as follows: The LNG Storage Facility consisting of a 1.5 Bcf storage tank and ancillary facilities including liquefaction and vaporization components, and substation and 5 km power line from the BC Hydro transmission system to provide the required electrical supply to the site; and The System Facilities consisting of all the facilities that will be constructed and operated as part of TGVI s transmission system including 5 km dual connecting pipelines, a gas measurement and odourization facility, and upgrades to existing facilities to allow for bidirectional flow. The current Project proposal for a 1.5 Bcf facility is based on the development work carried out by TGVI to support its 2004 application for a 1.0 Bcf facility at the same site. In support of that application, TGVI had conducted a thorough public consultation and environmental review process and received all the necessary permits and approvals to proceed with the construction of the facility once final BCUC approval had been obtained. TGVI had also completed site investigation activities and preliminary engineering work and executed a fixed price EPC contract with a major LNG tank supplier and contractor. As discussed in Section 2.3, at that time the need for new capacity on Vancouver Island was driven by the requirement to provide firm transportation service to both the existing ICP and proposed DPP. With the cancellation of the DPP in July 2005, the LNG project was suspended. However TGVI maintained rights to acquire the project site and continued to maintain stakeholder relationships to support future development of the project. The current Project is based on the same technical configuration, performance and operating specifications as proposed in the 2004 application, other than those elements required to Page 13

20 Mt. Hayes LNG Storage Facility increase the size of the facility to 1.5 Bcf with similarly scaled liquefaction and vaporization components. Appendix A provides a detailed description of the technical and operation characteristics of the facility as well as a discussion of the development work performed in 2004 and 2005 that forms the basis of the current proposal. Those issues were fully explored during the regulatory review of the 2004 application and TGVI believes further review would not provide any additional information. The Project information provided in this Section 3 is therefore focused on the elements that are different from the 2004 application and are key to obtaining approval for the current proposal Description of the LNG Storage Facility The LNG Storage Facility will be designed with capacities outlined in Table 3-1, with 200 days of liquefaction to fill the tank if completely utilized in any one season and the ability to send-out at daily rates up to 10% of the storage capacity. Table 3-1 LNG Storage Facility Design Capacity 1.5 Bcf Facility Capacities Design Capacity Volume/Rate Energy/Rate Storage 1.5 Bcf 1,620,000 GJ Liquefaction Rate 7.5 MMcfd 8,100 GJ/d Maximum Send-out Rate 150 MMcfd 162,000 GJ/d The TGVI LNG Storage Facility process components and descriptions in Appendix A are generally the same as planned for the 2004 TGVI application for a 1.0 Bcf facility. Changes to the design, including equipment sizing and site layout, to accommodate a 1.5 Bcf facility have been made based on preliminary discussions with Chicago Bridge & Iron Company ( CB&I ). CB&I is the major EPC Contractor that had been previously engaged by TGVI for the 2004 project development and 2005 proposed execution start. Following approval of this Application, TGVI will work with an EPC contractor to finalize the detailed design of the 1.5 Bcf LNG Storage Facility. During this design phase, and also during the Project implementation, the EPC contractor and the TGVI Project team will investigate process alternatives to improve the overall Project cost and operation. Page 14

21 Mt. Hayes LNG Storage Facility Mt. Hayes Project Site A block of property at the proposed Mt. Hayes site has been optioned by TGVI for purchase from the owner, Island Timberlands (previously Weyerhaeuser). A 42 hectare (ha) section of the property was rezoned by the Cowichan Valley Regional District in 2004 to allow construction and operation of an LNG facility with up to two 1.5 Bcf storage tanks. In addition to the 42 ha rezoned section, TGVI anticipates retaining an additional 20 ha to the east of the rezoned area to maintain control over the CSA Code required buffer zone, and return the remaining 80 ha to Island Timberlands to maintain ownership of and resume forestry operations. Lease of a further 20 ha of Crown land outside the property to the west was previously approved for TGVI through the British Columbia Oil and Gas Commission ( OGC ) and TGVI anticipates no issues in renewing this approval to ensure the appropriate buffer is maintained. Within the 42 ha rezoned area, the physical plant boundaries will encompass approximately 20 ha which will be fenced and contain all the facility components. Section in Appendix A describes the siting requirements and the Island Timberlands (previously Weyerhaeuser) property that has been optioned. The overall facility footprint is not expected to change to accommodate the larger 1.5 Bcf facility. The storage tank itself will be larger and be contained within a higher dike, but the facility fenceline is not expected to change significantly. The 50% increase in equipment capacity sizing will not impact the overall facility area requirement Substation and Power Line TGVI will install and own an electrical substation adjacent to the BC Hydro transmission system and a 5 km 25kV power line from the substation to the LNG Storage Facility site to provide the required electrical supply for the plant. The 7 m right-of-way ( ROW ) for the power line will be adjacent to the 18 m ROW for the pipelines connecting to the LNG Storage Facility and generally aligned adjacent to the existing road ROW. TGVI received approval for the power line ROW from the OGC, and TGVI anticipates no issues in renewing the approval. The location of the ROW is shown in Figure 1-4, Section of Appendix A. Page 15

22 Mt. Hayes LNG Storage Facility 3.3. Description of the System Facilities The System Facilities include the construction of pipeline laterals from the LNG Storage Facility site to connect with TGVI s transmission system, the gas measurement and odourization facility adjacent to the LNG Storage Facility and minor modifications to the TGVI transmission system to accommodate bi-directional flow. The System Facilities work is required to accommodate natural gas delivery to and from the proposed LNG Storage Facility by the TGVI transmission system Pipeline Laterals and Measurement/Odourization Station TGVI will construct and operate pipeline laterals connecting its transmission pipeline to the Mt. Hayes LNG Storage Facility and a measurement/odourization station adjacent to the LNG Storage Facility. These facilities were also reviewed in conjunction with the 2004 application, and the only modifications are those required to accommodate the higher vaporization capacity of the LNG Storage Facility (i.e. from 100 MMcfd to 150 MMcfd) Transmission System Modifications TGVI is also proposing certain modifications to the existing transmission system in order to allow bi-directional flow. Generally, TGVI expects that the gas nominated by TGI under the proposed Storage and Delivery Services Agreement will be redelivered to TGI s system through displacement. However, under certain demand conditions, there may be a requirement to physically flow gas sent out from the LNG Storage Facility to the interconnection between the TGVI and TGI systems at the Coquitlam compressor station (V1). This requirement was not contemplated in the 2004 proposal as the maximum send-out capacity of the 1.0 Bcf facility was lower than in the current proposal (i.e. 100 MMcfd versus 150 MMcfd), and TGVI was not providing a minimum level of service to TGI. In addition, the 2004 proposal was based on provision of additional system capacity and it was contemplated that there would significant baseload throughput on the system to serve the ICP and DPP generation facilities which in turn would enhance the displacement capacity. The requirement to flow gas back to the TGI CTS could occur at times when the required storage service sendout from the LNG Storage Facility is greater than the TGVI System load. As a result, TGVI will require minor modifications to its existing transmission system to Page 16

23 Mt. Hayes LNG Storage Facility accommodate flow in the reverse direction during maximum sendout from the LNG Storage Facility as follows: The existing check valves on the downstream side of each of the two main marine crossings will be replaced with actuated valves to allow the bi-directional flow. The actuated valves will provide the same security of undesired reverse flow blockage in the event of an upstream pipeline failure during normal flow operation of the system. The Texada Compressor Station (V-4) will be modified to accommodate reverse flow operation in order to move peak LNG sendout at non-peak TGVI System demand. These modifications will require the installation of a second set of side valves and associated piping and control system changes. The TGI/TGVI custody transfer station located at the Coquitlam Compressor Station will be modified to allow flow from the TGVI transmission system into the CTS. The modification will include flow measurement, pressure control and overpressure protection Pre-Construction Development Activities TGVI undertook significant project development work in support of the 2004 LNG Storage Project Application and approvals and the subsequent preparation to commence construction in 2005 that included: Stakeholder consultation and communication; Engineering reports on the site geotechnical and seismic conditions and the LNG facility design and costing; Environmental studies and assessments; Memorandum of Understanding ( MOU ) with the Chemainus First Nation ( CFN ); Site purchase option agreement and Crown land approvals; EPC and construction contracts; Historical cost estimate and schedule information; and Historical design and specification information. Page 17

24 Mt. Hayes LNG Storage Facility The current Application is based on the previous project development work updated to reflect the increased size of the facility from 1.0 Bcf to 1.5 Bcf and the target completion date of April To date, TGVI has relied on discussions with consultants and EPC contractors and TGVI s own experience in executing projects in order to develop the updated cost estimates and schedule to support this Application. Nevertheless, there still remains considerable uncertainty given the high level of construction activity currently occurring in British Columbia in particular and in the North American energy industry in general. In order to obtain greater cost certainty, TGVI will undertake additional project development work including the engagement of an EPC contractor to develop a firm fixed price proposal to construct the facility. The expected costs of these Project development activities are $1.9 million to December TGVI will undertake the further development work in this updating phase to provide greater confidence in the Project capital cost and to confirm the construction schedule prior to initiating construction and awarding the major contracts. The objective during this phase is to minimize capital costs and the potential for cost variance and to reduce required contingency by firming up the EPC contract price and the total Project estimate immediately prior to Project kick-off when TGVI issues authorisation to proceed to its project team and major contractors. Developing a firm facility price as close as possible to the construction start date minimizes the forward cost uncertainty and helps to minimize the cost uncertainty for the three year construction period for the EPC contractor, and thus reduces the risk premium the contractor would include in its firm price provided to TGVI. In parallel to the EPC price updating, the estimates for the activities managed directly by TGVI outside the scope of the EPC contract will also be confirmed. Confirmation of the current estimates will include additional geotechnical investigation and environmental impact assessment studies to verify the impact of the increase of the size of the storage facility to 1.5 Bcf from the original proposal. These pre-construction project development activities will commence in June 2007 to support a commencement of construction by December 1, The expected costs of these Project development activities are $1.9 million. The full scope of activities, during this period, is as follows: Stepping up communication and liaison with key stakeholders and local landowners on Project timing, impacts and opportunities; Page 18

25 Mt. Hayes LNG Storage Facility Updating the Environmental and Social Review and ensuring all environmental studies reflect the current Project, conditions and regulations; Confirming and renewing, as required, those applications for approval that are in place and those required to start construction December 1, 2007; Organizing the Project team and setting up those Project control elements required to initiate construction; Preparation work for the site civil contract including design and RFP documents and process; Further geotechnical investigation for the larger tank foundation and revised site plan; Engage EPC contractor to update design for 1.5 Bcf LNG facility and subsequent EPC price development; and Negotiation of EPC contract including appropriate risk allocation with the EPC contractor. The expected costs and timing of expenditures for this pre-construction phase are as shown in Table 3-2. These costs are included in the current capital cost estimates for the LNG Storage Facility discussed in Section 4. Table 3-2 Pre-Construction Development Costs 2007 LNG Project Development Updating $000 Jun Jul Aug Sep Oct Nov Communications $5 $5 $5 $5 $5 $5 Approvals $0 $0 $12 $12 $12 $0 Project Office $7 $14 $14 $21 $29 $29 Owners Costs Update $0 $0 $25 $25 $25 $0 Site Preparation $0 $168 $216 $71 $10 $10 EPC Contract $205 $205 $260 $260 $205 $0 Mthly Total $217 $393 $532 $394 $286 $44 Cumulative $217 $610 $1,142 $1,535 $1,821 $1,865 At the end of the pre-construction phase, TGVI will have developed revised cost estimates and have the EPC and other construction contracts in place. TGVI proposes to proceed with the Project at that time provided that the expected costs are still within the P50 to P90 range discussed in this Application. Page 19

26 Mt. Hayes LNG Storage Facility TGVI will record the expenditures relating to these pre-construction development activities in a non-rate base deferral account. These costs will be included in the Project costs for consideration as rate base upon completion of the Project. If at the conclusion at this preconstruction phase the Project does not proceed as a result of unexpected cost escalation, as part of this Application TGVI is requesting approval that these costs be recovered from customers as part of TGVI s approved cost of service by amortizing over a five year period the amounts prudently spent Project Management TGVI will set up a Project team that will include personnel from TGVI and TGI and other parties to manage the LNG Storage Facility and System Facilities Projects. The Company personnel involved in the Project team will draw on TGI s considerable experience in managing and completing major projects on time and on budget and experience in the development of the previous and current applications. The Project manager, who in turn will report to a Project sponsor, will direct all phases of the Projects after BCUC approval and will execute the overall Projects utilizing experienced contractors, consulting professionals and Company personnel. The Project manager will implement a Project execution plan for the development of each segment of the Project including design and construction quality assurance for all phases. The majority of specialized services required for environmental management and design and construction inspection will be under contract to individuals and companies with the demonstrated skill and experience to complete the work. The Project manager will implement a Project office team with the resources to manage overall Project costs and provide procurement, accounting and administration support. TGI operating personnel, experienced at TGI s Tilbury LNG Facility, will be deployed to the Project for design review to assist in ensuring the facility can be efficiently placed into operation upon completion of construction. TGVI will enter into a turnkey EPC contract for the major portion of the LNG Storage Facility, including all work inside the facility fence after site grade has been established. The EPC contractor will manage the design, procurement and construction of the facility according to performance specifications and contract conditions contractually agreed to with the Project team. Page 20

27 Mt. Hayes LNG Storage Facility The Project manager will execute design and construction of the System Facilities and the electrical substation and power line associated with the LNG Storage Facility through the use of local consultants and contractors, managed under the control of the Project office Environmental Assessment As part of the permitting process supporting the 2004 project proposal, TGVI prepared an Environmental and Social Review Report ( ESR ) which concluded that no residual postmitigation significant impacts are expected to result from the construction and term operation of the facility. The ESR contemplated the installation of a 1.5 Bcf storage tank and associated facilities and therefore still applies to the current 1.5 Bcf facility proposal. Section 2.0 of Appendix A provides a summary of the ESR. The ESR will be reviewed and updated during the 2007 updating phase to ensure TGVI addresses all potential environmental impacts. TGVI will fulfil all required environmental commitments and mitigation measures for the LNG Storage Facility. The full ESR Report 1 was reviewed during the regulatory proceeding for the 2004 project proposal and in its February 2005 Decision (Section 7.7) the Commission concluded that Environmental issues at the proposed Mt. Hayes site were considered in some depth in the ESR and with two exceptions, no significant environmental impact from the proposed facility was discovered. The two exceptions relate to water and aquatic systems and vegetation, both of which can be neutralized with mitigation efforts recommended in the report. TGVI will fulfil all required environmental commitments and mitigation measures for the Project. With respect to the System Facilities, the ESR included an assessment of the pipelines and gas measurement/odourization facility. The modifications to the TGVI system to accommodate bidirectional flow was beyond the scope assessed in the ESR. However, this additional work, including check valve replacements, Texada compressor station modifications and Eagle 1 The complete ESR report can be downloaded from Terasen Gas s website at the following location Page 21

28 Mt. Hayes LNG Storage Facility Mountain custody transfer modifications, is within the compounds of existing TGVI facilities and will have no significant environmental impacts Other Approvals The design, construction and operation of natural gas facilities, transmission pipelines and pipeline facilities are regulated by the OGC, enforcing established provincial legislation, and provincial and national codes. Section 3.0 in Appendix A lists the key standards, codes, and approvals relating to the projects. A 5 km long, 18 m wide ROW for the pipelines was previously approved by the OGC and TGVI anticipates no issues in renewing the approval which expires in April The pipelines ROW will be adjacent to the 7m wide power line ROW, which are shown in Figure 1-4, Section of Appendix A Public and Stakeholder Consultation Section 5.0 of Appendix A provides information on the public consultation process undertaken for the 2004 application. This process was reviewed during the 2004/05 proceedings and in the February 2005 Decision (Section 7.6) the Commission concluded that: The public consultations carried out by TGVI appear to have been adequate and there was a comprehensive attempt to explain the operation and safety-related issues of an LNG storage facility to members of the general public. The Commission Panel notes that there were no adverse submissions by any intervenor in this proceeding that centred upon safety or environmental concerns related to the LNG storage facility. TGVI will ensure to keep all commitments made during the previous development process public consultation and continue ongoing stakeholder consultation efforts Public Consultation Program The Public Consultation and Siting discussion in Section 5.0 of Appendix A outlines the comprehensive site selection and public consultation program that was undertaken in 2003 and Page 22

29 Mt. Hayes LNG Storage Facility 2004 to engage the public and locate a suitable site for the project. This program culminated in the successful rezoning of the subject Mt. Hayes property. Following the submission of the 2004 application TGVI issued 2 project newsletters (explaining the LNG project, its status and the expected impacts on the local community) to approximately 3,000 of the closest households to the Mt. Hayes site following the rezoning and prior to the decision not to proceed with the LNG project in Since that time, TGVI has continued to communicate on a regular basis with the local key stakeholders of the Mt. Hayes LNG Storage Facility project including the CFN, CVRD, Regional District of Nanaimo, Town of Ladysmith and City of Nanaimo, and support for the Project remains strong. As the Project proceeds, TGVI will communicate project developments in a timely fashion, including a quarterly newsletter to local residents and other stakeholders. TGVI will address any stakeholder concerns or potential negative impacts and will work to ensure the positive benefits of the project for the local community are realized First Nations The LNG Storage Facility and the connecting power line and pipelines fall within the traditional territory of the Chemainus First Nation ( CFN ). TGVI successfully negotiated an MOU with the CFN in 2005 and has continued to consult with the CFN to maintain the relationship and provide updates on the status of the project development. TGVI will continue to work with the CFN to ensure their interests are taken into account and that the project will provide benefits to the Band in accordance with the MOU. In addition, the Cowichan Tribes (First Nations based in Duncan) and TGVI have a long history of working together on Vancouver Island and Cowichan has approached TGVI regarding potential business opportunities related to the Project. TGVI and CFN, along with the Cowichan Tribes, will continue to have on going discussions with respect to opportunities that may be available if the Project proceeds Resource Plan Consultation The 2004 and 2006 TGVI Resource Plans also provide details of stakeholder consultation for the preparation and review of those plans. Since both plans recommend the construction of the Mt. Hayes LNG Storage Facility as part of the preferred resource portfolio, much of the related stakeholder consultation included a focus on gathering feedback from stakeholders in regard to the project. Details regarding those consultation efforts are included in Section 7 of the 2004 Resource Plan and Section 8 of the 2006 Resource Plan respectively. Page 23

30 Mt. Hayes LNG Storage Facility Socio Economic Assessment The construction of the LNG Storage Facility will provide positive benefits to local Vancouver Island communities as well as to British Columbia and Canada. The 2004 ESR included an assessment of the socio-economic effects of a 1.0 Bcf facility based on the cost estimates at that time. The effects of the Project implementation, based on the current P50 capital cost estimate, are shown in Table 3-3. Table 3-3 Socio- Economic Effects Economic Effects $Million Local Area All BC Canada (ex BC) Ex- Canada TOTAL Total $50.3 $73.0 $22.8 $69.5 $165.3 Employment Person-Yrs Direct Indirect Total Once in operation, the LNG Storage Facility is expected to employ 9 full time employees and generate approximately $150,000 in local expenditures annually (not including electricity and fuel gas). In addition the region will benefit from the local property taxes paid on the LNG Storage Facility Project Schedule LNG Storage Facility Project Schedule Figure 3-1 is a schedule of the timing of major elements of the LNG Storage Facility Project. TGVI is confident the LNG Storage Facility can be constructed, commissioned and the tank filled within 46 months from the award of the design-build EPC contract. The major elements of the schedule critical path are the receipt of BCUC approval of the items requested in this Application, the development and successful negotiation of the EPC contract in Page 24

31 Mt. Hayes LNG Storage Facility the updating phase, the site preparation work and the construction and commissioning of the LNG Storage Facility System Facilities Project Schedule Figure 3-2 is a schedule of the timing of major elements of the System Facilities Project work. TGVI is confident the Projects can be constructed and commissioned within the 3 ½ year construction period to operate in conjunction with the LNG Storage Facility. The extended time period for System Facilities implementation means TGVI can plan for construction in specific time periods to minimize any potential negative environmental impacts and minimize construction costs. The schedule for each segment of the System Facilities is of short duration relative to LNG Storage Facility Project schedule and each sub-project will be completed prior to being required to go into service. Page 25

32 Mt Hayes LNG Storage Facility Figure 3-1 LNG Storage Facility Schedule ID Task Name Duration Qtr 1 Qtr 2 Qtr 3 Qtr 4 Qtr 1 Qtr 2 Qtr 3 Qtr 4 Qtr 1 Qtr 2 Qtr 3 Qtr 4 Qtr 1 Qtr 2 Qtr 3 Qtr 4 Qtr 1 Qtr 2 Qtr 3 Qtr 4 1 BCUC 3 mons 2 Application Preparation 1 mon 3 Application Approval 2 mons 4 UPDATING PHASE 6 mons 5 LNG Facility EPC 6 mons 6 Contract Negotiation 2 mons 7 Design Development 2 mons 8 Geotechnical Evaluation 2 mons 9 Cost Development 3 mons 10 Owner's Project Work 3 mons 11 Power Line Update 2 mons 12 Site Prep Design/Contract 3 mons 13 ESR Update 2 mons 14 APPROVALS UPDATING 3 mons 15 OGC - Facility 3 mons 16 Prov Ministries - Permits 2 mons 17 DECISION TO PROCEED 0.25 mons 18 ONGOING COMMUNICATION 49 mons 19 LAND 3 mons 20 Exercise Site Option 0 mons 21 R-O-W Acquisition 3 mons 22 CONSTRUCTION 41 mons 23 TSI Project Work 12 mons 24 Site Grading 4 mons 25 Road Improvements 3 mons 26 R-O-W Preparation 3 mons 27 Power Line 3 mons 28 LNG Facility EPC 37 mons 29 Facility EPC On-Site 30 mons 30 Commission & Test 3 mons 31 Final Acceptance 4 mons 32 FILLING 5 mons 33 Operation by TGVI 5 mons 34 RESTORATION 3 mons Page 26

33 Mt Hayes LNG Storage Facility Figure 3-2 System Facilities Schedule ID Task Name Duration Qtr 1 Qtr 2 Qtr 3 Qtr 4 Qtr 1 Qtr 2 Qtr 3 Qtr 4 Qtr 1 Qtr 2 Qtr 3 Qtr 4 Qtr 1 Qtr 2 Qtr 3 Qtr 4 Qtr 1 Qtr 2 Qtr 3 Qtr 4 1 BCUC 3 mons 2 Application Preparation 1 mon 3 Application Approval 2 mons 4 UPDATING PHASE 4 mons 5 Design & Cost Update 2 mons 6 ESR Update 2 mons 7 OGC - Facilities 4 mons 8 Prov Ministries - Permits 2 mons 9 DECISION TO PROCEED - LNG 0.25 mons 10 DECISION TO PROCEED 0 mons 11 ONGOING COMMUNICATION 35 mons 12 LAND 3 mons 13 R-O-W Acquisition 3 mons 14 TGVI PROJECT WORK 40 mons 15 R-O-W's Preparation 3 mons 16 Pipelines 6 mons 17 Gas Msmt/Odour Faciity 6 mons 18 Reverse Flow Facilities 6 mons Page 27

34 Mt. Hayes LNG Storage Facility Project Description Summary A more comprehensive Project description and development information, including work initially undertaken for the 2004 application, can be found in Appendix A. Much of the previous technical development work remains useful for the current proposal, and the current Application reflects information changes due to the facility size increase and timing. The LNG Storage Facility Project site requirements and overall environmental and safety impacts as was reviewed for the 2004 TGVI LNG application remain essentially unchanged for the current Application. TGVI will fulfil all public consultation commitments and mitigation plans of TGVI and maintain the level of communication and analysis noted in the 2005 Decision Section 7.6: In summary, TGVI has satisfied the Commission Panel that the selection of the proposed site was performed with adequate due diligence, sufficient public and municipal consultation, and with a comprehensive Environmental and Social Review and operational and safety considerations. The Commission Panel commends TGVI for the extensive background work, public education and thorough site analysis that have been carried out for the proposed Mt. Hayes facility. Subject to the further required approvals discussed above, the Mt. Hayes site seems well suited for the location of the project. The Commission Panel is satisfied that the construction and operation of the proposed LNG storage facility at Mt. Hayes, with the mitigation measures and safeguards proposed by TGVI, would not result in any significant health, safety or other impacts on the public. The LNG Storage Facility Project execution will be managed by an experienced Project team to direct all Project management activities, from approvals, contracting and design to construction and commissioning. Increased facility size and the delay of more than 2 years from the 2004 application construction timing have resulted in higher capital costs for the larger facility. The timeframe to complete the Page 28

35 Mt. Hayes LNG Storage Facility Project includes upfront effort to minimize the Project cost and range of potential cost variation, and provides for the LNG Storage Facility to be in service by April 1, 2011 to allow complete fill of the storage tank to meet the 2011/12 winter requirement. Page 29

36 Mt. Hayes LNG Storage Facility 4. PROJECT COSTS This section provides the range of TGVI s cost estimates for the LNG Storage Facility and System Facilities based on current expectations. Updated cost estimate information for a 1.0 Bcf LNG storage facility is also provided to allow comparison to the estimates at the time of the 2004 application. The updated cost for a 1.0 Bcf facility reflects approximately a 40% increase from 2004, and provides perspective on the overall cost increase of LNG storage facilities due to escalating equipment and construction costs. The 1.0 Bcf LNG storage facility cost estimates also provide perspective on the capital costs of the 1.5 Bcf facility relative to the current cost of a 1.0 Bcf facility. TGVI believes that these cost estimates provide a reasonable forecast of the costs of the Project based on proceeding with project implementation by December 1, TGVI is therefore requesting approval of this Application provided that once the pre-construction activities discussed in section 3.4 are complete and the major construction and equipment procurement arrangements are in place, the expected direct costs continue to fall within current P10 to P90 cost estimate range discussed in this section. TGVI recognizes, however, that given the current construction environment, there is some potential for unexpected cost increases. In that circumstance, TGVI expects that it would be required to demonstrate that Project continues to be in the best interest of customers prior to triggering construction of the Project Capital Cost Forecast EPC Cost Development In the development of the Mt. Hayes LNG Project for the 2004 application to the BCUC, an EPC LNG contractor was engaged in a sole source process to proceed with the development of a design-build contract and contract price for a 1.0 Bcf LNG facility. TGVI plans to continue with this contracting strategy. The rationale to continue with the contracting strategy remains as explained in the 2004 application, and is even further reinforced in the current high industry activity levels. The sole source process allows the negotiation of contract terms and conditions and allocation of risks to the party best able to manage each risk. The sole source process allows the Project Page 30

37 Mt. Hayes LNG Storage Facility team to be part of the design specification and work scope development resulting in fewer potential change orders (minimizing future additional cost and schedule delays) during the construction and commissioning phase. The contract allows access to all of the contractor s price development information prior to finalization of the firm price, allowing owner input to alternatives selection. The process allows the contractor to minimize the contingencies included in its EPC price based on the scope of work and contract terms and conditions agreed to with the Project proponent. TGVI undertook a cost risk analysis of the EPC pricing in late 2006 and has incorporated the results in the range of EPC estimates in the overall project estimates. To achieve the best EPC contract pricing in the current high level of industrial construction activity, a key objective will be to minimize the cost uncertainty in key elements of the Project including major equipment items, base materials and labour productivity and cost. Developing facility EPC pricing as close as possible to the construction start date minimizes the forward cost uncertainty and helps to minimize the cost uncertainty on the two and one-half year construction period for the EPC contractor and therefore the cost to TGVI.. EPC price increases from the estimates used in the 2006 TGVI Resource Plan have been driven by the following key issues: Significant cost increases in raw materials prices, including steel, nickel, copper and aluminium Increases in the cost of manufactured equipment, including compressors, pumps, valves, etc. due to raw materials price increases, increasing demand and increasing cost of labour Increases in the cost of construction equipment, similar to manufactured equipment Increases in subcontractor costs, reflecting increases in equipment, labour, fuel, etc. Decreases in skilled trades and labour productivity due to shortages and increasing level of less experienced resources Increases in the cost of skilled trades and labour due to heated industry activity, and competition for skilled personnel. In discussions with qualified EPC contractors, TGVI has been advised that given the current construction environment a firm fixed price for the LNG Storage Facility project can be developed, but would likely contain significant contingency for the items with potential for high Page 31

38 Mt. Hayes LNG Storage Facility cost volatility over the project life. During the pre-construction development phase, TGVI will work with the EPC contractor to evaluate the benefits and risks to having defined elements of the EPC pricing as fixed or cost reimbursable. Currently identified elements that could be considered for pricing as cost reimbursable are the major equipment items (where vendors are currently very reluctant to provide even budgetary pricing), major materials (i.e. tank plate steels) and skilled trades and labour. The potential overall cost reimbursable component of the full EPC price could range from 0% to 40%. For all cost reimbursable components TGVI will undertake a cost risk analysis to assess the potential for cost over runs LNG Storage Facility Capital Cost Estimates TGVI s current cost estimates for the LNG Storage Facility have been developed using pricing obtained during the 2005 development of the 1.0 Bcf project facility, information supplied by consultants, contractors and TGI internal resources, utilizing TGI/TGVI experience in project management of other major capital projects. In 2005 TGVI received a firm EPC price for a 1.0 Bcf LNG facility. Since that time TGVI has received budgetary EPC estimates for both 1.0 Bcf and 1.5 Bcf facilities which provide perspective on general cost increases as a whole and the cost of increasing the size of the facility from 1.0 to 1.5 Bcf. The Owner s components (i.e. those components outside of the EPC scope) of the LNG Storage Facility capital costs, including the power line and substation, have been escalated from the 2005 detailed estimates. Capital cost estimates have increased from the 2005 detailed estimates and the escalated estimates presented in the 2006 TGVI Resource Plan. The Resource Plan estimates were based on escalation of 2005 pricing which included a firm EPC price for the 1.0 LNG facility and estimates of Owner s costs. Subsequent to the 2006 Resource Plan, updated budgetary prices for the LNG Storage Facility and off-site work have been developed and the cost increases have been included in the estimates in the Application. Table 4-1provides the estimated direct and capital cost estimates for the LNG Storage Facility for different degrees of confidence. These costs represent the total expected costs, excluding AFDUC, for the LNG Storage Facility including the EPC Contract and the Owner s Costs. The Page 32

39 Mt. Hayes LNG Storage Facility as-spent estimates assume that the TGVI executes the EPC contact and issues authorisation to proceed to the contractors by December 1, Table 4-1 LNG Storage Facility Costs LNG Storage Facility Costs (Direct 2007$ millions) P10 P50 P Bcf LNG Facility $154.9 $165.0 $ Bcf LNG Facility $116.3 $124.9 $140.8 LNG Storage Facility Costs (As Spent$ millions) P10 P50 P Bcf LNG Facility $155.7 $166.0 $ Bcf LNG Facility $116.8 $125.7 $141.6 The EPC contract, for the full scope of work, and will be a fixed lump sum, or fixed lump sum with a cost reimbursable component. The fixed sum which will limit the potential for further cost escalation during the construction for those components that within the EPC scope of work..any changes to the EPC scope of work that may occur over the detailed design or construction period could result in further costs or savings that could impact the final EPC contract costs, however these are expected to be minimal. The major components of the outside of the EPC scope of work included in the Owner s Costs will either be executed immediately (i.e. the site civil preparation and Project insurance) or within the first year (i.e. power line and substation) while Project management and construction over-sight costs will be spread evenly over the course of the 2 ½ year construction period System Facilities Capital Cost Estimates TGVI, in the development of the Mt. Hayes LNG project for the 2004 application to the BCUC, completed cost estimates for the connecting pipelines and gas measurement and odourization station based on TGVI and TGI experience in project management of other major system capital projects and information provided by consultants and contractors. For the current Application TGVI has updated the capital estimates for the pipelines and station from the 2005 estimates. TGVI has also now included the costs of the TGVI transmission system modifications, which Page 33

40 Mt. Hayes LNG Storage Facility were not in the scope of the 2004 application rationale for the project, to accommodate bidirectional flow in the system. These estimates are based on previous TGVI and TGI experience in transmission projects. The capital cost estimates for natural gas facilities have increased from those in the 2004 application due to the cost increases for materials and manufactured equipment (including pipe, valves, etc.) and for construction cost in the current heated construction industry. Table 4-2 provides the estimated direct and as-spent capital costs for System Facilities based on the start of construction of the LNG Storage Facility in December The System Facilities scope is for all work outside implemented directly by TGVI outside of the fenceline of the LNG Storage Facility. These costs in Table 4-2 are not included in the Owners costs that form part of the LNG Storage Facility costs summarised in Table 4-1. Table 4-2 System Facilities Project Costs (Direct 2007$ millions) P10 P50 P90 Pipelines $6.0 $6.4 $6.8 Msmt & Odor Stn $0.8 $0.8 $0.9 Reverse Flow Facilities $2.1 $2.4 $2.7 Project Management $0.1 $0.1 $0.1 Contingency $0.5 $1.0 $1.5 Projects for 1.5 Bcf Facility $9.5 $10.7 $12.0 Projects for 1.0 Bcf Facility $6.3 $7.1 $7.9 (As Spent$ millions) P10 P50 P90 Projects for 1.5 Bcf Facility $10.4 $11.6 $13.2 Projects for 1.0 Bcf Facility $6.9 $7.8 $8.7 Page 34

41 Mt. Hayes LNG Storage Facility The direct 2007$ for System Facilities activities will be coordinated with the construction of the LNG Storage Facility Project so that costs are minimized while still meeting the commissioning and operational requirements. The pipeline laterals and gas measurement/odourization station will be completed to align with the need for gas delivery for testing and commissioning of the LNG Storage Facility late in The TGVI transmission system modifications to accommodate reverse flow are required to be in service for the winter of 2011/12 and thus will not likely be constructed until the middle of The System Facilities scope of work is typical of project work at TGVI, and is subject to many of the same project cost risks as the EPC contract, i.e. material and equipment cost volatility and heated construction environment. The 3 ½ year schedule for the Project over which expenditures will be made adds further potential for cost variance from the estimates. The updated estimates will reflect the current cost environment and reduce the P10 to P90 cost range to the extent reasonably possible Capital Cost Approvals TGVI believes that the cost estimates described in Section for the LNG Storage Facility and Section for the System Facilities provide a reasonable forecast of the costs of the Project based on TGVI issuing authorisation to proceed December 1, It is on this basis that TGVI is requesting approval of this Application provided that once the major construction and equipment procurement arrangements are in place, the expected direct costs continue to fall within current P10 to P90 cost estimate range. TGVI recognizes, however, that given the current construction environment, there is some potential for unexpected cost increases. In that circumstance, TGVI expects that it would be required to demonstrate that Project continues to be in the best interest of customers prior triggering the construction of the Project Operating Costs Project Operating Costs The fixed (i.e. do not vary with liquefaction or sendout volumes) operating costs ( fixed O&M costs ) for the LNG Storage Facility are based on actual and budgeted operating costs of the TGI Tilbury LNG Facility in Delta, B.C. The fixed O&M costs also include adjustments to account for the larger facility size and maintenance of the access road. Property taxes are Page 35

42 Mt. Hayes LNG Storage Facility based on estimated assessment values and are included in the financial evaluation discussed in Section 8 but are not included in the fixed O&M costs shown below. Table 4-3 Fixed Annual Operating Costs LNG Storage Facility Fixed O&M 2007 $ Bcf Facility 1.5 Bcf Facility Operators Salary & Benefits $778 $850 Training & Expenses $68 $79 Misc. Materials $57 $71 Consulting $10 $10 Outside Services $121 $152 Sales of LNG $0 $0 Site & Access $51 $56 Insurance $153 $198 Annual Facility Fixed O&M $1,239 $1,416 Trained operating personnel and management will make all decisions relating to the day-to-day operation of the LNG Storage facility, and be responsible for compliance with all permits and approvals, including environmental and emergency preparedness and response. TGVI will ensure training is provided for operating personnel and ensure O&M manuals and EH&S programs are maintained, as a minimum to the levels provided for the operation of TGI s Tilbury LNG Facility. TGVI will incur estimated additional operating cost of $10,000 per year for the 5 km of pipelines and additional facilities described as the System Facilities Project. TGVI will also incur additional Shared Services costs from TGI and other TGVI departments to cover incremental costs and time commitments for site servicing contracts (i.e. waste removal, janitorial, etc.), back office administrative support and centralized service O&M functions such as Instrumentation & Communication Services and Corrosion Services). Page 36

43 Mt. Hayes LNG Storage Facility Variable costs reflect the annual electricity and natural gas used during liquefaction, send-out and holding operations of the LNG Storage Facility. Table 4-4 below summarises the total annual incremental operating and maintenance costs assuming that on average 50% of the storage tank volume is used and re-filled. Table 4-4 Project Operating Costs 2007 $ Bcf 1.5 Bcf Fixed O&M Facility Fixed O&M $1,239 $1,416 System Facilities $10 $10 Shared Services $134 $134 Total $1,383 $1,560 Variable O&M Electricity $456 $671 Fuel Gas, GJ 20,234 28, Project Cost Summary The current cost estimates for the LNG Storage Facility and the System Facilities are summarised in Table 4-5. These estimates provide the basis for the financial assessments that support this Application. Table 4-5 Costs Forecast Probability Direct 2007$ Millions P10 P50 P90 LNG Storage Facility $154.9 $165.0 $185.7 System Facilities $9.5 $10.7 $12.0 Total Project Costs $164.4 $175.7 $197.7 TGVI believes that these cost estimates provide a reasonable forecast of the costs of the Project based on TGVI issuing authorisation to proceed December 1, In order to obtain higher confidence in these estimates, TGVI will engage in the pre-construction development phase described in Section 3.4 to confirm the design, costing and construction schedule for the 1.5 Bcf facilities leading to execution of the EPC contract by 1 December Page 37

44 Mt. Hayes LNG Storage Facility TGVI will provide an updated cost estimate report upon completion of the pre-construction activities and prior to issuing authorisation to proceed. At this time, TGVI is requesting approval to proceed with the Project provided that once the major construction and equipment procurement arrangements are in place, the expected direct costs continue to fall within current P10 to P90 cost estimate range. In the circumstance that cost estimates are higher than this range, TGVI expects that it would be required to demonstrate that Project continues to be in the best interest of customers prior to triggering the construction of the Project. Page 38

45 Mt. Hayes LNG Storage Facility 5. LNG STORAGE FACILITY COST RECOVERY 5.1. Overview This Application is seeking approval for TGVI to build, own and operate the LNG Storage Facility at the Mt. Hayes site and to build the System Facilities to connect from the site to its transmission system. TGVI proposes to recover the incremental cost of service related to the Project through its customer rates and through revenue it will receive from TGI for storage services under the Storage and Delivery Services Agreement. As part of the request for approval of the Project, TGVI is seeking a return on equity on the rate base associated with the LNG Storage Facility that will allow for returns that are more comparable to those allowed for similar investments elsewhere in North America. TGVI is also seeking to establish depreciation rates for the LNG Storage Facility assets. In addition, TGVI and TGI will enter into a long term agreement (the Storage and Delivery Services Agreement) whereby TGVI will provide a provide storage services to TGI based on a portion of the LNG capacity. TGI will make annual payments to TGVI based on a fixed price that reflects the current view of the cost of new long-term storage resources redelivered to TGI s service area. The revenue from TGI will be directly credited against the cost of service of the LNG Storage Facility, thereby reducing the costs to be recovered from TGVI customers A Fair Return on Equity TGVI is requesting a return on equity associated with the LNG Storage Facility that would allow for an additional 50 basis points above that which TGVI would otherwise realize. As discussed more fully in Appendix B, and summarised below, TGVI believes that this request would allow TGVI to earn returns on this capital investment that are more comparable, although still lower, than those realized by similar investments elsewhere in North America. The LNG Storage Facility will provide a valuable peaking gas supply resource for both TGVI and TGI as part of their overall gas portfolios and reduce their dependence on downstream storage resources and/or upstream pipeline capacity. In addition, as an on- system resource, the LNG Page 39

46 Mt. Hayes LNG Storage Facility Storage Facility will allow TGVI to improve the efficiency and reliability of its existing transmission system. As discussed in Section 7.1.2, natural gas infrastructure is becoming increasingly constrained during winter peaking periods in the Pacific Northwest region in which TGVI and TGI compete for supply. In order to meet the growing peaking requirements of their customers, TGVI and TGI s gas supply alternative to the LNG Storage Facility is to promote incremental third party investment in off-system storage resources and/or upstream pipeline capacity through long term contractual commitments. TGVI believes that the public interest is served by fair and appropriate utility returns on investment. Low returns on equity will, over time, result in underinvestment in infrastructure that in turn will lead to negative outcomes such as energy price volatility and decreased system reliability. TGVI believes that the utility returns on equity in BC and Canada are too low in general but in particular for large infrastructure investments such as the LNG facility the returns are well below those for similar investment in the US. In addition there appears to be growing recognition by energy industry participants and stakeholders, including policymakers in government, regulators and industry, that more favourable investor returns are required to promote the security, reliability and cost-effectiveness of the energy delivery systems. In addition, in Canada the dominance over the last ten to fifteen years of utility ROEs being set by formula-based mechanisms employing an equity risk premium approach relative to long Canada bond yields has led to widening gap in approved returns for Canadian local distribution utilities and transmission providers relative to their U.S. counterparts. These trends affect the longer-term ability of Canadian utilities to attract capital. While the short term impact of these trends on energy infrastructure may not be obvious, in the longer term where investment risk is similar, rational investors will put their money in higher return investments. TGVI believes that the LNG Storage Facility will provide significant value to the customers of TGVI and TGI. It will also deliver benefits beyond the service territories of TGVI and TGI by enhancing the robustness and reliability of energy infrastructure in the Pacific Northwest. As discussed in Section 7 and 8 of this Application, the alternative to the LNG Storage Facility would be to meet the specific gas portfolio resource requirements by contracting for third party storage or pipeline resources, if and when available, and to meet TGVI transmission capacity Page 40

47 Mt. Hayes LNG Storage Facility requirements by adding compression and pipeline looping as required. This alternative requires less upfront capital investment by TGVI, however is not as cost effective and would not deliver the same level of benefits to customers. On the basis of all these considerations, TGVI believes its ROE request for the rate base associated with the LNG Storage Facility of TGVI s allowed ROE plus 50 basis points to be fair, reasonable and appropriate LNG Storage Facility Cost of Service TGVI is proposing to build, own and operate the LNG Storage Facility and System Facilities as part of its overall natural gas transmission and distribution system. The annual revenue requirement associated with the LNG Storage Facility will be determined based on current approved ratemaking principles, however as discussed in the previous section, the allowed ROE includes 50 basis point return over and above that allowed under TGVI s ROE as determined from time to time. TGVI is proposing an adjusted depreciation schedule to help mitigate the initial impact of the upfront capital investment. The annual revenue requirement associated with the System Facilities will be determined based on the same principles as the current transmission plant and is not included in the discussion in this section. The revenue requirement associated with the System Facilities is included in the Sections 7 and 8 supporting the financial justification of the Project Adjusted Depreciation Schedule The financial evaluation of the LNG Storage Facility in this Application has been based on average depreciation expense of approximately 3% per annum. This is consistent with the treatment proposed by TGVI in its 2004 application and is based on the findings of a Depreciation Study conducted by Gannett Fleming Valuation and Rate Consultants Inc. in 1999 for TGI. Under current approved rate-making principles, straight line depreciation would be applied over the life of the Project, which results in a declining rate base and associated revenue requirement over the life of the facility. Page 41

48 Mt. Hayes LNG Storage Facility In order to reduce the impact of the large upfront capital investment associated with the LNG Storage Facility, TGVI is proposing to apply a modified depreciation schedule over the initial 20 years of operation of the facility. As illustrated in Figure 5-1, the modified depreciation schedule reduces the depreciation expense in the early years of the project, and thereby will also the revenue requirement over the same period. The impact of this adjusted depreciation schedule to TGVI s shareholder is deferral of capital recovery and a reduction in annual cashflows in the earlier years of the Project. The accumulated depreciation at the end of the initial 20 years would be equivalent to depreciation that would have been recorded that if straight line depreciation had been applied (approximately 60%) at which point the depreciation expense would revert to 3% per annum. The proposed depreciation schedule for the LNG Storage Facility and the impact on the annual depreciation expense is shown in Figure 5-1. Figure 5-1 Proposed Depreciation Schedule $10 $Millions $9 $8 $7 $6 $5 $4 $3 2.1% 2.1% 2.1% 2.2% 2.2% 2.2% 2.3% 2.4% 2.5% 2.6% 2.8% 3.0% 3.1% 3.3% 3.5% 3.8% 4.0% 4.3% 4.6% 4.9% 3.0% 3.0% 3.0% Adjusted Depreciation Straight Line Depreciation 3.0% 3.0% 3.0% 3.0% 3.0% 3.0% 3.0% 3.0% $2 $1 $ Annual Revenue Requirement The direct financial impacts to customers of the proposed depreciation schedule can be illustrated by comparing TGVI s expected annual revenue requirement under the proposed structure to a revenue requirement forecast determined by using straight-line depreciation. Page 42

49 Mt. Hayes LNG Storage Facility This comparison is provided in Figure 5-2 for the P50 Capital Cost estimate for the LNG Storage Facility. The adjusted depreciation schedule was determined to allow for a lower initial revenue requirement that would be forecast to increase by 1% per annum. Under straight line depreciation scenario, the higher depreciation expense initially results in a higher revenue requirement which declines over time as the rate base declines. Detailed schedules summarising the financial assumptions and the cost of service calculations are provided in Appendix F of this Application. TGVI s current allowed ROE is 9.07% (based on the current BCUC approved formula) which if unchanged would give rise in an ROE of 9.57% for the LNG Storage Facility. The financial evaluations provided in the 2006 Resource Plans and this Application however, assume that over the long term TGVI s allowed ROE based on the current approved formula will average 9.5%. Consequently the long-term ROE assumed for the LNG Storage Facility for the purposes of the financial evaluations and comparisons provided in this Application is 10%. As illustrated in Figure 5-2, the proposed depreciation schedule initially reduces the annual costs to customer. The expected revenue requirement under the proposed treatment of the LNG Storage Facility allows TGVI to better match the costs of LNG Storage Portfolio with the expected avoided costs of transmission system upgrades that would otherwise be required over the 25 year planning period evaluated in the 2006 Resource Plan. Figure 5-2 Annual Cost Comparison Annual Revenue Requirement $26 $24 $22 $20 $18 $16 $14 $12 $ Millions Adjusted Depreciation Straight Line Depreciation $ Page 43

50 Mt. Hayes LNG Storage Facility Present Value Assessment The present value of TGVI s cost of service related to the LNG Storage Facility is illustrated in the Figure 5-3 based on the P50 capital cost scenarios. The figure compares the present value of the annual cost of service under different scenarios over the 15 and 25 year planning periods evaluated in the 2006 Resource Plans. Note that the first year in the planning periods is 2007, therefore these evaluation periods include the first 11 and 21 years of operation of the LNG Storage Facility beginning in These values are presented based on the 6.2% and 10% discount rates used in the Resource Plan assessment. As discussed in Section 8 of this Application, the 6.2% rate is the long term forecast of TGVI s weighted average cost of capital while the 10% discount rate is a used to reflect uncertainty of future demand and costs. The Figure also illustrates the impact of the adjusted depreciation schedule. The results show that adjusted depreciation schedule helps to mitigate the costs over the shorter evaluation period resulting in savings to customers of $8 million on a present value basis. Over the longer term customers are relatively indifferent. Figure 5-3 Present Value Cost of Service Comparison 250 $Millions Straight Line Depreciation 200 Adjusted Depreciation Present Value Year 25 Year 15 Year 25 Year % Discount Rate % Discount Rate Page 44

51 Mt. Hayes LNG Storage Facility Capital Cost Impact The following table presents the range of the present value of the annual cost of service of the LNG Storage Facility based on the proposed depreciation schedule, under the different capital cost scenarios. The values corresponding to the 15 and 25 year evaluation periods are used in the overall economic evaluation and scenario analysis provided in Section 8. Table 5-1 Present Value of LNG Storage Facility Cost of Service $Millions Evaluation Period 6.2% Discount Rate 15 Year 25 Year P10 Capital $140 $219 P50 Capital $148 $230 P90 Capital $163 $254 10% Discount Rate Evaluation Period 15 Year 25 Year P10 Capital $111 $155 P50 Capital $117 $163 P90 Capital $129 $ TGI Storage Revenues Under the Storage and Delivery Agreement (the Agreement ), TGI will contract with TGVI for storage and delivery services. The proposed form of the Storage and Delivery Agreement is provided in Appendix C. Upon approval of this Application, TGVI and TGI will file an executed agreement with the Commission. The terms and conditions of this Agreement have been developed based on the LNG Storage and Delivery Agreement that had been prepared in support of TGVI s 2004 CPCN application and which was approved by the Commission under Order No. G dated May 18, The proposed Agreement has been revised from the agreement approved in 2005 to provide greater clarity and to reflect current arrangements. From a commercial perspective, the only significant changes from the 2005 agreement are as follows: Page 45

52 Mt. Hayes LNG Storage Facility TGI is guaranteed a minimum volume of 1.0 Bcf storage capacity, 100 MMcfd deliverability and 5 MMcfd of liquefaction over the first 20 years of the Agreement; and The price paid for the storage and delivery service is fixed over the initial 20 year term of the agreement based on the assessment of the cost of incremental market area storage as provided in Section 7.1 of this Application and Appendix G of the 2006 Resource Plan. In the 2004 application, the LNG facility was to be used primarily to serve TGVI capacity and peaking requirements on Vancouver Island. TGVI planned to mitigate its costs of holding the LNG facility by putting to TGI any capacity that it would not require from year to year, however TGI had no assurance on the volume or term of capacity it would be able to use. In the proposed Agreement in this Application, TGI is contracting for a fixed storage volume and capacity (Primary LNG Service) at a fixed cost which it will be able to use for long-term portfolio and capacity planning purposes. TGVI continues to hold the right to put any additional capacity associated with the remaining 0.5 Bcf storage volume to TGI from period to period (Supplemental Service) upon provision of 24 months notice. The Supplemental Service is priced based on the same market value as the Primary LNG Service Terms and Conditions The principal terms of the Agreement are as follows: Commencement date of April 2011; Minimum Contract term of 35 years; Receipt and delivery points at Huntingdon or Eagle Mountain through displacement and/or physical redelivery if required; Capacity: o For the first 20 years TGI is guaranteed a minimum of 1.0 Bcf of storage capacity and 100 MMcfd of deliverability (the Primary Service ); and o The Primary Service contract levels can be decreased for the remaining term of the agreement to the degree that TGVI requires the capacity to serve its own customers. Price: o For the first 20 years, TGI pays a fixed monthly charge of $1,002,200 for the Primary Service; Page 46

53 Mt. Hayes LNG Storage Facility o For the remaining term, TGI pays a prorata share of TGVI s annual costs of service associated with the LNG Storage Facility for the Primary Service; and o Variable charges include pass through of variable electric charges and other commodity related charges. The revenues from TGI will go directly to reducing the cost of service of the LNG Storage Facility to TGVI s customers. TGVI s net revenue requirement, based on providing only Primary LNG Service to TGI, is illustrated in Figure 5-4 below: Figure 5-4 TGVI Net Revenue Requirement Annual Cost $Miilions $26 $24 $22 $20 $18 $16 $14 $12 $10 $8 $6 $4 $2 $0 TGVI Net Revenue Requirement TGI Storage Service Revenues The present value of the TGI payments to TGVI and TGVI s net revenue requirement (i.e.. the annual revenue requirement less the TGI payments) are summarised in Table 5-2 for the corresponding 15 and 25 year planning periods. Page 47

54 Mt. Hayes LNG Storage Facility Table 5-2 Present Value TGVI Net Revenue Requirement $Millions Evaluation Period 6.2% Discount Rate 15 Year 25 Year P10 Capital $50 $84 P50 Capital $58 $95 P90 Capital $73 $119 10% Discount Rate Evaluation Period 15 Year 25 Year P10 Capital $39 $58 P50 Capital $45 $66 P90 Capital $57 $82 Page 48

55 Mt. Hayes LNG Storage Facility 6. TGVI AND TGI CUSTOMER DEMAND TGVI and TGI are requesting approval of the LNG Facility Agreement and the Storage and Delivery Agreement to support the development of the LNG Storage Facility located on Vancouver Island. Through the proposed contractual arrangement the LNG Storage Facility will provide both utilities with incremental peaking gas supply and system capacity resources to help meet growing customer demand in the TGVI and TGI Coastal service regions. As demand on these systems continues to grow, the regional resources relied on to manage seasonal demand fluctuations are becoming more scarce since regional demand is also growing. This Section provides a summary of the relevant demand forecast information for TGVI and the TGI Coastal service areas and describes some of the seasonal challenges in meeting natural gas demand that impact the need for new resources. Since the proposed LNG Storage Facility will not serve TGI s Interior service area, Interior demand is not reviewed. The 2006 TGI and TGVI Resource Plans present the long-range customer and demand forecasts for the respective companies and evaluate the resource requirements to continue providing reliable service. In both cases, the Resource Plans concluded that an on-system LNG Storage Facility located on Vancouver Island will help to avoid costs of incremental gas storage requirements from resources located outside of the TGI and TGVI service regions. The LNG Storage Facility also has the potential to avoid costs for new facilities on each of the respective transmission systems TGVI Demand Forecast. The TGVI 2006 Resource Plan (Section 3) describes the demand forecast and methodology for TGVI core customers as well as the considerations for future demand from the Vancouver Island Gas Joint Venture ( VIGJV ), ICP, Squamish and Whistler. TGVI forecasts for both annual and design day demand, with the annual demand forecast predicting the most likely yearly consumption assuming normal weather conditions and the design day demand forecast identifying the highest expected daily consumption that might occur during extremely cold weather. The design day demand forecast is a critical factor when planning for system capacity requirements. Page 49

56 Mt. Hayes LNG Storage Facility Core Demand For core market customers, the forecast of demand for natural gas is driven by the forecast for future customer additions. In its Resource Plan TGVI develops a base demand scenario to identify the most likely expectation of future core customer additions and resulting demand for natural gas, as well as high and low demand scenarios to bracket the range of possible outcomes in core market customer growth. As noted below, minor updates to the long-term core demand forecast have been made since the submission of the TGVI 2006 Resource Plan, each having very little or no impact on future planning for the TGVI system. In its 2006 Settlement Update, submitted to the BCUC in October 2006, TGVI noted a change in the base number of 2005 customers used to determine the TGVI demand forecast. This rebasing of the 2005 customer number resulted when TGVI moved its customer database into new customer information system software. In the newer software (the same software currently used to manage TGI customer information) a number of accounts previously identified as customers did not meet the criteria for inclusion as a customer within the new system. The result of this finding is an adjusted starting point for the number of customers at the beginning of the forecast period. A short-term forecast update for both the customer additions and demand was also completed as an input into TGVI s 2006 Settlement Update. This forecast update included six additional months of actual 2006 data that was not available for inclusion in the TGVI 2006 Resource Plan, and was extended five years into the future to cover the 2007 to 2011 period. The net effect of the revised customer base and short-term forecast update on the long-term forecast of both design day and annual demand is small. To review the relative changes, the original demand forecast presented in Appendix E of the 2006 TGVI Resource Plan can be compared to the revised forecast incorporating the re-based customer numbers included in Appendix D of this Application Squamish and Whistler Demand TGVI will also be providing transportation service to two smaller service regions Whistler and Squamish. Service to Terasen Gas (Whistler) Inc. ( TGW ) will begin in the fall of 2008, when the existing propane distribution system is converted to natural gas. The 2006 TGVI Resource Page 50

57 Mt. Hayes LNG Storage Facility Plan also considered demand requirements over the planning horizon from Terasen Gas (Squamish) Inc., which on January 1 st 2007 was amalgamated with TGI Industrial Transport Demand TGVI also has two large industrial transportation customers: BC Hydro and the six mills that are represented by the VIGJV. As identified in the 2006 Resource Plan, following the closure of the Woodfibre mill, the VIGJV gave notice to reduce its firm contract demand from the current 12.5 TJ/d to 9.1 TJ/d as of April Based on discussions with the VIGJV, TGVI must assume an ongoing need to provide a minimum firm demand of 9.1 TJs/d for the foreseeable future. This is a significant reduction from the VIGJV firm demand forecast in the 2004 Resource Plan, and is also significantly lower than the mills capability to burn gas. It should also be noted that although the mills have reduced their firm contract demand under the transportation agreement, they continue to rely significantly on interruptible service to manage upset conditions, meet higher demands during winter periods and also to provide flexibility to respond to favourable market conditions. As discussed in Section of the TGVI 2006 Resource Plan, there remains some uncertainty in the requirement for firm system capacity to meet gas transportation requirements for BC Hydro to serve ICP. As identified in BC Hydro s 2006 Integrated Electricity Plan ( IEP ) and confirmed during ongoing discussions with BC Hydro, ICP will continue to be required as a firm energy and capacity resource beyond the IEP planning period of 20 years. However, given the size of the ICP load (45 TJ/d), TGVI would not proceed with transmission system expansions to meet ICP s requirements without a long-term commitment from BC Hydro. As a result, for the purposes of this Application TGVI s baseline demand scenario assumes that BC Hydro is not a firm transport customer. A second scenario, however, is assessed wherein BC Hydro enters a long-term agreement for firm gas service to ICP based on its current contract demand of 45 TJ/d and continues to provide curtailment rights based on the existing 53 hours of distillate fuel storage Design Year Temperature Variability As described in Section of the TGVI 2006 Resource Plan, the temperature profile used to determine the design year load duration curve is developed by averaging the five coldest years (ranking the days within each year from coldest to warmest) since 1961 and replacing the Page 51

58 Mt. Hayes LNG Storage Facility coldest day with the statistical design day temperature 1 represented in Heating Degree Days ( HDD ) 2. Figure 6-1 shows the design year temperature duration curve compared to those of the 5 coldest years from which it was derived. Figure 6-2 focuses on the coldest 30 days of this temperature duration curve and shows how the variability of temperatures is greatest within approximately the coldest 20 days of the curve. These graphs illustrate the range of potential temperatures around the design year temperature profile that need to be considered when planning resources to meet peak period requirements. Figure 6-1 TGVI Design Weather vs. Five Coldest Winters 35 Heating Degree Days Design N th Coldest Day of Year 1 Design day temperature estimated using extreme value analysis. 2 HDD and HDD18 refer to a measure of the coldness of the weather experienced. The number of heating degree days for a given day is calculated based on the extent to which the daily mean temperature falls below a reference temperature of 18 degrees Celsius. Page 52

59 Mt. Hayes LNG Storage Facility Figure 6-2 TGVI Design Weather vs Five Coldest Years First 30 days Heating Degree Days Design N th Coldest Day of Year Figure 6-3 displays the chronological weather data for each of the 5 years used in developing the design year temperature profile. Comparing this data further illustrates the potential variability in the distribution of weather in any one year from the design year temperature profile. The graphs highlight other weather factors that need to be considered in planning to meet gas supply requirements including the potential for multiple extreme cold weather events in a single year and the potential for sustained cold weather during peak period events. Note that for this comparison is based on Contract Year refers to the gas contract year, which is the period between November 1 st of any given year to October 31 st of the following year. Page 53

60 Mt. Hayes LNG Storage Facility Figure 6-3 Five Coldest Years Heating Degree Days for Winter Period Contract Year 1968 HDD Design Year Date 01/11/ /11/ /12/ /12/ /12/ /01/ /01/ /02/ /03/ /03/ /03/ Design Year Contract Year HDD /11/71 16/11/71 01/12/71 16/12/71 31/12/71 15/01/72 30/01/72 14/02/72 29/02/72 15/03/72 30/03/ Design Year 25.6 Contract Year 1978 HDD /11/78 16/11/78 01/12/78 16/12/78 31/12/78 15/01/79 30/01/79 14/02/79 01/03/79 16/03/79 31/03/ Contract Year 1984 Design Year HDD /11/84 16/11/84 01/12/84 16/12/84 31/12/84 15/01/85 30/01/85 14/02/85 01/03/85 16/03/85 31/03/ Design Year Contract Year 1985 HDD Design Day HDD18 = /11/ /11/ /12/ /12/ /12/ /01/ /01/ /02/ /03/ /03/ /03/1986 Page 54

61 Mt. Hayes LNG Storage Facility The data in Figure 6-3 shows that in 1984, the coldest temperature that occurred was reached on three separate days during two separate cold weather spells and 1971 each featured two extreme cold period peaks, with the second peak period lasting several days longer than the first was characterized by a sustained, early season peak in November, followed by a second cold peak much later in the season. It is these multiple and/or extended cold weather events, combined with experiencing a near design day temperature that will put the greatest strain on the TGVI gas transportation system s ability to meet peak demand. Gas supply and storage portfolios need to be flexible enough to balance both the cost of resources and the ability to meet demand under a wide range of weather patterns that could affect the entire British Columbia and Pacific Northwest region TGI Demand Forecast for the Lower Mainland Region The TGVI and TGI 2006 Resource Plans identified the benefits for TGI s Lower Mainland service area (also referred to as the Coastal Region) customers from TGI s participation in the LNG Storage Facility. As a result, TGI is proposing to contract for gas storage at the facility as part of its gas supply portfolio. An examination of gas supply portfolio alternatives therefore requires a review of the demand forecast for the TGI s Lower Mainland customers Lower Mainland Core and Transportation Demand The TGI demand forecast, presented in the TGI 2006 Resource Plan, shows that design day demand for core market customers in the Lower Mainland will continue to grow, while demand from transportation customer classes for TGI is assumed to have little or no net growth over the planning period. The details of the customer additions and demand forecast for the base scenario for TGI s Lower Mainland service area are contained in Appendix E of the TGI 2006 Resource Plan. Similar to TGVI, the short-term portion of the TGI forecast was updated in late 2006 to include actual data from the early part of the year in order to provide a revised 2007 demand forecast for the 2006 Annual Review and Mid-Term Assessment Review of TGI s Performance Based Rate Plan ( The TGI Annual Review ). There was no change in the Demand forecast methodology and the update resulted in only small adjustments to the TGI demand forecast as presented in the 2006 Resource Plan. These minor adjustments have no impact on the long-term transmission system planning for the TGI CTS. Page 55

62 Mt. Hayes LNG Storage Facility Lower Mainland Generation Demand TGI provides firm transportation service across the CTS to feed TGVI s transmission system at Eagle Mountain and to serve BC Hydro s Burrard Thermal Generating Station. TGI s 2006 Resource Plan identified that future expansions on the CTS will principally be driven by the future requirements of Burrard Thermal. BC Hydro s 2006 IEP indicates that three of the six generating units are currently required to provide firm capacity and that by 2009 all six units would be required. The IEP also indicated that BC Hydro is considering retirement of Burrard Thermal in 2014 provided the capacity can be replaced by that time. At the time the Resource Plan was prepared, three of six generating units were operational for both voltage support and electricity generation. As identified by BC Hydro during the 2006 IEP regulatory review, a fourth unit was re-commissioned in 2006 and is currently available for dispatch. Evidence provided at the BCUC hearing for BC Hydro s 2006 IEP, indicates that justification for advancing this recommissioning was based on meeting BC Hydro s system capacity requirements as well as providing other economic benefits 3. BC Hydro also indicated that feasibility studies to bring one or both of the remaining units on-line before 2009 are also currently underway, demonstrating a continued need for Burrard Thermal s dependable capacity. Through the IEP regulatory review process, it was also established that the replacement of the Burrard Thermal capacity is dependant on the proposed construction of the Interior to Lower Mainland (ILM) electric transmission reinforcement line. Further, although BC Hydro indicated that it expected that the ILM could be completed as early as 2014, there remains considerable uncertainty regarding the routing, permitting and construction schedule. BC Hydro also identified that the requirement for the ILM could be deferred for up to seven years under the scenario where Burrard Thermal remained operational or was repowered. Due to this uncertainty, as part of this Application TGI has further evaluated CTS expansion requirements assuming Burrard Thermal continues to require firm service beyond BC Hydro. August, Generation Operations Business Case: Recommissioning of Burrard G1. 12p. Exhibit B- 51 of the 2006 IEP / LTAP Hearing before the BCUC (BCUC Project No ). Page 56

63 Mt. Hayes LNG Storage Facility Lower Mainland Load Duration As with TGVI, TGI forecasts core load duration for both normal and design year conditions over the planning period. Section 3 of the 2006 TGI Resource Plan describes the methodology and results of the design year load duration forecast, represented as load duration curves. For planning purposes, since extreme cold weather events typically occur only when a deep Arctic air mass covers the entire province of BC 4, coincidental peaks are assumed for the design years of both the TGVI and TGI Coastal systems Peak Period Temperature Uncertainty Lower Mainland Since regional weather patterns affecting Vancouver Island would typically be affecting the Lower Mainland over the same period, multiple and or extended cold weather events that would affect TGVI would also affect the rest of BC. Therefore, discussion regarding temperature uncertainty for TGVI contained in Section above also applies to TGI. In the Lower Mainland, extreme weather events will impact a much larger customer base than that of TGVI, creating additional supply challenges during peak weather events Winter 2006/07 Cold Weather Event British Columbia experienced an extreme cold weather event early in the 2006/07 winter season. On Vancouver Island, temperatures reached a cold period peak 5 of -4 O C on November 27 th and -6 O C on November 28. These temperatures correspond with the 7 th and 4 th coldest days respectively of the TGVI forecast design year temperatures. As expected, temperatures on the same days in the Lower Mainland reached a similar cold peak of -5.7 O C and -8.4 O C, each temperature falling between the 6 th and 7 th and the 3 rd and 4 th coldest days respectively of the TGI Lower Mainland service area design year. Although temperatures (on Vancouver Island) in 2004 and 2005 dipped to -4.7 O C and -4.1 O C in January of each respective year, it has been ten years since similar temperature patterns to the November 2006 event were last reached. On January 29 and 30, 1996, the TGVI system experienced -5.7 O C and -4.3 O C respectively. In December the same year, temperatures moved 4 Pacific Meterology Inc., September Return Periods of Low Mean Daily Temperature for the Lower Fraser Valley. 6p. This report was provided to the Commission on October 20 th, 2006 in response to BCUC IR No. 1, Question 2.1, page 3 for the 2006 TGI Resource Plan. 5 Temperatures measured as the average of hourly temperature readings over a gas day Page 57

64 Mt. Hayes LNG Storage Facility between -5.1 O C and -3.8 O C over a 5 day period. While many years can pass between these extended cold events, the recent cold weather experienced across the Province underscores why the TGI and TGVI systems need to be designed to meet demand during extreme cold weather. Two aspects of the November 2006 cold weather event emphasize the challenges in planning for gas supply on the TGVI and TGI transmission systems. First, the fact that this event occurred so early in the heating season is critically important to meeting the gas supply requirements of core customers throughout the remainder of the winter. Second, the fact that this weather affected both TGVI and TGI service areas coincidently supports the need for peaking resources to serve both systems. The possibility that additional cold weather events will follow in the same winter season remains, affecting all of BC. Page 58

65 Mt. Hayes LNG Storage Facility 7. PROJECT JUSTIFICATION TGVI and TGI Resource Plans provide a long-term view of customer growth and assess the options available to the utilities to meet the forecasted customer needs. The 2006 Resource Plans conclude that the availability of up to a 1.5 Bcf LNG peak shaving facility located on TGVI s transmission system offers a cost effective option for meeting the future requirements of both utilities over the 25 year planning period examined in the Resource Plans. The LNG Storage Facility will primarily be used to provide both utilities a peaking gas storage resource to include in their gas portfolio mix. By locating the facility on Vancouver Island, it also provides TGVI with additional system capacity to serve customers during cold weather events and allows TGVI to avoid the construction of new compressor stations and looping to meet future customer peak day growth. The facility will also reduce TGVI s future transport demands on TGI s Coastal Transmission System ( CTS ) during peaking periods which in turn also allows TGI to defer future expansions. An on-system resource will allow the utilities to reduce their dependence on contracted storage services at facilities located in Washington and/or Oregon states and also provide additional reliability and security of supply benefits. This Section expands on the assessment provided in the 2006 Resource Plans supporting the development of an on-island LNG Storage Facility. The gas portfolio, system capacity and other on-system benefits are examined in separate sections as follows: Gas Supply Portfolio Assessment: Section 7.1 assesses the value of access to the LNG storage resource as an alternative to TGI s and TGVI s other gas portfolio resource options to meeting peaking gas supply requirements; Resource Portfolio Development: Section 7.2 examines the expansion requirements of the TGVI and TGI transmission systems to meet future growth that can be avoided or deferred if the LNG Storage Facility moves forward; and Other On-System Benefits: Section 7.3 provides an assessment of additional benefits provided through greater operational flexibility and enhanced reliability and security of supply obtained by having access to an LNG storage facility on Vancouver Island. Page 59

66 Mt. Hayes LNG Storage Facility An overall evaluation that considers the gas portfolio, system capacity and other on-system benefits is provided in Section 8. This evaluation continues to support the conclusions reached in the Resource Plans that the availability of the LNG Storage Facility on Vancouver Island is the preferred option to meet TGVI s and TGI s long-term requirements for storage resources and system capacity and provides many other benefits Gas Supply Portfolio Assessment Introduction The 2006 Resource Plans for TGI and TGVI reviewed long-term resource adequacy and identified preferred supply strategy to meet projected demand. Section 5 of the Resource Plans provide an overview of gas supply portfolio planning including an assessment of regional market conditions and incremental resource options to arrive at the following conclusions: Shorter duration resources such as market area storage provide a cost effective solution which best aligns TGI and TGVI supply portfolios with projected demand; In that assessment, market area storage refers to downstream stream storage resources, primarily Jackson Prairie ( JP ) Storage and Mist Storage. Value of incremental peaking resources at Huntingdon/Sumas market at minimum will be the expected cost of that market area storage plus redelivery transport; Growing uncertainty in availability and cost of incremental market area storage and associated redelivery transport in the Pacific Northwest introduces long-term supply risk to TGI and TGVI gas supply portfolios; and An on-system LNG storage resource can provide long-term supply security and cost certainty relating to incremental storage requirements and mitigate risk of expiring contracts. This Section examines the gas supply portfolio benefits provided by the availability of the proposed LNG Storage Facility at Mt Hayes. It begins with a review of gas supply portfolio findings identified in the 2006 Resource Plans including updated market evaluation for a peaking resource. The second part assesses storage requirements for purposes of quantifying the value of an on-system LNG storage resource to TGI and TGVI gas supply portfolios. Page 60

67 Mt. Hayes LNG Storage Facility Summary of Resource Plan - Gas Supply Portfolio Planning Findings Section 5 of the TGVI and TGI 2006 Resource Plans identified that existing resources in the TGVI and TGI gas supply portfolios are insufficient to meet projected demand and concluded shorter duration resources would be most effective to meet the majority of incremental requirements. In addition to this resource inadequacy, the assessment recognized an inherent supply and cost risk associated with expiry of existing contracts with third party market area storage providers. The influence of regional issues on long-term portfolio planning and availability of resource options were also discussed in the Resource Plans. Key challenges relating to procurement of long-term supply included expected growth and changing nature of regional demand combined with a lack of reserve capacity in current natural gas infrastructure in the Pacific Northwest and longer lead times for large infrastructure projects. These regional drivers are supported by findings in the 2006 Northwest Gas Outlook Update that identifies a currently constrained pipeline and storage capacity during extreme peak demand conditions and the need for incremental infrastructure to maintain long-term resource adequacy in the region. A copy of the final report is provided in Appendix E of this Application. The Resource Plans identified potential incremental resource options to include Westcoast T- South transport and downstream market area storage (JP or Mist) with associated firm transportation service on Northwest Pipeline ( NWP ). An economic assessment of the future cost of these alternatives was used to derive the value of an incremental peaking resource at Huntingdon/Sumas; a price floor set by market area storage plus redelivery transport and a price ceiling set to Westcoast T-South transport. The main objective of this assessment was to emphasize that while expected costs of existing regional resources provide a mechanism to estimate the current value of incremental resources, uncertainty in availability of preferred incremental resource options will be the primary driver of supply and price risk in the gas supply portfolio. Page 61

68 Mt. Hayes LNG Storage Facility Combined TGI and TGVI Portfolio Evaluation Currently, two separate legal entities exist to serve the TGI and TGVI natural gas customers. As a result, independent gas supply portfolios and contracts are maintained for TGI and TGVI, but management of planning and operations is conducted on a combined basis. Accordingly, assessment of storage requirements provided in this Section is based on the combined requirements of the TGI and TGVI portfolios. The evaluation of the combined gas supply impact has been made to simplify analysis and recognize portfolio synergies with respect to similar planning and procurement criteria, resource requirements, and potential for increased efficiency in resource utilization. TGI and TGVI are examining the potential for amalgamation of the two legal entities, which structure would also result in one gas supply portfolio to serve the combined service areas. However, examination of the merits of having an on-system LNG storage resource available is not dependant on whether or not an amalgamation proceeds at any time in the future New Resource Alternatives Gas Supply Portfolio Portfolio Efficiency via Resource Diversity Characteristics and costs, specific to a resource, determine the economic and operational fit in the gas supply portfolio. TGI and TGVI recognize the value of a supply portfolio characterized by resource diversity. Diversity in supply facilitates operational flexibility, more efficient use of resources, and minimizes potential for stranded cost. As such, the choice in incremental resource is based on a combination of relative cost of market alternatives and its impact on cost, operation, and risk of the total supply portfolio. Figure 7-1 illustrates the role of resource diversity in meeting the cost effective criteria. The chart highlights that the seasonal nature of demand and increased variability of winter peaking load relative to summer demand is best met with a high deliverability shorter duration resource. It identifies that current portfolio composition includes minimal access to on-system storage resources. The baseload component shows effectiveness of pipeline assets to meet constant demand; however, when pipeline is used to meet weather sensitive loads it has a higher potential for under utilization when compared to shorter duration resources Page 62

69 Mt. Hayes LNG Storage Facility Figure /2007 Normal and Design Load vs. Supply TGI & TGVI Economic Assessment of Market Alternatives The 2006 Resource Plans for both TGI and TGVI (Appendix G Market Area Storage Analysis ) provides a high-level economic assessment of the cost of an incremental peaking resource at the Huntingdon/Sumas market. The analysis is based on comparative cost of using Westcoast T-South transport or JP storage with associated NWP redelivery transport to structure a peaking resource equivalent to a 10-day LNG service. The market alternative of upstream storage with associated Westcoast T-North and T-South transport offers an effective seasonal resource but is the highest cost solution to meet peaking requirements and therefore was excluded in this evaluation. The following discussion on analytical assumptions and findings relate to an updated economic analysis of market alternatives based on the assessment provided in Appendix G of the Resource Plan. Updated schedules can be found in Appendix E of this Application. The calculations assume incremental availability of Westcoast T-South capacity at a firm transportation toll of C$0.39/Mcf escalating annually at 1.62%; this escalation is based on assessing WEI Cost of Service excluding deferral accounts and variable costs from 2005 to Other cost variables include a premium associated with winter daily commodity purchases at Station 2 and fuel requirements. The potential for T-South toll mitigation via offsystem sales is accounted by assuming a maximum of 33% (or equivalent of 100% toll recovery Page 63

70 Mt. Hayes LNG Storage Facility for 120 days) of annual fixed costs can be recovered. This assumption is consistent with historical value of T-South reflected in winter and annual average Sumas Station 2 commodity price differential of C$0.21/GJ (or 100% toll recovery for 104 days) and C$0.12/GJ (or 34% toll recovery per annum) respectively. The minimum expected cost of market area storage is based on cost of service rates associated with the JP storage expansion capacity offered in the 2006 NWP JP Storage Open Season plus firm redelivery transport on NWP. These assumptions equate to a storage reservation cost of US$3.10/Dth (or of capacity for a service that would be equivalent to the proposed 10-day LNG service). This cost is determined from the expansion rates filed by NWP to FERC on July 13, 2006 [reference to Docket No. CP06-416] and the detail calculations are shown in Appendix E. The annual cost of firm redelivery transport on NWP is based on current offerings to TGI based on 151-day winter service at the full firm transport tariff. On an annual basis, this equates to approximately 40% (i.e. 151 divided by 365) of the NWP TF-1 rate which is estimated to be US$0.39/Dth. Variable cost components include storage injection fuel and fuel requirements for transport on NWP. The use of underground storage such as JP storage to structure a 10-day LNG service requires an increased capacity allowance to account for differences in withdrawal characteristics. The daily withdrawal rate of an LNG resource is constant whereas withdrawal rate of underground storage is subject to decline as total storage inventory reduces. To account for this decline in daily withdrawal rate a 15-day storage capacity at JP storage is used to evaluate the cost of a 10-day LNG equivalent service. Implicit in this analysis is the unrestricted access to incremental resources. However, as discussed in the 2006 Resource Plans and summarized in Section of this Application, regional competition for peaking supply and minimal availability of NWP redelivery transport create uncertainty in the ability to procure long-term downstream storage contracts to meet incremental needs. In recognition of this uncertainty in resource availability scenarios of NWP redelivery transport costs at 40% TF-1 and 50% TF-1 have been calculated to capture current market offerings and the rate at which T-South transport with mitigation becomes cost competitive. Page 64

71 Mt. Hayes LNG Storage Facility Figure 7-2 provides an updated cost comparison of resource alternatives used to structure a 10- day LNG equivalent service. The chart indicates market value of an incremental peaking resource will, at minimum, be equivalent to the cost of market area storage plus associated firm redelivery transport. The maximum value will be capped at the expected cost of Westcoast T- South transport plus a premium associated with winter daily commodity purchases and zero toll mitigation revenue. Based on the stated cost assumptions, unrestricted availability to incremental resource options, and accounting for T-South mitigation revenue potential, it is expected the value to TGI and TGVI of an incremental peaking resource at Huntingdon/Sumas will be within a floor price of C$115/GJ and a ceiling price of C$137/GJ. Figure 7-2 ($Cdn/GJ) $200 Cost Comparison of Alternatives for a 10-day LNG Equivalent Service at Huntingdon/Sumas. ANNUAL GAS STORAGE & DELIVERY COST $183 $150 $100 $115 $131 $137 $50 $- JP + TF-1@40% JP + TF-1@50% 1 T-South (mitigated) T-South (no mitigation) Impact of Storage Availability on Gas Supply Portfolio Analytical Approach SENDOUT Model For portfolio analysis and development of a preferred resource mix TGI and TGVI are assisted with the use of New Energy Associates SENDOUT gas supply planning model. SENDOUT uses linear programming principles to simulate gas networks, a portfolio of supply, storage, and transportation options to determine optimal resource dispatch and portfolio composition by considering economic parameters and operational constraints. Page 65

72 Mt. Hayes LNG Storage Facility The model is consistent with TGI s and TGVI s planning standard as optimized resource selection and utilization is based on finding the least cost supply portfolio over a defined time period which can meet daily demand under design year weather conditions. TGI and TGVI use SENDOUT to analyze supply requirements, resource alternatives, and portfolio behaviour to different marketing conditions. Planning scenarios are created to model specific decision context followed by sensitivity analysis to identify key decision drivers and test resiliency of the optimized resource portfolio. For this Application SENDOUT has been used to assess incremental market area storage requirement across the range of costs discussed in the previous Section and summarized in Figure Key Modelling Assumptions Primary input assumptions relate to demand, commodity prices, economic and operational characteristics of supply, storage, and transportation resources, and mitigation revenue opportunities. Models of TGI and TGVI gas supply portfolios were created to represent existing and incremental resource options under a design year demand. The portfolios assumed the majority of existing storage and transportation contracts will be retained during the full study period. Currently contracted capacity at Aitken Creek and Mist storage were assumed to be fully renewed. The level of contracted JP storage was based on renewal of existing contracts that have not been recalled and includes capacity awarded to TGI as part of the 2006 NWP JP storage Open Season. All current transportation contracts were assumed to be renewed with the exception of T-South transport where de-contracting up to a maximum of 20% of existing contracted capacity was allowed. Incremental resource alternatives included T-South transport, upstream storage and associated T-North pipe, and market area storage of 15 and 26 day duration with associated NWP redelivery capacity. The decline in storage deliverability was modelled. Mitigation revenue opportunities via off-system commodity resales were included at each market hub. Page 66

73 Mt. Hayes LNG Storage Facility SENDOUT allows detailed modelling of economic parameters to enhance portfolio analysis. The fixed costs of incremental resources were those identified in Section The variable costs, commodity requirements, and mitigation revenue are derived from an optimized daily dispatch of resources Gas Portfolio Base Case Results The gas portfolio base case scenario models the expected resource cost and commodity prices under design year demand conditions. Results of this scenario aim to identify directional movements in portfolio composition and resource preferences primarily driven by projected demand. SENDOUT provides a theoretical optimum solution of the preferred resource mix under the assumptions of perfect foresight of cost, demand, and resource availability; infinite decision flexibility in resource additions or reductions; and is specific to a set of input assumptions. As such, these results demonstrate economic preference for specific resource characteristics to provide a guideline in resource requirements and portfolio composition Optimal Resource Mix and Preferred Resource Characteristic Figure 7-3 and Figure 7-4 represent an optimized mix of resources required to meet projected design year demand. The first chart indicates the composition of resources utilized to meet peak day demand while the second shows incremental storage requirements. An inadequacy in the existing supply portfolio to meet long-term demand is confirmed by the selection of incremental resources. Figure 7-3 shows long-term incremental requirements is best served by a combination of market area storage and pipe where the optimal portfolio composition includes market area storage equivalent to approximately 35 to 40% of TGI and TGVI peak day demand. Page 67

74 Mt. Hayes LNG Storage Facility Figure 7-3 Peak Day Resource Use as % of Peak Day TGI & TGVI Gas Portfolio Base Case 45% 40% 35% 30% 25% 20% 15% 10% 5% 0% % of Peak Day (Fuel Inclusive) preferred portfolio includes 37% market area storage to meet TGI and TGVI peak day demand Alberta Upstream Storage US Supply & Curtailment Station 2 Market Area Storage Figure 7-4 identifies preferred resource characteristics to meet incremental storage requirements assuming that there are no future constraints on the availability of resources. The chart shows zero pick up of Mist and an annual increase in JP storage. These resource choices indicate that under the base cost assumptions, high deliverability shorter duration market area storage is a better economic fit in the existing gas supply portfolio to meet TGI and TGVI projected demand. If competitively priced, the storage resource provided by the proposed LNG Storage Facility offers an alternative to meet the preference for shorter duration storage resources and would replace the incremental component of JP storage shown in the Figure. Page 68

75 Mt. Hayes LNG Storage Facility Figure 7-4 Optimized Storage Peak Day Use TGI & TGVI Gas Portfolio Base Case Optimised Peak Day Deliverability TJ/D Shorter duration market area storage preferred over upstream and longer duration market area storage Tilbury LNG Mist Storage Jackson Prairie Storage Market Area Storage At Risk The above incremental storage requirements are conditional on guaranteed renewal rights of existing contracted capacity with third party storage providers that have not provided termination notice. Figure 7-5 compares optimized market area storage requirements to the current capacity contracted or owned by TGVI and TGI. The Figure highlights the supply risk associated with potential recall of existing contracted capacity at expiry. The gap between the optimal requirement and firm contracts also represents the market area storage requirement exposed to uncertainty in availability and cost. The chart includes optimal market area storage requirements at a NWP redelivery transport rate of 40% and 50% TF-1 to recognize how the optimal allocation between resources can vary under different cost assumptions. For example, the reduced storage requirement when redelivery is priced at 50% TF-1 reflects increasing competitiveness of T-South transport as total cost of market area storage rises. However the continued inclusion of market area storage at a higher redelivery cost demonstrates a long-term preference for shorter duration resources. Also highlighted in the chart is a level of existing contracted and company owned market area storage that is below optimal requirements. This shortfall is a reflection of prevailing market conditions regarding lack in availability of incremental market area storage and associated Page 69

76 Mt. Hayes LNG Storage Facility redelivery transport and represents the potential for long-term decline in the portfolio s economic efficiency. The availability of an on-system LNG storage resource offers an opportunity to reduce the identified resource gap and introduce cost certainty to a portion of market area storage requirements. Figure 7-5 demonstrates that a 1.5 Bcf 150 MMcfd (162,000 GJ/d) peaking resource can be fully utilized to meet storage requirements of TGI and TGVI and indicates the availability of the proposed Mt. Hayes LNG storage does not eliminate future requirement for incremental resources to meet projected demand. Figure 7-5 Market Area Storage Contracts & Future Requirements - TGI & TGVI MARKET AREA STORAGE PROFILE TJ/d TJ/d TF-1@40% TJ/d TF-1@50% Mist Contract JPS Contract Tilbury LNG Requirement (TF-1@40%) Requirement (TF-1@50%) Early Expiration Drivers of Resource Selection Sensitivity of Market Area Storage Requirement The gas portfolio base case scenario results represent an optimal solution that is specific to the input assumptions on demand, resource availability and cost, commodity prices, and mitigation revenue opportunities. To identify key decision drivers in resource selection, sensitivity analysis is performed to test resiliency of the optimal portfolio. The following discussion identifies significant factors, other than the cost of resources, that can change the choice between the use of transport and storage resources. Page 70

77 Mt. Hayes LNG Storage Facility Results of sensitivity analysis on commodity prices indicate resource selection is insensitive to absolute changes in prices. Figure 7-6 provides a comparison of market area storage requirement based on GLJ Petroleum Consultants Ltd. ( GLJ ) April and GLJ January commodity price forecasts. The January 2007 update shows a 17% increase in the longterm gas price forecast, adjusted for foreign exchange rate, relative to the April 2006 edition. The analysis shows absolute changes in commodity prices primarily impact a portfolio s variable cost related to supply purchases while the decision to select transport or storage is largely driven by fixed demand charges, and therefore changes in commodity prices have nominal impact the market area storage requirements. Figure 7-6 Market Area Storage Requirement Sensitivity to Commodity Price Forecast Storage Optimal Peak Day Use TJ/D Apr 2006 GLJ Forecast - Current Base Jan 2007 GLJ Forecast Other cost drivers of resource selection are the relative differences between commodity prices. These differences primarily relate to seasonal (summer winter) and location (variation between purchase points). Previous analysis indicates higher summer-winter commodity price differentials increase the preference for storage. On the other hand, elevated locational differentials raises the value of transport connecting the two price points and could reduce the preference for shorter duration market area storage. In either case it is the mitigation revenue potential for either resource that increases the preference for that resource rather than the need to meet portfolio demand. As summer-winter and locational differentials narrow, portfolio composition is determined by the relative fixed cost of resource options. Page 71

78 Mt. Hayes LNG Storage Facility TGI and TGVI adopt a planning criterion that bases resource decisions on the obligation to provide safe, reliable, and cost effective natural gas supply to meet the needs of customers. Revenue from mitigation activity has a higher degree of uncertainty than the demand charges associated with a resource. As such, long-term decisions are made in the context of estimates of summer-winter and locational price differentials which recognize the potential for mitigation revenue while at the same time attempting to not unduly bias the portfolio toward specific resources based on that potential Value of LNG Storage Service The development of the LNG Storage Facility on TGVI s system will provide both utilities with a new peaking resource alternative that can help meet future requirements for shorter duration resources and reduce the requirement for acquiring additional off-system market area storage or transport resources. The value of the LNG Storage Facility as a peaking resource in the gas portfolio can therefore be measured by the expected cost of the alternative resource options; in this case JP storage with associated redelivery and WEI transport. An assessment of LNG storage value based on these resource alternatives is detailed in schedules provided in Appendix E of this Application. Table 7-1 summarizes the gas supply benefit for 15 year and 25 year evaluation periods commencing 2007 which is consistent with planning periods used in the 2006 Resource Plans. The expected in-service date of the LNG Storage Facility is 2011; therefore these values are equivalent to the avoided costs of alternate resource options associated with over the first 11 year and 21 years of operation of the LNG Storage Facility. The results show that the present value of the LNG storage service to the TGI and TGVI gas supply portfolios over the 25 year evaluation period is between $203 million and $241 million with a corresponding levelized annual value between $19 million and $22.1 million. Page 72

79 Mt. Hayes LNG Storage Facility Table 7-1 Present Value of Resource Alternatives Supply Alternative $Millions 15 Year Evaluation Period 25 Year Evaluation Period 6.2% Discount Rate PV Annual Annual PV Levelized Levelized JP Storage with NWP transport WEI transport with mitigation Discount Rate JP Storage with NWP WEI transport with mitigation Gas Supply Portfolio Summary The 2006 Resource Plans for TGI and TGVI identified a long-term deficiency in supply-demand balance and concluded shorter duration market area storage is the cost effective incremental resource to meet projected demand. An assessment of expected future cost of incremental Westcoast T-South transport and JP storage with associated redelivery on NWP indicates that the market value of an incremental peaking resource at Huntingdon/Sumas will at minimum be equivalent to cost of market area storage plus associated firm redelivery transport and up to a maximum set by expected cost of Westcoast T-South transport. The impact of a peaking resource on TGI and TGVI gas supply portfolios was evaluated using SENDOUT ; an optimization model based on least cost principles. The analysis quantified incremental resource requirements to identify an optimum portfolio composition includes market area storage equivalent to 35 to 40% of TGI and TGVI peak day requirements. The modelling also demonstrated cost effectiveness of a peaking resource at a cost equivalent to 2006 NWP Jackson Prairie Open Season and 40% TF-1 NWP redelivery transport. Implementation of a procurement strategy to achieve this preferred portfolio composition is challenged by prevailing uncertainty in availability of incremental shorter duration resource and associated redelivery in the Pacific Northwest. Supply and cost risk in long-term gas portfolio Page 73

80 Mt. Hayes LNG Storage Facility planning is further magnified when the potential for recall of currently contracted market area storage at expiry is considered. Availability of the proposed Mt. Hayes LNG storage offers a supply solution that facilitates alignment of TGI and TGVI supply portfolios to projected demand and helps to alleviate the resource gap illustrated in Figure 7-5. This Figure demonstrates a 1.5 Bcf with 150 MMcfd or 163 TJ/d deliverability) peaking resource can be fully utilized to meet market area storage requirements of both utilities and indicates that the availability of this new LNG storage capacity does not eliminate future requirement for incremental resources. As an on-system LNG storage resource, access to the Mt. Hayes LNG Storage Facility allows TGVI and TGI an opportunity to mitigate long-term cost and supply uncertainty associated with incremental market area storage and redelivery transport. Page 74

81 Mt. Hayes LNG Storage Facility 7.2. Resource Portfolio Development A primary objective of TGVI and TGI resource planning is to provide a review of the capacity and expansion alternatives for the major transmission systems such that the utilities can continue to meet expected customer demand over the long term. Section 6 in each of the TGVI and TGI 2006 Resource Plans provides an assessment of the requirements on the TGVI System and the CTS and concludes that an on-island LNG storage facility would allow both utilities to avoid or significantly defer transmission expansion facilities such as pipeline looping or compression additions. This section expands and updates the resource requirement assessment provided in the 2006 Resource Plans System Description of CTS and TGVI System The CTS provides transportation from the Huntingdon trading point to various metering and regulating stations in the Fraser Valley and Metro-Vancouver area. As shown in Figure 7-7, the CTS consists of a 265 km network of pipelines and includes the Langley compressor station which is used to maintain transmission pressures during periods of high demand, and the existing Tilbury LNG storage facility. The Tilbury Facility is used to meet peaking gas supply requirement as well as increasing system deliverability to the CTS during high demand periods. The CTS serves as the backbone for distribution systems serving the core market demands in the Lower Mainland, as well as BC Hydro at Burrard Thermal and TGVI at Eagle Mountain in Coquitlam. As described in the TGI 2006 Resource Plan, future expansions on the CTS will largely be driven by the future requirements to service Burrard Thermal and the TGVI System. The TGVI System commences at the interconnection with the CTS in Coquitlam. Through a 615 km transmission pipeline, in combination of three dual marine crossings, and several small size laterals, and compressor stations in Coquitlam (V1), Port Mellon (V3), and on Texada Island (V4), the system delivers natural gas to various metering and pressure regulating stations located at customer sites and communities on Sunshine Coast and on Vancouver Island. Figure 7-8 illustrates the route and basic components of the existing TGVI System, and locations of the major industrial customers and distribution networks. Page 75

82 Mt. Hayes LNG Storage Facility Figure 7-7 Coastal Transmission System Figure 7-8 TGVI Transmission System Page 76

83 Mt. Hayes LNG Storage Facility TGVI System Capacity Requirements The TGVI System is used to serve the gas requirements for core market customers on Vancouver Island, the Sunshine Coast and Squamish and for large industrial customers the six pulp and paper mills currently represented by the VIGJV and BC Hydro for the ICP generating facility at Campbell River. Following completion of a pipeline lateral from Squamish in 2008, the TGVI System will also serve the community of Whistler. As described in Section 6.3 of the TGVI 2006 Resource Plan, the TGVI System capacity is currently constrained during peaking periods and TGVI relies on a right to call back firm transportation capacity from BC Hydro during design weather events in order to serve its core market peak heating load requirements. This right to call back capacity is limited by ICP s ability to fuel switch and the amount of distillate storage at the ICP facility site. Figure 7-9 TGVI Design Day Forecast 250 TGVI Design Day Forecast Terajoules per Day TGVI Core Whistler BC Hydro Squamish VIGJV 2006 Capacity Year beginning November Figure 7-9 compares the current TGVI System deliverability of approximately TJ/d to the core market and transport demand forecast. As discussed in Section 3 of its 2006 Resource Plan, TGVI continues to see strong core demand growth on its system and also expects to continue serving the six mills currently represented by the VIGJV over the planning period. In addition, BC Hydro has identified in its 2006 IEP that the ICP is required as a long-term firm Page 77

84 Mt. Hayes LNG Storage Facility capacity and energy resource, and therefore TGVI also expects that BC Hydro will continue to require transportation service beyond the expiry of its existing agreement in Nevertheless, given the significant size of the ICP demand (45 TJ/d) relative to the overall demand on the TGVI system and in the absence of a long-term transportation commitment from BC Hydro, for resource planning purposes the TGVI baseline demand scenario assumes the ICP is not a firm customer. However, a demand scenario to serve the firm requirements for the ICP is also assessed. In this case, it is also assumed that TGVI retains the capacity right to curtain the ICP up to the limit of the ICP current distillate fuel storage capacity of 100 TJ, equivalent to 53 hours of the ICP operation at full load. For the purposes of this Application therefore, two demand scenarios are examined when assessing future TGVI resource requirements: Baseline Demand Scenario Base core market forecast for TGVI, TGW and TGI s Squamish service; and Industrial demand of 9.1 TJ/d associated with the long-term demand of the six mills currently represented by the VIGJV. Base plus ICP Demand Scenario Baseline Demand Scenario plus ICP firm Contract Demand of 45 TJ/d; and ICP Capacity Curtailment right of up to 45 TJ/d but a maximum of 100 TJ in any one winter TGVI Portfolio Development Section 6.5 of TGVI s 2006 Resource Plan identifies the two separate resource portfolio strategies used to identify future compression and looping requirements on the TGVI System to meet expected customer demand. In the LNG Storage Portfolio, it is assumed that an LNG storage facility is put in-service at Mt Hayes that provides TGVI both capacity and peaking gas supplies during the core market winter peaking periods and therefore allows the deferral of transmission capacity expansion facilities. In the P&C portfolio, an on-system storage resource is not available, and TGVI must expand its transmission system capacity to meet its peaking requirements. Page 78

85 Mt. Hayes LNG Storage Facility Hydraulic simulation modelling of the TGVI System was used to identify the timing and requirement for compression and looping additions under these two separate portfolio approaches 1. The results of the hydraulic modelling are summarized in Table 7-2 identifying the resource and required timing of each addition. In the LNG Storage Portfolio, it is assumed that the LNG Storage Facility is in service in 2011, and therefore Table 7-2 shows the costs of the System Facilities in In the P&C portfolio, the results for the Baseline Demand Scenario show that the first capacity expansion is required in 2013 when new compressor stations at Squamish (V2) and Dunsmuir (V5) would be necessary to meet the expected capacity requirement for the winter of 2013/14. In the Base plus ICP Demand Scenario, the requirement for Squamish Compressor is advanced to 2010 followed by additional facilities in 2012 and In the LNG Storage Portfolio, the modelling shows that in the Baseline Demand Scenario, the on-system storage services from the LNG storage facility allows TGVI to defer any transmission system addition beyond the end of the planning period to Similarly, in the Base plus ICP Demand Scenario, having on-system storage services available allows significant deferral of compression and pipeline facility additions, with only the potential for the Squamish Compressor (V2) addition in As is discussed more fully in Section below, these results also indicate that the LNG Storage Portfolio would put TGVI in a position to provide BC Hydro firm transportation service for the ICP (assuming the availability of 53 hours of curtailment) at least until 2019 without having to make any compression or pipeline looping investments. In the P&C portfolio, the schedule of resource additions matches that shown in Table 6-1 of TGVI s 2006 Resource Plan (page 98). In the LNG Storage Portfolio, however, the results are more favourable than that shown in the 2006 Resource Plan. The main difference is that in the Resource Plan, the hydraulic modelling assumed that only 0.5 Bcf LNG storage with 50 MMcfd of vaporization capacity would be available to be utilized for TGVI s purposes, while as explained in Section 7.2.4, the results in Table 7-2 take into consideration that the proposed LNG Storage Facility consists of 1.5 Bcf storage capacity with 150 MMcfd of deliverability. 1 Detailed descriptions of the different resource options were provided in the Appendix H, I and J of the TGVI 2006 Resource Plan. Page 79

86 Mt Hayes LNG Storage Facility Table 7-2 TGVI System Expansion Facilities Pipe & Compression Portfolio Squamish V2 Dunsmuir V5 Coquitlam V1-U4 Sechelt V3b Crofton V6 Watershed 25.3 km Loop [P10 - millions 2007$ direct] $22.2 $22.0 $12.5 $22.0 $22.2 $29.7 [P50 - millions 2007$ direct] $24.2 $24.0 $13.6 $24.0 $24.0 $32.6 [P90 - millions 2007$ direct] $27.4 $27.3 $15.4 $27.3 $27.3 $35.9 Demand Scenarios Baseline Demand Base + ICP LNG Storage Portfolio System Facilities Squamish V2 Dunsmuir V5 Coquitlam V1-U4 [P10 - millions 2007$ direct] $10.4 $22.2 $22.0 $12.5 [P50 - millions 2007$ direct] $11.7 $24.2 $24.0 $13.6 [P90 - millions 2007$ direct] $13.1 $27.4 $27.3 $15.4 Demand Scenarios Baseline Demand 2011 Base + ICP Sechelt V3b Crofton V6 Watershed 25.3 km Loop Legend System Facilities Squamish V2 Dunsmuir V5 Coquitlam V1-U4 Sechelt V3b Crofton V6 Watershed 25.3 km Loop Note: System Facilities included inteconnections, measurement, and pipeline reversibility facilities associated with the LNG Storage Facility. Compressor Station Addition Compressor Station Addition 4th Unit Addition to Compressor Station V1 Compressor Station Addition Compressor Station Addition Pipeline Looping with NPS 12 to existing NPS 10 from downstream of Watershed. For LNG portfolio to meet core markets + JV, V5 is deferred beyond 2031 by utilizing up to 60 mmscfd of LNG deliverability on design peakday only without exceeding its 0.5 bcf LNG storage capacity limit. This is acceptable as TGI is expected to call on Mt Haynes LNG on design peakday as well. Page 80

87 Mt. Hayes LNG Storage Facility Comparison with 2006 Resource Plan Results TGVI s 2006 Resource Plan assessed the TGVI system expansion requirements in the LNG Storage Portfolio based on the availability of a 0.5 Bcf storage facility and 50 MMcfd of deliverability. In this Application, TGVI is proposing to build the LNG Storage Facility based on 1.5 Bcf of storage capacity and 150 MMcfd of vaporization capacity or deliverability. TGVI will initially reserve up to 0.5 Bcf and 50 MMcfd of deliverability for serving its own customers, will contract with TGI for the remaining capacity. Under the terms of the proposed storage and delivery services agreement between TGVI and TGI, TGI will contract for a minimum of 1.0 Bcf of storage capacity and 100 MMcfd of deliverability for the initial term of 20 years. After the initial term, TGVI can decrease the capacity available to TGI to the degree it requires that capacity to serve its own customers. Although TGVI is initially reserving up to 50 MMcfd of deliverability for its own use, the fact that the total vaporization capacity will be 150 MMcfd effectively provides TGVI with even greater deliverability to meet its system capacity requirements during peaking events. Since extreme cold weather events are caused by Arctic air mass coverage of the entire province of BC including Vancouver Island, the design day demand from Vancouver Island, Sunshine Coast and the Lower Mainland are generally expected to be coincidental (see Section 6.2.3). Therefore, it is reasonable to expect in the event of a design weather event the LNG Storage Facility would be delivering LNG simultaneously to meet both TGVI and TGI s requirements. Nevertheless, in the unlikely scenario where TGI is not experiencing an extreme cold weather event coincidentally with TGVI, and is not nominating peaking supplies from the LNG Storage Facility, TGVI would be able to use the unutilized vaporization capacity to meet its own requirements. The facility addition forecast for the LNG Storage Portfolio shown in 2006 TGVI Resource Plan (refer to Table 6-1, page 98) was based on the limitation of 50 MMcfd of vaporization capacity. Under this constraint, in the Baseline Demand Scenario, the Squamish compressor (V2) would be required in 2029 To defer the V2 compressor addition beyond the resource planning period ending in 2031, TGVI would require up to 60 MMcfd in LNG deliverability on the single design day in Years 2029 to This additional LNG deliverability would not result in exceeding the 0.5 Bcf LNG storage capacity that TGVI is reserving for its own use. As a result, the V2 Page 81

88 Mt. Hayes LNG Storage Facility compressor addition is removed from the TGVI LNG storage portfolio for the Baseline Demand Scenario. In the Base plus ICP Demand Scenario, the requirement for the V2 Compressor in 2019 is determined by LNG storage capacity rather a deliverability limitation. It therefore can only be deferred if TGVI has access to more than 0.5 Bcf LNG storage capacity over the winter period. At that time, it could potentially be more cost effective for TGVI to arrange for use of some of TGI s storage capacity than to build the V2 Compressor; in particular if BC Hydro does not intend to renew its ICP Electricity Purchase Agreement when it expires in April However, this would change the value of the storage capacity to TGI and therefore for the purposes of this Application it is assumed that the V2 Compressor will be required in 2019 for the Base plus ICP Demand Scenario. Table 7-3 compares the present value of cost of service associated with the incremental TGVI system facilities for the 15 and 25 year planning periods beginning in In the LNG Storage Portfolio, the costs include the System Facilities associated with the LNG Storage Facility, however the cost of the storage Project itself is not included. The difference between the two portfolios represents the value of the capacity benefit the LNG Storage Facility will provide to TGVI before taking into account the gas portfolio benefits discussed in Section 7.1. Section 8 provides an overall assessment of the LNG Storage Facility taking into account the costs of the facility relative to gas portfolio and capacity benefits. Note that this comparison is based on the P50 capital cost estimates in both portfolios. Table 7-3 TGVI Capacity Benefits 6.2% Discount Rate P&C Portfolio 25 Year Evaluation Period LNG Storage Portfolio TGVI Capacity Benefits Baseline Demand Scenario (115) (21) 94 Base plus ICP Demand Scenario (148) (51) 97 10% Discount Rate Baseline Demand Scenario (72) (15) 57 Base plus ICP Demand Scenario (99) (32) 67 Page 82

89 Mt. Hayes LNG Storage Facility 6.2% Discount Rate P&C Portfolio 15 Year Evaluation Period LNG Storage Portfolio TGVI Capacity Benefits Baseline Demand Scenario (48) (14) 34 Base plus ICP Demand Scenario (83) (20) 64 10% Discount Rate Baseline Demand Scenario (36) (11) 24 Base plus ICP Demand Scenario (64) (15) TGI CTS Portfolio Development Section of the TGI 2006 Resource Plan discusses the capability of the CTS to meet forecast demand and concludes that the Coquitlam segment in the Lower Mainland could have a significant constraint in the near to medium term. The requirement for CTS capacity expansion is driven by the CTS core market demand growth, firm transportation service to Burrard Thermal and TGVI takeaway capacity at Eagle Mountain. The assessment of the CTS capacity requirement to support these loads takes into account a number of factors: TGI s contractual requirements under the TGVI Wheeling Agreement and the BC Hydro Bypass Transportation Agreement; TGVI s take-away capacity at Eagle Mountain under different scenarios (i.e. P&C portfolio versus LNG Storage Portfolio); Burrard Thermal s gas consumption rate under full load; and BC Hydro s forecast of the requirement for Burrard Thermal as a firm capacity resource as provided in the 2006 IEP. The assessment provided in the TGI 2006 Resource Plan concluded that the CTS capacity expansion could be required as early as 2011 if the proposed Mt. Hayes facility did not proceed and TGVI subsequently expanded its transmission system capacity through compression additions, and therefore increasing its transportation requirement through the CTS to Eagle Mountain. This expansion requirement also assumes the TGVI Base plus ICP demand scenario, the CTS high core market demand, and all six units are required at Burrard Thermal for which BC Hydro holds capacity under the Bypass Transportation Agreement. It was also identified in the Resource Plan that if Burrard Thermal is retired, the current CTS capacity would Page 83

90 Mt. Hayes LNG Storage Facility be sufficient to serve the remaining loads over the planning period. Figure 7-10 below illustrates the capacity of the CTS to serve the expected demands in the Coquitlam area under this scenario. Figure 7-10 TGI CTS Capacity to Serve Coquitlam Area BC Hydro Bypass Transportation Agreement BC Hydro, under the Bypass Transportation Agreement, holds 275 TJ/d firm capacity on the CTS for Burrard Thermal and currently assigns some of its capacity to TGVI to support firm transportation service to ICP on Vancouver Island. That bypass agreement expires in 2030; however BC Hydro has the right to terminate the agreement as early as 2009 upon payment of a termination fee based on the book value of the facilities that were constructed to provide service under the agreement. As discussed in Section 6.2.2, there are currently four operational units at Burrard Thermal and the remaining two units are expected to be re-commissioned and operational to meet firm system capacity requirements by winter 2008/09. In its 2006 IEP, BC Hydro has also indicated that it is considering alternatives to allow the retirement of Burrard Thermal. This would first require the construction of the proposed ILM transmission project. BC Hydro has indicated the Page 84

91 Mt. Hayes LNG Storage Facility ILM transmission project could be completed in 2014 at the earliest; however, BC Hydro has also indicated that if Burrard Thermal is not retired or is re-powered the requirement for the completion of the ILM transmission project could be deferred for up to seven years Transportation Service for TGVI TGVI, through its wheeling agreement with TGI, holds transportation capacity on the CTS to move gas from Huntingdon to the beginning of the TGVI System at Coquitlam. Under the terms of the agreement, the annual demand charges are based on the estimated cost and capacity of a bypass pipeline to meet the contract demand. The maximum contract demand, based on volume, is equivalent to 140 TJ/d at a minimum hourly delivery of 260 psig. For long-term planning purposes, however, TGI has assumed a minimum delivery pressure of 300 psig, and TGVI deliveries based on the forecasted requirements under the different demand scenarios and considering both the P&C and LNG Storage Portfolios approaches. The initial 20 year term of the Wheeling Agreement expires in July 2011 with TGVI having the right to extend one 20 year term thereafter. TGVI also holds the right to increase its contract demand to double the current maximum value upon timely notice to TGI. The incremental demand rate increase would be based on the estimated cost of any incremental facility addition to the bypass pipeline to meet the new capacity requirement. Under all scenarios, TGVI is expected to require additional wheeling capacity to meet its requirements over the long term; however this capacity requirement is much lower in the LNG Storage Portfolio where core market peaking demand is met with supply from the LNG Storage Facility. In addition, under the proposed arrangements, TGI will also have access to its own peaking supply from the LNG Storage Facility. Redeliveries from the on-island storage facility to the Lower Mainland is done through displacement which has the effect of further reducing the TGVI s wheeling capacity requirement through the CTS during peaking periods TGI System Future Expansion Requirements Section of the TGI 2006 Resource Plan identifies the principle alternatives in meeting the CTS capacity requirements. In this section, the potential for storage services associated with the LNG Storage Facility to defer the CTS expansion requirement through phased construction of the Nichol Coquitlam loop is assessed. Page 85

92 Mt. Hayes LNG Storage Facility The TGI 2006 Resource Plan shows that with TGI s base core market demand forecast and with Burrard Thermal removed from service by March 2014 as indicated in the BC Hydro 2006 IEP, the CTS would not require any capacity expansion. However, the Resource Plan also shows that if the TGI core market demand growth approaches the high demand forecast, the CTS capacity expansion could be required as early as As illustrated in Figure 7-10, if and when Burrard Thermal is retired, the CTS would have sufficient system capacity to satisfy the CTS core market demand and TGVI takeaway capacity at Eagle Mountain without any additional facility expansion for the duration of the study period ending in These results are based on TGI s base core market demand forecast provided in the 2006 Resource Plan. Table 7-4 summarizes the timing of CTS expansion requirements under the different TGVI scenarios assuming that BC Hydro continues to require firm transportation for Burrard Thermal for the planning period. In the TGVI P&C portfolio, the potential for continuing operations at Burrard Thermal beyond 2014 could trigger three phases of looping of the CTS through the planning period ending in At least two phases are triggered in the period to 2021, the period which the ILM transmission project can be deferred if Burrard Thermal continues to be in operation. In the TGVI Base + ICP Demand Scenario, Table 7-4 shows that the first phases could be required in 2013 and For both TGVI demand scenarios, the LNG Storage Portfolio results in less take away capacity from Eagle Mountain, and therefore reduces the requirement for CTS capacity over the P&C portfolio. In addition, as TGI is proposing to contract for deliverability and storage capacity from the LNG Storage Facility as part of TGI s gas supply portfolio, and the delivery of TGI s peaking supplies from the LNG Storage Facility is largely done through displacement 9, there would be further reduction in CTS capacity requirement to TGVI. As is shown in the table, the availability of the LNG Storage Facility will defer the need for any CTS facility additions until very late in the planning periods even if the retirement of Burrard Thermal is deferred. 9 TGI would take TGVI s gas at Huntingdon and TGVI would use TGI s gas from the LNG facility to serve Vancouver Island loads. Page 86

93 Mt. Hayes LNG Storage Facility Table 7-4 CTS Facility Expansion Requirements with Six operational units at Burrard Thermal Pipe & Compression Portfolio 4.89km x 30 loop Nichol - Port Mann 4.56km x 30 loop Cape Horn - Coquitlam 4.44km x 30 loop Coquitlam - Noon s Crk [P10 - millions 2007$ direct] $22.4 $20.9 $20.4 [P50 - millions 2007$ direct] $29.9 $27.8 $27.2 [P90 - millions 2007$ direct] $37.4 $34.8 $34.0 Demand Scenarios Baseline Demand Base + ICP LNG Storage Portfolio 4.89km x 30 loop Nichol - Port Mann 4.56km x 30 loop Cape Horn - Coquitlam 4.44km x 30 loop Coquitlam - Noon s Crk [P10 - millions 2007$ direct] $22.4 $20.9 $20.4 [P50 - millions 2007$ direct] $29.9 $27.8 $27.2 [P90 - millions 2007$ direct] $37.4 $34.8 $34.0 Demand Scenarios Baseline Demand 2031 Base + ICP 2028 Legend Nichol- Port Mann Loop Cape Horn-Coquitlam Loop Coquitlam-Noon's Creek Loop Pipeline Looping 4.89 km long with NPS 30 from Nichol Valve Station to Port Mann Valve Station Pipeline Looping 4.56 km long with NPS 30 from Cape Horn Valve Station to Coquitlam Regulator Station Pipeline Looping 4.44 km long with NPS 30 from Coquitlam Regulator Station to Noon's Creek Valve Station Given that BC Hydro is considering the retirement of Burrard Thermal as early as 2014, the economic benefit of being able to avoid CTS capacity additions has a wide range, however access to the LNG Storage Facility clearly provides TGI greater flexibility to manage the uncertainty related to the long-term operation of Burrard Thermal. Table 7-5 below summarizes the present value of the incremental cost of service associated with the expansion facilities shown in Table 7-4 based on continued operation of Burrard Thermal. The financial schedules supporting the cost of service are shown in Appendix F. The difference between the P&C Portfolio and the LNG Storage Portfolio represents the TGI Capacity Benefits that TGI would realize under this scenario if the LNG Storage Facility proceeds. Page 87

94 Mt. Hayes LNG Storage Facility Table 7-5 TGI Capacity Benefits (Assuming 6 Units at Burrard Thermal) 6.2% Discount Rate P&C Portfolio 25 Year Evaluation Period LNG Storage Portfolio TGI Capacity Benefits Baseline Demand Scenario $45 $1 $44 Base plus ICP Demand Scenario $52 $4 $48 10% Discount Rate Baseline Demand Scenario $28 $0 $28 Base plus ICP Demand Scenario $34 $2 $32 6.2% Discount Rate P&C Portfolio 15 Year Evaluation Period LNG Storage Portfolio TGI Capacity Benefits Baseline Demand Scenario $21 $0 $21 Base plus ICP Demand Scenario $28 $0 $28 10% Discount Rate Baseline Demand Scenario $15 $0 $15 Base plus ICP Demand Scenario $21 $0 $ Flexibility of LNG Portfolio TGVI is proposing to construct and put the LNG Storage Facility in service by April The facility will provide gas portfolio benefits to both utilities by providing access to on-system storage and peaking gas supplies to meet the winter 2011/12 requirements. As discussed in this Section 7.2, the LNG Storage Facility will also provide flexibility for the utilities to manage the uncertainty of generation demand associated with ICP and Burrard Thermal. As discussed in Section 7.2.2, the TGVI System is currently constrained and beyond 2010 cannot continue to meet all the firm loads it currently serves (including ICP) without establishing additional system capacity during peaking periods. Availability of the LNG Storage Facility will allow TGVI to meet demand requirements for the Baseline Demand Scenario without any additional pipe and compression facilities over the planning period to In addition, once Page 88

95 Mt. Hayes LNG Storage Facility the LNG Storage Facility is in service, TGVI could continue to provide firm capacity to ICP at least until 2019, assuming 53 hours of curtailment continues to be available, or meet additional firm capacity requirements associated with the VIGJV member mills. Figure 7-11 illustrates the peak day system capacity of the TGVI System for the LNG Storage Portfolio in the Baseline Demand scenario where no additional system facilities are constructed once the LNG Storage Facility is in place. The figure assumes that TGVI would reserve a maximum of one third of the storage and deliverability of the 1.5 Bcf facility in order to meet core market and firm transport demands on its own system. The Figure illustrates the additional peak day system capacity that could be offered on a shortterm basis to meet additional firm transportation demand under the LNG Storage Portfolio. Beginning in winter 2011/12, there is additional firm system capacity available above the demand from the core market and the six mills of the VIGJV. There would be adequate firm system capacity available to meet the ICP demand up to and including winter 2014 without the use of distillate fuel. Thereafter, to winter 2019, there would be firm capacity to ICP in combination with the use of its current 100 TJ of distillate fuel storage. For winter 2018 and 2019, the additional peak day capacity would not be constrained by TGVI s LNG deliverability limit of 50 MMcfd, but rather would be constrained by the TGVI s LNG storage limit of 0.5 Bcf required to meet the core market demand and firm transportation demand for the whole winter season. It is important to identify that the additional system capacity would not necessarily be available on an interruptible basis. For example if BC Hydro chooses not to continue holding firm transportation for the ICP, TGVI would optimize the amount of LNG storage capacity and deliverability it would reserve for itself based on its gas portfolio requirements from year to year. Once the heating season commences, TGVI would not elect to use its storage capacity and deliverability to provide interruptible service as this could gas portfolio at risk during peaking events and reduce the value of the storage resource. However to the degree that the amount of LNG service TGVI holds exceeds the minimum service it requires to meet its firm capacity requirements, incremental interruptible service may be available. If the LNG Storage Facility does not proceed and on-system storage services are not available, TGVI will expand with compression additions to meet demand growth as described for the Page 89

96 Mt. Hayes LNG Storage Facility Baseline Demand Scenario in the Section With no long-term firm commitment from BC Hydro, the compression additions would not be constructed to meet the ICP firm requirements and the firm capacity available from period to period would be limited as illustrated in Figure 7-12 below. In this scenario, BC Hydro will have to put in other facilities or arrangements to allow it to continue to consider the ICP as a firm electrical capacity resource Resource Portfolio Summary The assessment of capacity requirements and the resource portfolios of the TGVI System and the CTS concludes that the development of the LNG Storage Facility on Vancouver Island to provide an on-system storage resource offers the best opportunity for both utilities to avoid or defer future transmission system expansions in the form of pipeline looping and compression addition, and provide flexibility to manage uncertainty of future generation demand while minimizing the risk of stranding pipeline and compression assets. The availability of on-system storage and peaking capacity will provide immediate capacity benefits to TGVI since its system is currently constrained to meet its core market demand growth and the existing transport demand during winter peaking periods. TGVI would avoid future transmission system expansion as well as reduce its capacity requirement through the CTS. The capacity benefit from the LNG Storage Facility will also put TGVI in position to offer firm service to the ICP for a longer period of time which helps to reduce average system costs to all TGVI customers. The capacity benefit of the provided by storage services to TGI depends on the future decisions by BC Hydro on the long-term operation of Burrard Thermal. However these benefits could be significant by allowing TGI to avoid major pipeline looping in the urban environment of the Lower Mainland should Burrard Thermal continue to operate beyond In short, availability of the LNG Storage Facility affords BC Hydro a longer timeframe to determine its long-term gas demand for ICP and Burrard power generation without incurring additional cost to gas customers. Page 90

97 Mt. Hayes LNG Storage Facility Figure 7-11 Firm Service Available LNG Portfolio 250 LNG Storage Design Day System Capacity Peakday Demand [TJ/d] Available Design Day Capacity Joint Venture Member Mills Whistler Squamish TGVI Core Figure 7-12 Firm Service Available Pipe and Compression Portfolio V3 V Design Day System Capacity V2 & V5 V1-U Peakday Demand [TJ/d] Avail Design Day Capacity Joint Venture Member Mills Whistler Squamish TGVI Core Page 91

98 Mt. Hayes LNG Storage Facility 7.3. Additional Benefits The proposed LNG Storage Facility located on Vancouver Island and connected to TGVI s transmission system offers additional benefits in terms security of supply, improved system reliability, reduced price volatility and increased operating flexibility. In addition, as discussed in previous paragraph, the LNG Storage Facility will enhance TGVI s ability to provide a higher level of firm transportation service. These benefits are described below. These additional benefits were reviewed during the regulatory filing process of the TGVI CPCN application in 2004 for an LNG project at Mt. Hayes with a 1.0 Bcf storage capacity and 100 Mcfd deliverability. The BCUC concluded in the 2005 Decision that an on-island LNG facility significantly improves security of supply against system outages and provides operational flexibility, reduces gas price volatility, and provides a useful additional resource for balancing of the TGVI System (Section 9.3.1, and pages 56-57). With a larger 1.5 Bcf storage capacity and 150 MMcfd deliverability, the LNG Storage Facility will be able to extend these benefits to TGI s CTS as well Incremental Transportation Revenue In both the LNG portfolio and the P&C Portfolio for the Baseline Demand Scenario, additional system capacity is available from year to year that could be used to provide additional firm transportation service and which in turn would reduce the average unit cost of transmission service and mitigate the rate impact to all TGVI customers. As discussed in Section and illustrated by comparing Figure 7-11 and Figure 7-12, the available incremental firm transportation capacity is greater in the LNG Storage Portfolio than the P&C Portfolio. The value of this benefit can be estimated by assuming that on average 10% to 25% of the additional firm transport capacity is contracted from year to year. Assuming an average unit rate of $0.90 per GJ/d of capacity, the present value of the incremental transportation service is summarized in the Table 7-6 which demonstrates that the LNG portfolio offers significantly greater opportunity value than the P&C Portfolio. Note that this benefit flows directly to existing customers. The lower value over the 25 Year evaluation period reflects the fact that more capacity is available in the later years in the period under the P&C Portfolio as can be seen by comparing the Figure 7-11 and Figure Page 92

99 Mt. Hayes LNG Storage Facility Table 7-6 Incremental Transport Revenue $ Million Incremental Transport Revenue Benefit 25 Year 15 Year Evaluation Evaluation Period Period 6.2% Discount Rate $27 $36 10% Discount Rate $27 $ Security of Supply From a regional perspective, the TGVI and TGI Lower Mainland service areas are characterized by a lack of market area storage and dependence on a single supply corridor from the Westcoast and Northwest pipeline systems. As the LNG Storage Facility is located at what is effectively the tail-end of this regional system, use of gas supply from this facility to mitigate the effect of a supply restriction would benefit all customers downstream of the restriction. In the event of an upstream failure that limits physical delivery capacity, TGVI and TGI could use the capacity of the LNG Storage Facility to maintain supply on Vancouver Island and to reduce delivery requirements on the CTS. For example, under system upset or emergency conditions the LNG Storage Facility could provide enough on-island supply to meet roughly 25 days of average core market winter demand. As a recent example, the cold weather event of late November 2006 affected a large portion of the Pacific Northwest region with temperatures dropping lower than the normal weather year coldest temperature; the heat sensitive demands reached higher than normal year peak values. Coincident with the cold weather event, the Westcoast T-south system on November 27, 2006 experienced declining system pressures which resulted in a reduction in T-South delivery capacity to Huntingdon. As a result, Westcoast had difficulties meeting its firm gas nominations. This condition also impacted the NWP system by reducing supply available to move south to service the PNW. Had the condition been extended, it would have also impacted downstream storage redeliveries. TGI was able to use LNG from its Tilbury Facility in the Lower Mainland to mitigate this particular threat of supply restriction until Westcoast system pressures were restored to acceptable levels. The availability of the supply from the LNG Storage Facility in conjunction with the Tilbury Facility will enhance the capability of TGI and TGVI to manage such events. Page 93

100 Mt. Hayes LNG Storage Facility As regional resources become more constrained to meet growing demand across the Pacific Northwest, the probability of such events impacting the supply demand balance increases. The value of the benefit of enhancing the on-system storage capability for TGVI and TGI can be quantified by estimating the cost to the utilities to compete for replacement or emergency supply in the spot market. Figure 7-13 provides the historical Sumas daily price from 1996 and compares the highest price seen in each winter to the average winter price. Excluding the 2000/01 outlier, the data shows that the premium over the average winter price has been US$0.41 to $9.66 per MMBtu, which is equivalent to an average premium of US$3.05 per MMBtu. This represents a potential annual avoided cost to TGVI and TGI of $75,000 to $1.7 million, or an average of $549,000, based on incremental supply of 150 MMcfd from the LNG Storage Facility on Vancouver Island to mitigate market disconnects on any one day. Figure 7-13 Historical Sumas Price Page 94

101 Mt. Hayes LNG Storage Facility Improved System Reliability Availability of the LNG Storage Facility will also provide alternate system capacity and supply to core customers on the TGVI System in the event of capacity reduction or interruption due to compressor unit outage or pipeline damage on the TGVI system. The TGVI transmission system, operating at a MOP of 2160 psig, relies on its entire installed compressor horsepower to provide system capacity to meet peak day demands. In the unlikely event of an outage of the T70 compressor unit (ISO 9670 hp) at Coquitlam (V1) Station coincident with cold weather conditions, the reduced transmission system capacity would not be sufficient for winter 2008 to meet core market demand plus the firm transportation to the mills of the VIGJV for the 5 coldest days on the design year load duration curve. The duration of potential system shortfall would increase to 12 days by winter 2012 with increasing core market demand. To limit the duration of potential outage, TGVI plans to acquire a T70 spare engine in With the spare engine, the outage would be limited to 2 days, the time required to change the engine. In order to mitigate the service impact of system upset or emergency conditions, the LNG Storage Facility could provide enough on-island supply to meet at least the 10 days of core market demand during the coldest weather period, or roughly 25 days of core market demand during an average winter period. Without access to an on-system resource such as that provided by the LNG Storage Facility, in the event of a complete transmission service interruption due to compressor unit failure or pipeline damage for two or more days, TGVI would have to shut off service at customers meters from both the transmission and all of the distribution systems during initial outage; and would be required to perform safety checks of the gas systems; then relight individual customers gas appliances as the transmission service is recovered and the distribution systems are reactivated. Depending on the severity of an interruption on the transmission system, TGVI would minimize customer outage by systematically shutting off services to selective communities to maximize the survival time of the remaining communities. For an event of partial transmission service interruption affecting a major community the size of Nanaimo or Victoria, the direct cost for the shut off, system safety check and relight, based on an average cost of $70 per customer, would be in the range of $1.2 and $3.0 million, respectively based on forecast customer counts in Page 95

102 Mt. Hayes LNG Storage Facility The direct cost of shut off, system safety check and relight to TGVI customers from a complete system service interruption would be in the range of $8 million in 2010 to $11 million by The service shut off, safety checks, and service restoration of the entire transmission and all of the distribution systems could take up to 5 to 7 weeks during such a major outage depending on the number of field operations personnel available including external resources from mutual aid programs with other gas utilities. With the availability of the LNG Storage Facility, TGVI would be able to utilize LNG to replace system capacity loss due to single compressor unit outages or transmission damage to serve core market customers downstream of the damage, while customers upstream of the damage would continue to be supplied as normal. The mitigation of gas service interruptions by means of the LNG Storage Facility would minimize revenue losses for TGVI, while also minimizing impacts on the local economy by maintaining critical service to hospitals and shelters for customers during cold weather Reduced Rate Volatility The LNG Storage Facility will help reduce rate volatility for the customers of TGVI and TGI, and other regional gas consumers. A large storage facility close to a major market helps mitigate commodity price increases during periods of peak demand. Such commodity price increases were evident in the two recent cold snaps in the Pacific Northwest. On November 28, 2006, when Vancouver experienced the coldest day since December 1996, the Sumas gas price was $11.82 per GJ. This is a $2.23 Cdn per GJ increase over the average gas price of the 10 days before and 10 days after November 28, Again on January 12, 2007, when Vancouver experienced the 12th coldest day since December 1996, the Sumas gas price was $9.27 per GJ, which is a $1.38 Cdn per GJ increase over the average gas price of the 10 days before and 10 days after January 12, The LNG Storage Facility will increase regional supply capacity and decrease the risk of regional price disconnects Operational Flexibility and Efficiency LNG storage gives superior load following capability both in terms of capacity and energy. This capability enables its use as an intermediate or seasonal supply, not just as a peaking resource, as well as a resource for balancing and quick response to pressure upset situations. Page 96

103 Mt. Hayes LNG Storage Facility Balancing As an on-system supply, access to, and use of, the LNG Storage Facility will be a valuable addition to the balancing resources currently available to both TGVI and TGI. Both TGVI and TGI schedule gas supply from third parties through day-ahead nomination based on forecasted weather. Imbalances often occur due to weather forecast adjustments or demand variations. The error in the TGVI and TGI daily temperature forecast, at a 95% confidence level, is 3 degree Celsius, and is equivalent to 9 TJ/d for TGVI and 72 TJ/d for the TGI customers served by the CTS. Opportunities for same-day adjustments to match the forecast to the actual demand are limited due to fixed re-nomination schedules associated with third party transport and storage resources. As an on-system resource, availability of the LNG Storage Facility will provide an efficient means to balance supply on the system compared to TGVI s current resource options. TGVI and TGI will be able to call on LNG supply on short notice and will not be hindered by upstream re-nomination schedules or by TGVI s contracted capacity agreements. As an on-system resource, dispatched at the request of TGVI and TGI, LNG storage at the LNG Storage Facility provides greater flexibility for upward nominations to eliminate imbalances on both TGVI System and the CTS. Other than the physical capabilities of the LNG Storage Facility, there are essentially no limitations on the number of hours or days in the year that the LNG supply can be used. The send out rate can be varied continuously which will allow TGVI to respond quickly and accurately to variations in demand. Gas deliveries from the LNG Storage Facility do not have to follow third-party pipeline nomination schedules so the service can be provided on much shorter notice and flow can be altered to best match TGVI and TGI s requirements for capacity and supply on an hour-by-hour basis. As an on-system resource, the LNG Storage Facility can also be dispatched on short notice in response to transient flow conditions that may develop on the pipeline helping to mitigate the impact of significant transport load fluctuations Operational Efficiency Without access to on-system storage, the TGVI System relies on line-pack to meet the transient demands from the industrial customers (i.e. the VIGJV and ICP) directly on the transmission Page 97

104 Mt. Hayes LNG Storage Facility system as well as customers on the distribution systems. In order to have the flexibility to react to a transmission system pressure upset condition caused by an unplanned compressor shutdown or valve closure, the line-pack pressure level is maintained at a level higher than that required for normal operation. The higher line-pack increases compression fuel usage. With LNG supply available to react quickly to a pressure upset condition, TGVI would be able to optimize its line-pack level while maintaining the same level of flexibility Operations and Maintenance From an operational perspective LNG supply from the LNG Storage Facility will provide greater flexibility to deal with the requirements of planned maintenance on the TGVI System. LNG will be used as a source of secondary supply to extend the duration that pipeline facilities can be removed from service. Currently, during maintenance on the transmission system that requires the sections of the pipeline to be out of service, downstream customers rely solely on line-pack and service to transport customers must be restricted. These requirements restrict the windows for operation and maintenance work. The LNG Storage Facility would provide a secondary source of supply that would allow greater flexibility for scheduling this work so that restrictions could be avoided Summary of Additional Benefits The additional benefits provided by the proposed LNG Storage Facility discussed in this Section 7.3 are summarized below: Incremental Firm Transport Revenue could provide a benefit of between $32 to 42 million over the planning period (Section and Table 7-6); Security of supply is enhanced by the location of the LNG Storage Facility, effectively at the end of regional transmission infrastructure that serves TGVI and TGI s service areas (Section 7.3.2). The facility would help mitigating any impacts of any upstream supply restrictions or price disconnects; Page 98

105 Mt. Hayes LNG Storage Facility Improved system reliability is realized by the availability of an alternate supply source for TGVI s customers in the event of an interruption or loss of system pressure on TGVI s System (Section 7.3.3). This significantly reduces the risk of service interruptions and associated relight costs; The LNG Storage Facility will help reduce commodity price volatility for customers of TGVI and TGI and other regional gas consumers that compete for gas at Huntingdon/Sumas by providing for additional capacity during periods of peak demand (Section 7.3.4); and Operational flexibility and efficiency benefits will be realized by the provision of an additional resource for balancing and quick response to upset conditions (Section 7.3.5). The use of the LNG Storage Facility as a secondary supply allows greater flexibility for scheduling of operations and maintenance work. Page 99

106 Mt. Hayes LNG Storage Facility 8. ECONOMIC JUSTIFICATION AND CUSTOMER IMPACTS This Section discusses the economic justification for the TGVI LNG CPCN Application and the benefits to TGI of entering into a long-term firm agreement with TGVI for storage services from the LNG Facility. The value of the LNG storage resource is considered first for TGVI and then TGI followed by an analysis of the customer rate benefits for TGVI of the LNG facility. The economic justification for TGVI considers the combined costs and benefits of the LNG Facility cost of service (from Section 5), the gas supply benefits and revenues from TGI (from Section 7.1) and the TGVI system benefits (Section 7.2). For TGI the evaluation considers CTS capacity benefits (Section 7.2) and mid-stream benefits that arise in specific circumstances. The economic benefits for TGVI and TGI are developed for a base case (the Baseline Scenario) and several sensitivity scenarios. In addition, a discussion of the significance of Other Benefits as identified in Section 7.3 is included. The last component of this Section discusses possible approaches to the treatment in TGVI s cost of service of the net LNG costs and provides a comparison of customer rate impacts of the LNG portfolio and the Pipe and Compression portfolio under these possible treatments of the LNG costs TGVI Portfolio Comparison As discussed in TGVI s 2006 Resource Plan, the LNG Storage Portfolio provides the most costeffective solution for meeting TGVI s long term capacity and peaking gas requirements. In addition, by constructing a 1.5 Bcf facility, TGVI is able to reduce average per unit cost of storage through the economies of scale realized by the larger size of the facility. In this way by offering firm storage services to TGI at a fixed price, TGVI is subsequently able to reduce the cost impact to its own customers. This section provides the comparison of the LNG Storage and P&C Portfolios for TGVI for the 1.5 Bcf facility in a similar fashion to that presented in section 7.2 of the TGVI 2006 Resource Plan based on the updated costs provided in this Application. Page 100

107 Mt. Hayes LNG Storage Facility Under the approvals sought in this Application TGVI will own and operate the LNG facility. TGVI will, under the terms of the Storage and Delivery Services Agreement, provide a 1 Bcf and 100 MMcfd of the LNG Storage Facility capacity to TGI at a fixed price that is has been determined based on the value to TGI of an incremental storage resource delivered to its system at Huntingdon/Sumas. TGVI proposes to allocate the remaining costs to the gas supply and transmission components of its cost of service based first on the recognition of the value of the LNG service as a storage resource in its gas portfolio and the residual as transmission capacity benefits for all customers on its system. For TGVI, the benefit of the LNG Storage Portfolio as compared to the Pipe & Compression Portfolio is driven by both the gas portfolio benefits and system capacity benefits. This section compares the outcome of the two portfolio approaches side by side based on the following assumptions: TGVI System Costs reflects the incremental cost of service of the transmission facilities added by TGVI under the different scenarios as discussed in Section and summarised in Table 7.3. In the LNG Storage Portfolio, TGVI System Costs include the cost of the System Facilities. LNG Cost of Service reflect TGVI s annual cost of service associated with the LNG Storage Facility as discussed in Section 5.2 and summarised in Table 5-1. TGVI Gas Supply Benefit represents the value of the storage resource to TGVI s gas portfolio. The valuation of the storage resource is discussed in Section 7.1. Note that the values summarised in Table 7-1 is for the total capacity of the 1.5 Bcf facility, whereas the TGVI Gas Supply Benefit is based the 0.5 Bcf of capacity TGVI reserves for its own use. TGI storage revenues reflect the price TGI pays under its agreement with TGVI for 1.0 Bcf storage capacity as discussed in Section Financial Assumptions The 2006 Resource Plans provided a forecast of customer demand, gas supply and facility requirements over a 25 year planning period ending in In addition, financial comparisons of the different portfolio options were provided for 15 and 25 year evaluation periods beginning Page 101

108 Mt. Hayes LNG Storage Facility at the same point as the 25 year planning horizon. The use of two different evaluation periods illustrates the sensitivity of the analysis to the length of the study period and is consistent with the recommendations of the Commission Panel in its February 2005 decision as follows: In future resource plans, to address TGVI s concerns about sub-optimal solutions, the Commission Panel recommends that the Utility also conduct 15-year and 25-year evaluations as sensitivity cases to assess the effect of the length of the study period. (page 18, end of section 3.2.2) Note that the 25 year planning period begins in 2007 while the expected in-service date for the LNG Storage Facility is Accordingly, the 15 and 25 year evaluation periods include only the first 11 and 21 years of operation of the LNG Storage Facility. Similarly, the present value calculations in the financial analysis was performed using both a 6.2% and 10% discount rate and is also consistent with the recommendations of the Commission in the February 2005 decision as follows: The Commission recommends that TGVI consider its capital structure for the planning period in the annual Resource Plan updates, and use a range of discount rates to reflect the possible capital structure. In future Resource Plans, TGVI should present financial comparisons using both a discount rate that is based on its after-tax cost of capital, and higher discount rates to reflect risks to cash flows. (page 21, end of section 3.2.3) The 6.2% discount rate represents the forecast of TGVI s after tax weighted average cost of capital based the 60/40 debt equity split and an assumed long term ROE of 9.5% based on the current ROE formula. The higher discount rate of 10% is used as a sensitivity to reflect the uncertainty with future costs and demand. Appendix F provides a summary of the financial assumptions used in the cost of service analysis and detailed schedules supporting the financial results provided in following sections. Page 102

109 Mt. Hayes LNG Storage Facility 8.3. TGVI Baseline Scenario This scenario is based on TGVI s Baseline Demand Forecast, P50 capital costs, and gas supply benefits based on the same unit value paid by TGI to TGVI pursuant to the Storage and Delivery Services Agreement. The results in Table 8-1 show that the net costs of the LNG Storage Portfolio to TGVI, based on the arrangements proposed in this Application, are significantly lower than the cost of the P&C Portfolio. The Baseline scenario demonstrates a large present value net benefit from the LNG Storage Portfolio over both the fifteen-year and twenty-five year evaluation periods and for both discount rates. Over the 25 year evaluation period, the net saving is expected to be $66 million ($49 versus $155 million) while in the 15 year evaluation period, which includes only the first eleven years of operation of the LNG Storage Facility, savings of $21 million ($27 versus $48 million) would be realized. Table 8-1 TGVI Portfolio Comparison Baseline Case ($ Millions) 25-Year Evaluation Period P&C Portfolio 6.2% LNG Storage Portfolio P&C Portfolio LNG Storage Portfolio TGVI System Costs $115 $21 $72 $15 TGVI LNG Costs TGVI Gas Supply Benefit (68) (48) Storage Revenues from TGI (135) (97) Net Portfolio Cost $115 $49 $72 $33 15-Year Evaluation Period 6.2% TGVI System Costs TGVI LNG Costs TGVI Gas Supply Benefit (45) (36) Storage Revenues from TGI (90) (72) Net Portfolio Cost $48 $27 $36 $ Sensitivity Scenarios This section summarises the evaluation a number of different scenarios performed in order to measure the impact of the net benefits of the Project resulting from any change in any of the Page 103

110 Mt. Hayes LNG Storage Facility base case assumptions such as capital costs, forecast demand and/or market value of alternate storage resources. The scenarios that were assessed are described in Table 8-2 below: Table 8-2 Description of Sensitivity Scenarios Scenario Assumptions Baseline Scenario LNG and TGVI System costs based on P50 Capital Costs and (Sec 8.3) TGVI Baseline Demand scenario (no firm service to ICP) Gas Supply Benefits based on JPS + discounted TF1 TGI Revenues based on Storage & Delivery Agreement Base + ICP LNG and TGVI System costs based on TGVI Base + ICP Scenario Demand scenario which includes firm service to ICP All other assumptions same as Baseline Scenario Low Core Demand LNG TGVI System Costs based on low core demand forecast Scenario and no firm service to ICP All other assumptions same as Baseline Scenario High Cost LNG and TGVI System costs based on P90 Cost Estimates and Scenario TGVI Baseline Demand All other assumptions same as Baseline Scenario Upside Case LNG and TGVI System Costs based on P10 Cost Estimates and TGVI + ICP Demand Scenario Gas Supply Benefits based on avoided WEI Costs TGI revenues the same as Baseline Scenario Appendix F provides the summary tables for each of these scenarios as shown for the Baseline Scenario described in Table 8-1. The results for each scenario are shown Table 8-3 and Table 8-4 for the 25 and 15 year evaluation periods respectively. In these summary tables, the Net LNG Benefits represent the cost savings that would be realized as a result of the Project over the evaluation periods relative to the Pipe and Compression Portfolio approach. The Baseline Scenario is shown for comparison purposes. Page 104

111 Mt. Hayes LNG Storage Facility Table 8-3 Net Portfolio Costs Sensitivities 25 Year Net Portfolio Cost ($ Millions) 6.2% 25-Year Evaluation Period P&C LNG Portfolio Portfolio Net LNG Benefits Baseline Scenario Base + ICP Demand Scenario Low Core Demand Scenario High Cost Scenario Upside Scenario % Baseline Demand Scenario Base + ICP Demand Scenario Low Core Demand Scenario High Cost Scenario Upside Scenario Table 8-4 Net Portfolio Costs Sensitivities 15 Year Net Portfolio Cost ($ Millions) 6.2% 15-Year Evaluation Period P&C LNG Portfolio Portfolio Net LNG Benefits Baseline Demand Scenario Base + ICP Demand Scenario Low Core Demand Scenario High Cost Scenario Upside Scenario % Baseline Demand Scenario Base + ICP Demand Scenario Low Core Demand Scenario High Cost Scenario Upside Scenario Page 105

112 Mt. Hayes LNG Storage Facility The results of the sensitivity analysis show that there are positive net benefits provided by the Project across a broad range of assumptions, and over both the fifteen and twenty five year evaluation periods. Below are some important observations: Only the Base + ICP and the Upside scenarios assume that BC Hydro continues to be a long term customer on TGVI s System for service to ICP, however all scenarios show positive net benefits. Hence, the justification for the Project is not dependant on obtaining long term firm agreement with BC Hydro; In the Base + ICP scenario, the LNG Net Benefits are comparable to the Baseline Scenario over the 25 year evaluation period, and are significantly higher over the shorter term evaluation period since the LNG facility allows significant deferral of pipe and compression expansion facilities that would otherwise be required early in the planning period to serve ICP; The High Cost scenario which assesses the impact of the P90 cost estimates results in higher costs in both the P&C and LNG Portfolios, however the impact on the Net LNG Benefit is relatively small (e.g. $61 million for the High Cost Scenario versus $66 million for the Baseline Scenario at 6.2% discount as shown in Table 8.3); and The Net LNG Benefits in the Low Core Demand scenario are lower than in the Baseline scenario as the lower demand (and no service to ICP) defers the requirement for expansion facilities in the Pipe & Compression Portfolio. However, this scenario continues to provide positive benefits. In addition, as discussed in section 7.2.9, the LNG Storage Facility will provide significantly higher capacity to provide short firm term service to ICP and/or incremental transport loads that would not be available under the P&C Portfolio. Note that the LNG Net Benefits results represent avoided costs of alternate storage resources and capacity expansion facilities and do not include consideration of the additional benefits described in section 7.3 which would further increase the value of the Project to customers. This potential is discussed in the following section. Page 106

113 Mt. Hayes LNG Storage Facility 8.5. Impact of Additional Benefits Incremental Transportation Revenues As discussed in section 7.2.9, the LNG Storage Facility provides greater flexibility to continue to serve ICP or future firm demands from the industrial customers thereby offering the potential to further reduce the average unit cost impact to customers. The potential value of incremental transportation revenues associated with this increased flexibility to the customers on TGVI s system assumed in the Baseline Demand scenario (i.e. Core TGVI, TGW and Squamish customers and the VIGJV) is discussed in Section 7.3 and summarised in Table 7-5. Consideration of this value in the net benefits further improves the Project value as shown in Table 8-5 for the Baseline Scenario. Table 8-5 Baseline Scenario Adjusted Net Benefits PV $Millions Discount Rate 25 Year Evaluation Period 6.2% 10% Net LNG Benefits (Table 8-3) Net Incremental Transportation Revenues (Table 7-6) Adjusted Net Benefits PV $Millions Discount Rate 15 Year Evaluation Period 6.2% 10% Net LNG Benefits (Table 8-4) Net Incremental Transportation Revenues (Table 7-6) Adjusted Net Benefits The value of the flexibility realized by the LNG Storage Facility applies to all the scenarios described in Section 8.4. While Tables 8.3 and 8.4 summarise the value of the avoided costs realized by the LNG Storage Portfolio relative to the Pipe & Compression Portfolio, the potential to realize additional transportation revenues provides further value to customers by allowing TGVI to use its transmission system more efficiently and thereby reduce unit costs and Page 107

114 Mt. Hayes LNG Storage Facility subsequent rate impacts. The impact on the range of potential outcomes associated with the Scenarios described in Table 8-3 and Table 8-4 is summarised in Table 8-6. Table 8-6 Potential Range of Adjusted Net Benefits PV $Millions Discount Rate 25 Year Evaluation Period 6.2% 10% Net LNG Benefits (Table 8-3) 32 to to 62 Net Incremental Transportation Revenues (Table 7-6) Adjusted Net Benefits to to 94 PV $Millions Discount Rate 15 Year Evaluation Period 6.2% 10% Net LNG Benefits (Table 8-4) 6 to 60 3 to 47 Net Incremental Transportation Revenues (Table 7-6) Adjusted Net Benefits to to Additional Benefits In the 2004 Commission proceeding, in addition to financial benefits TGVI identified a number of additional benefits relating to security of supply, reduced rate volatility, reduced CTS expansion costs, balancing and reduced risk of stranded assets. The Commission Panel discussed the merits of these additional benefits in Section 9 of its February 2005 decision and concluded: The Commission Panel concludes that, in addition to the financial costs and benefits discussed in the next Chapter, the LNG portfolio would have several material benefits for TGVI ratepayers, compared to portfolios that include only compression, pipeline looping and curtailment. (2005 Decision page 58) Section 7-3 of this Application provides further review and assessment of the additional benefits that would be provided by the LNG Storage Facility. Aside from the incremental transportation Page 108

115 Mt. Hayes LNG Storage Facility revenues discussed in 8.5.1, the following benefits and the potential financial impacts were discussed: Security of Supply (section 7.3.2); Improved System Reliability (section 7.3.3); Reduced Rate Volatility (section 7.3.4); and Operational Flexibility and Efficiency (section 7.3.5). Each of these items has the potential to improve the justification for the LNG Storage Facility by improving operational flexibility or avoiding or mitigating the cost consequences of adverse circumstances. TGVI believes they are important factors to consider in the evaluation of this Project. Page 109

116 Mt. Hayes LNG Storage Facility 8.6. TGI Portfolio Analysis TGI is supporting the Project by entering into a long-term arrangement with TGVI for storage and delivery services. Under terms of the Agreement, as described in Section 5.3, TGI will pay a fixed price charge for the initial term 20 years following which the annual demand charge will be based on an allocated share of TGVI s cost of service of the LNG Storage Facility. The primary benefit of the Agreement to TGI is access to an incremental storage resource as part of its midstream gas portfolio. The LNG Storage Facility will help TGI to meet incremental peaking requirements on its system and also help to mitigate the cost and availability risk associated with its existing storage portfolio. As discussed in Section 7.2.5, in addition to a midstream portfolio resource, the LNG Storage Facility will also provide TGI the flexibility to manage the uncertainty relating to the future of Burrard Thermal without requiring it to expand the CTS TGI Benefit TGI s cost for storage services under its agreement with TGVI reflects the cost of an incremental storage resource based on the current JP storage expansion project and NWP redelivery capacity. As discussed in Section 7.1 of this Application, and Appendix G of the TGI 2006 Resource Plan, the capacity offered by the JP storage expansion project was fully subscribed and there is limited firm redelivery capacity available. There is no certainty on the availability and cost of future downstream storage expansion capacity. TGI s primary alternative to meeting future requirements is therefore to hold additional upstream pipe capacity. As a result, the assessment of the maximum value of the storage resource from TGI s perspective is the value of holding Westcoast T-South capacity assuming a historical level of mitigation as discussed in section The forecast of JP storage plus redelivery costs and WEI transport form the potential range of value provided by the LNG Storage Facility as summarised in Table 8-7. These values correspond to those shown in Table 7.1 prorated for the 1.0 Bcf of firm capacity of the 1.5 Bcf facility for which TGI is contracting under the Storage and Delivery Services Agreement. Page 110

117 Mt. Hayes LNG Storage Facility Table 8-7 TGI Midstream value PV $Millions Discount Rate 25 Year Evaluation Period 6.2% 10% WEI transport with mitigation TGVI Demand Charges* Net Midstream Benefit Year Evaluation Period Discount Rate 6.2% 10% WEI transport with mitigation TGVI Demand Charges* Net Midstream Benefit 11 9 *Equal to 2/3 of value JP Storage with NWP transport from Table TGI Benefit Table 8-8 describes the three separate scenarios that were evaluated to assess the financial benefits of the LNG Storage Facility to TGI through the Storage and Delivery Services Agreement. These scenarios correspond to the similar TGVI scenarios described in Table 8-2. The High Cost Scenario is excluded since the payments TGI makes to TGVI under the Storage and Delivery Services Agreement are fixed based on the value of alternate market storage and therefore not dependant on the final cost of the LNG Storage Facility. The Low Core Demand scenario is also excluded since the requirements for CTS upgrades are driven by Burrard Thermal and changes in core growth would have a negligible impact. Page 111

118 Mt. Hayes LNG Storage Facility Table 8-8 Description of TGI Scenarios Scenario Assumptions Baseline Scenario TGVI Baseline Scenario Storage Value based on Storage & Delivery Agreement (i.e. JPS plus redelivery) Burrard retired and BTA terminated in 2014 Base + Burrard TGVI Base + ICP Scenario Scenario Storage Value based on Storage & Delivery Agreement Avoided CTS costs assumes operation of Burrard to 2021 Upside Scenario TGVI Base + ICP Scenario Gas Supply Benefits based on avoided WEI Costs Avoided CTS costs assumes operation of Burrard to 2021 The results are summarised in Table 8-9 and Table 8-10 for the 25 year and 15 year evaluation periods. As before, the evaluation periods commence in 2007 and therefore include only 21 and 11 years of LNG storage services assuming the LNG Storage Facility goes into service in In the baseline scenario, Burrard is assumed to be retired in 2014 and therefore there are no avoided CTS expansion costs. It is also assumed that TGI is able to access future incremental downstream storage resources at the current cost of expansion and re-delivery capacity on which the contract with TGVI is based. The other two scenarios assume that the agreement with TGVI for storage services allows TGI to avoid CTS expansion facilities in order to meet its obligations to serve Burrard Thermal until at least In the Upside Scenario, it is also assumed that the alternative midstream resource to the TGVI LNG storage services is priced at the cost of holding WEI pipeline capacity (with mitigation). Page 112

119 Mt. Hayes LNG Storage Facility Table 8-9 TGI Net Benefits 25 Year Net Portfolio Cost ($ Millions) 6.2% 25-Year Evaluation Period Capacity Midstream Net Benefit* Benefit** Benefit Baseline Scenario Base + ICP + Burrard Scenario Upside Scenario % Baseline Demand Scenario Base + ICP + Burrard Scenario Upside Scenario *Capacity Benefit from Table 7-5 **Midstream Benefit from Table 8-7 Table 8-10 TGI Net Benefits 15 Year Net Portfolio Cost ($ Millions) 6.2% 25-Year Evaluation Period Capacity Midstream Net Benefit Benefit Benefit Baseline Scenario Base + ICP + Burrard Scenario Upside Scenario % Baseline Demand Scenario Base + ICP + Burrard Scenario Upside Scenario *Capacity Benefit from Table 7-5 **Midstream Benefit from Table 8-7 The results show that the financial benefits TGI would realize from the Project ranges from 0 to $74 million over the 25 year evaluation period or up to $39 million over the shorter period which encompasses the first 11 years of operation of the LNG Storage Project. Page 113

120 Mt. Hayes LNG Storage Facility In addition to these financial cost savings, the construction of an storage facility will allow TGI to realize many of the same benefits as TGVI that are described in section 7.3. In particular security of supply (section 7.3.2), reduced rate volatility (section 7.3.4) and operational flexibility and efficiency (section 7.3.5) TGVI Customer Rate Impact Sections 8.3 and 8.4 compare the net present value of the incremental costs for TGVI of the LNG Storage Portfolio with the P&C Portfolio. The analyses show that the LNG Storage Portfolio is the preferred alternative for meeting future system demand requirements because it supports TGVI s ability to provide natural gas services to its customers at the least delivered cost. This section provides an assessment of the relative customer rate impacts of the two portfolios based on certain assumptions. However, TGVI is not seeking at this time approval of any allocation or rate design approach for recovery of the LNG Storage Portfolio net costs from its customers. As part of this Application, TGVI is seeking approval of the LNG Storage Facility, System Facilities, and TGI Storage and Delivery Agreement. TGVI is also seeking approval of the ROE treatment and the adjusted depreciation schedule associated with respect to LNG Storage Facility. The allocation of costs and design of rates to recover the cost of the LNG Storage, net of revenues from TGI, and the cost of the TGVI connecting facilities will be the subject of a future rate review. This section examines the estimated cost allocations based as much as possible on current approved rate design principles for TGVI. The rate impacts depicted in the following figures and table are illustrative and present a reasonable range of outcomes. The LNG storage capacity will be used differently by each utility. TGI will use the capacity as part of its gas supply portfolio. Since the price to TGI in the Storage and Delivery Agreement is based on the alternative storage resource Jackson Prairie storage and redelivery to Sumas no incremental impact on the TGI gas supply portfolio is assumed. TGVI will use the LNG capacity as part of its gas supply portfolio and also for system capacity to meet its firm peak day obligations. Accordingly, the discussion below focuses on the impact to TGVI customers. Page 114

121 Mt. Hayes LNG Storage Facility System Cost Allocation Assumptions The TGVI customer rate impacts were assessed for both the LNG Storage and the P&C Portfolios under the Baseline Demand Scenario (i.e. TGVI, TGW and Squamish Core Demand and the VIGJV). The assessment was based on current TGVI cost allocation principles where applicable. The cost allocations for the LNG Storage Portfolio assumed that TGVI would assign a portion of the LNG Storage Facility costs to its gas supply portfolio based on the same unit value of storage implicit in the Storage and Delivery Agreement with TGI. The costs assigned to the TGVI gas supply portfolio are offset by the share of the avoided midstream supply costs discussed in Section 7.1 and Appendix E that TGVI will realize. TGVI s remaining LNG Facility costs, net of revenue from TGI ( Net LNG Storage Facility Costs ), have been allocated to core market and transportation customers using two different approaches described in more detail below. Figure 8-2 below, illustrates the portion of the LNG Storage Facility costs, in this case for the year 2015, that are assigned to TGI, the TGVI gas supply portfolio and the Net LNG Storage Facility costs. These figures assume P50 capital costs. Figure 8-2 Illustrative Allocation of Costs $Millions TGVI LNG Storage Facility $12.6M $6.3M $1.9M TGI Storage and Delivery TGVI Gas Supply Portfolio TGVI Net LNG Storage Page 115

122 Mt. Hayes LNG Storage Facility In this illustrative example, in 2015, of the $20.8 million LNG Storage Facility costs, $12.6 million is the responsibility of TGI, while $6.3 million is assigned to the TGVI Gas Supply Portfolio. The TGI amount of $12.6 million is the annual charge for 2015 in the Storage and Delivery contract based on 1.0 Bcf of capacity and 100 MMcfd deliverability. The TGVI amount of $6.3 million allocated to TGVI s gas supply portfolio is half of annual charge to TGI in 2015 since TGVI has half of TGI s capacity in the facility (i.e., 0.5 Bcf of capacity and 50 MMcfd deliverability). The residual LNG Storage Facility amount of $1.9 million is counted as a system capacity benefit and is allocated to core market and transportation customers on an illustrative basis under the following two LNG Storage Portfolio cost allocation approaches: Approach 1 Net LNG Storage Facility costs are allocated to all TGVI customer classes (i.e., core market and transportation customers); Net LNG Storage Facility costs and TGVI transmission system costs are allocated to all customers based on the firm contract demand of transport customers and forecast core market peak day demand; Distribution system costs are allocated to core market customers only. Approach 2 Net LNG Storage Facility costs are allocated to core market customers only; TGVI transmission system costs are allocated to all customers based on firm contract demand of transport customers and peak demand of core customers net of TGVI s portion of the LNG Storage Facility sendout capacity; and Distribution system costs are allocated to core market customers only. The Baseline Demand Scenario assumes that BC Hydro is not a firm customer (for ICP) and therefore transmission capacity is not expanded to meet the contract demand for ICP. However, as discussed in section 6.1.3, TGVI expects that BC Hydro will continue to require some level of transportation service for ICP over the planning period. For the purposes of this analysis, a simplifying assumption was made that BC Hydro will contract from period to period on average at a level equal to 50% of ICP s current contract demand of 45 TJ/day. This simplifying assumption could also as a proxy for interruptible revenues for service to ICP. Page 116

123 Mt. Hayes LNG Storage Facility For the LNG Storage Portfolio, once the LNG Storage Facility is in service, as discussed in section 7.2.9, TGVI will have sufficient capacity to provide firm transportation service to ICP to meet the full demand of 45 TJ/d, assuming 53 hours of curtailment is available, at least until As illustrated in Table 7-1, the LNG Storage Portfolio is identical for both the Baseline Demand Scenario and the Base plus ICP Demand Scenario up to 2019 when the Squamish compressor may be required. Therefore an additional scenario was assessed for the LNG Storage Portfolio in which BC Hydro contracts for firm capacity on a year by year basis for ICP s full 45 TJ/d requirement through Expected Core Market Unit Cost Impact Based on the principles and assumptions described above, Figures 8-3 and 8-4 illustrate the expected average delivery cost (excluding cost of gas) to serve core market customers under the two allocation approaches for the LNG Storage Portfolio compared with the P&C Portfolio. In Figures 8.3 through 8.6, the average delivery cost (excluding cost of gas) for the P&C Portfolio is plotted as the line graph, and the bars represent the LNG Storage Portfolio. Figure 8.3 assumes the Net LNG Storage Facility costs are allocated to all customers (Approach 1). Figure 8.4 assumes those net costs are allocated to core market customers only (Approach 2). Both Figures 8.3 and 8.4 present the allocated unit delivery costs for the core market in $/GJ with the bars representing the LNG Storage Portfolio and the line representing the P&C Portfolio. The results show similar allocated costs to core customers for both portfolios over the near term to 2015; however over the longer term to 2031 the LNG Storage Portfolio shows increasingly lower allocated costs than the P&C Portfolio because of the ability to avoid add compression facilities to meet incremental demands. Page 117

124 Mt. Hayes LNG Storage Facility Figure Core Market Average Delivery Cost (Excluding Cost of Gas) Approach # Unit Delivery Cost ($/GJ) Allocated Unit Delivery Cost LNG Allocated Unit Delivery Cost P&C Figure Core Market Average Delivery Cost (Excluding cost of Gas) Approach # Unit Delivery Cost ($/GJ) Allocated Unit Delivery Cost LNG Allocated Unit Delivery Cost P&C Page 118

125 Mt. Hayes LNG Storage Facility Firm Transportation Service The forecast average cost for firm transportation service customers is illustrated in the Figures 8-5 and 8-6 employing the two allocation approaches described above. These figures present the forecast allocated unit costs in $/GJ/day for firm transportation customers with the bars representing the LNG Storage Portfolio and the line representing the P&C Portfolio. Figure 8-5 assumes the Net LNG Storage Facility costs are allocated to all customers and transmission system costs are allocated based on core peak demand plus transportation contract demand (Approach 1). Figure 8-6 assumes the Net LNG Storage Facility costs are allocated to core market customers only (Approach 2). The results again show that the LNG Storage Portfolio will allow TGVI to offer firm transportation services at comparable or lower allocated cost over time, than the P&C Portfolio. As is the case for the core market customers, this benefit is expected to increase if other loads are added to the TGVI system. Figure Firm Transportation Service Average Cost Approach # Unit Delivery Cost ($/GJ) Allocated Unit Delivery Cost LNG Allocated Unit Delivery Cost P&C Page 119

126 Mt. Hayes LNG Storage Facility Figure 8-6 Firm Transportation Service Average Cost Approach # Unit Delivery Cost ($/GJ) Allocated Unit Delivery Cost LNG Allocated Unit Delivery Cost P&C Levelized Cost Comparison The allocated delivery costs (i.e. excluding the cost of gas) for core market and transportation customers are shown in Figures 8-3 through 8-6 an annual basis. To facilitate a better comparison of the results of these alternative portfolio and allocation approaches, Table 8-11 below shows the levelized allocated costs (excluding gas costs) for core market and transportation customers using 15- and 25-year evaluation periods to 2021 and 2031 respectively. A sensitivity scenario is also provided showing the impact in the LNG Storage Portfolio of providing firm contract demand of 45 TJ/D to BC Hydro for ICP through After 2018 the ICP contract demand is reduced by 50% as additional compression facilities would be required at that point to provide the full contract demand. The capability of providing firm capacity to BC Hydro until 2018 is applicable only to the LNG Storage Portfolio and represents a potential increased benefit for TGVI s customers provided by the Project. Page 120

127 Mt. Hayes LNG Storage Facility Table 8-11 Comparison of Levelized Allocated Average Delivery Costs Excluding Gas Costs Baseline Scenario Levelized Allocated Cost ($/GJ) LNG Approach 1 LNG Approach 2 Pipe & Compression Levelized Allocated Cost ($/GJ) LNG Approach 1 LNG Approach 2 Pipe & Compression Core Market Firm Transport Impact of Firm Service to ICP to 2018 Core Market Firm Transport Conclusions and Observations: The results show that the allocation of the LNG Storage Facility costs either to the core market only or to all customers provide benefits for both the core market and transportation customers. The levelized allocated unit costs for the LNG Storage Portfolio are lower under either allocation approach and for both evaluation periods than the levelized allocated unit costs for the P&C Portfolio; and There is the possibility of further benefits being achieved from the LNG Storage facility if service to ICP is maintained at the full contract demand as long as system capacity allows. Additional firm transportation revenues from ICP have the potential to further lower the allocated unit costs for core market and transportation customers. Page 121

128 Mt. Hayes LNG Storage Facility 9. CONCLUSIONS This Application requests approval from the Commission for: TGVI to construct and operate the 1.5 Bcf Mt. Hayes LNG Storage Facility and recover costs based on requested ROE treatment and adjusted depreciation rate; TGVI to construct and operate System Facilities which include transmission system reverse flow valves and transmission pipeline laterals required for TGVI to benefit from the LNG Storage Facility; and TGVI and TGI to enter into a long term Storage and Delivery Services Agreement. The target in-service date for the proposed facilities is April 1, 2011, and the estimated direct capital costs for the LNG Storage Facility and System Facilities are as follows: Table 9-1 Capital Costs Forecast Probability As Spent $Millions P10 P50 P90 LNG Storage Facility System Facilities Total Direct Costs TGVI will proceed with pre-construction development activities required to confirm current cost estimates and schedule to support project initiation by 1 December TGVI is requesting approval to proceed with the Project if at that time the cost estimates continue to fall within the current P10 to P90 forecast. This Application also seeks approval for TGVI to recover the costs associated with the pre-construction development activities if the Project does not proceed at the conclusion of the pre-construction phase due to unforeseen cost escalation. This Application is consistent with the conclusions and actions set out in both the TGVI and TGI 2006 Resource Plans. The analyses presented in this Application demonstrate that the construction, ownership and operation of an LNG Storage Facility near Mt. Hayes on Vancouver Page 122

129 Mt. Hayes LNG Storage Facility Island under arrangements presented herein, is in the best interest of TGVI, TGI and their customers. Among the major benefits of the LNG Storage Facility will be the ability of both utilities to reduce dependence on services that are, or would otherwise be, contracted at facilities located outside their service areas, and provide higher reliability and security of supply through access to onsystem storage resources. The approvals sought in this Application will allow TGVI to avoid costs associated with pipe and compression infrastructure that would otherwise be required to meet the growing core customer demand in the TGVI service area. The LNG Storage Facility will also allow TGI to significantly defer future transmission system expansion that might be required, depending on BC Hydro s future plans for Burrard Thermal. The pricing structure being sought through the proposed contractual arrangements reduces costs to TGVI in the early years of facility operation, thereby benefiting TGVI and its customers by offering the least cost option for meeting growth in core customer demand on Vancouver Island and the Sunshine Coast. In addition to providing a cost effective long term solution for core market customers, the proposed LNG Storage Facility will also allow TGI and TGVI to manage the uncertainty associated with serving future demand from electrical generating facilities in each service area. Page 123

130 GLOSSARY Annual demand the cumulative daily demand for natural gas over an entire year. Avoided cost the incremental cost that a utility would incur to purchase gas supplies and capacity equivalent to that saved under a demand side management program. Components of avoided cost could include energy, capacity, storage, transmission and distribution. BCUC (British Columbia Utilities Commission). The BCUC is the provincial body regulating utilities in British Columbia. Bcf Billion cubic feet CFT (Call for Tenders) in this document, CFT refers to a specific Call for Tenders that BC Hydro has initiated as part of a review of electricity supply options for Vancouver Island. Cogeneration in this document, cogeneration refers to the generation of both electrical and thermal power simultaneously by utilizing the waste heat from a gas turbine to generate steam. Commission see BCUC. Compression, compressor station the application of increased pressure to a natural gas pipe system to create gas flow. Higher levels of compression can be applied to increase the carrying and storage capacity of the pipe. Increased pressure is applied through a compressor station constructed along the pipeline. Core, core customers, core market residential, commercial and small industrial customers that have gas delivered to their home or business (bundles sales). Terasen Gas purchases natural gas and delivers it to the customer in a bundled sales rate. Core Market customers typically use a significant portion of their gas requirements for heating applications, resulting in weather sensitive demand. CPCN (Certificate of Public Convenience and Necessity) a certificate obtained from the British Columbia Utilities Commission under Section 45 of the Utilities Commission Act for the construction and/or operation of a public utility plant or system, or an extension of either, that is required, or will be required, for public convenience and necessity. CPI Consumer Price Index CPR (Conservation Potential Review) a study completed to identify opportunities for energy savings across gas and electrical energy delivery infrastructures and improvements to overall energy utilization efficiency. CSA Canadian Standards Association CTS Terasen Gas Inc. s Coastal Transmission System

131 CVRD Cowichan Valley Regional District Daily demand the amount of natural gas consumed by Terasen Gas customers throughout each day of the year. Demand forecast a prediction of the demand for natural gas into the future for a given period and under a specified set of expected future conditions. Demand side, Demand side programs defined as any utility activity that modifies or influences the way in which customers utilize energy services. From Terasen Gas perspective, the primary objectives of demand side programs are to increase the overall economic efficiency of the energy services it provides to customers and maintain the competitive position of natural gas relative to other energy sources. Design-day demand, design hour demand (see also: peak day or peak hour demand) the maximum expected amount of gas in any one day (with respect to TGVI) or hour (with respect to TGI, Lower Mainland) required by customers on the TGVI or TGI systems. Since Core customers' demand is primarily weather dependent, design-day or design-hour demand is forecasted based upon a statistical approach called Extreme Value Analysis, which provides an estimate of the coldest day weather event expected with a 1 in 20 year return period. For transportation customers, the design-day is equivalent to the firm contract demand. (See also: peak day). EPA - Electricity Purchase Agreement. EPC Engineering, procurement and construction. ESR Environmental and Social Review Report GJ Gigajoule A measure of energy of natural gas - one billion joules. One joule of energy is equivalent to the heat needed to raise the temperature of one gram (g) of water by one degree Celsius (ºC) at standard pressure ( kpa) and standard temperature (15ºC). GLJ - GLJ Petroleum Consultants Ltd. is a private petroleum industry consultancy serving clients who require independent advice relating to the petroleum industry, including the preparation of natural gas and oil price forecasts on a quarterly basis. ha - hectare Heating degree day A measure of the coldness of the weather experienced. The number of heating degree days for a given day is calculated based on the extent to which the daily mean temperature falls below a reference temperature, 18 degrees Celsius. Huntingdon/Sumas gas flow regulating stations on either side of the British Columbia / US border through which much of the regional gas supply is traded.

132 I-5 Corridor the natural gas regional market area served by infrastructure located along Interstate 5 in the north western US. The I 5 Corridor includes B.C. s Lower Mainland and Vancouver Island, Western Washington and Western Oregon. ICP (Island Cogeneration Plant) A cogeneration plant located at Elk Falls, Campbell River supplying electricity and thermal energy on Vancouver Island. IEP (Integrated Electricity Plan) BC Hydro s 2006 Integrated Resource Plan. ILM Interior to Lower Mainland electrical transmission capacity improvement project proposed by British Columbia Transmission Corporation. JP (Jackson Prairie) Storage downstream storage resources. JV (Joint Venture) see Vancouver Island Gas Joint Venture. LNG (Liquefied natural gas) natural gas cooled to -160 o C at atmospheric pressure condenses to a liquid. One volume of this liquid is formed from approximately 620 volumes of natural gas. The clear liquid weighs about half as much as the same volume of water. LNG Import Terminals - Terminals that receive liquefied natural gas that is shipped in large tankers from overseas. LNG Import terminals are considered base load supply resources not peaking resources. LNG Storage Facility in this Application, refers specifically to an LNG storage tank and infrastructure located inside the site fence, including liquefaction and sendout infrastructure. Load the total amount of gas demanded by all customers at a given point in time. Load duration, load duration curve a graphical representation of the daily loads over a period of time, typically one year, sorted from highest load to lowest load. Looping the twinning of sections of gas transmission pipeline to improve flow characteristics within the service area. LTAP - BC Hydro s Long Term Acquisition Plan which identifies the preferred resources, both supply and demand, which the utility intends to acquire over the long-term to serve the growing demand for electricity in BC. Market Area Storage natural gas storage facilities and services that are located near the consuming market. It is generally characterized by high deliverability and low capacity. MEMPR - Ministry of Energy and Mines and Petroleum Resources. MMcfd - 1 million cubic feet per day.

133 MOP - maximum operating pressure. MOU Memorandum of Understanding NWGA - NorthWest Gas Association is a trade organization of the Pacific Northwest natural gas industry. Its members include six natural gas utilities, including Terasen Gas, serving communities in Idaho, Oregon, Washington and British Columbia, and three interstate pipelines that move natural gas from supply basins into and through the region. NWP Northwest Pipeline. Off-system Storage natural gas storage facilities that are located outside of TGVI or TGI service areas. On-system Storage Natural gas storage facilities and services attached to the natural gas transmission or distribution systems owned and operated by TGI or TGVI. OGC British Columbia Oil and Gas Commission. Peak day / peak hour demand see Design day / hour demand P90, P50, P10 Cost Estimate The probability, based on a statistical distribution, that actual costs will be at or below a given cost estimate value. For example, a P90 cost estimate of $100,000 has a 90% probability that actual costs will be at or below the stated value of $100,000 for that estimate. PJ Petajoule equal to 1,000 Terajoules or 10 6 Gigajoules. Portfolio, resource resource portfolio refers to selected supply and / or demand resources that, when grouped together, can meet the future demand and supply needs of a service area. Portfolio, gas supply gas supply portfolio refers to a combination of different upstream gas supply resources that can be purchased or contracted by TGI and/or TGVI to ensure that gas supply and delivery to the TGI and TGVI systems meets customer demand throughout the planning period. psig pounds per square inch gauge. Resources demand side and supply side means available to meet forecasted energy needs. Examples of supply side resources within the context of the Resource Planning process are Pipeline Looping, Compression and Storage. Examples of demand side resources are industrial customer curtailment and load management programs for residential and commercial customers. ROW Right-of-way. Tcf Trillion cubic feet. TJ Terajoule equal to 1000 Gigajoules

134 TGI Terasen Gas Inc. a subsidiary of Terasen Inc. TGVI Terasen Gas (Vancouver Island) Inc. a subsidiary of Terasen Inc. TGVI Transmission System the gas transmission pipeline and related facilities owned and operated by TGVI extending from a point of connection with the Terasen Gas Inc. system in Coquitlam, British Columbia to various delivery points on the Sunshine Coast and Vancouver Island. Tilbury facility / Tilbury LNG Storage Facility an existing, on-system LNG storage facility located in the Tilbury industrial area in Delta, BC owned and operation by TGI. VIGJV (Vancouver Island Gas Joint Venture) a Vancouver Island Gas Joint Venture, a joint venture of seven pulp & paper mills who contract for transportation services as a single entity. The joint venture is comprised of the following corporations and limited partnerships: Howe Sound Pulp and Paper Limited Partnership, Catalyst Paper Corporation, Pope & Talbot and Western Pulp Limited.

135 Appendix A LNG PROJECT INFORMATION

136 Appendix A Mt. Hayes LNG Storage Project APPENDIX A Table of Contents 1.0 Projects Description LNG Storage Facility Project LNG Storage Facility Project Development Mt. Hayes LNG Storage Facility Site LNG Facility Description Public Consultation and Siting Site Size Requirements System Facilities Project Pipelines and Measurement/Odourization Station Rights-of-Way Reverse Flow Transmission Modifications Environmental Assessment Other Approvals Design, Construction and Operations Site Rezoning and Land Purchase Private Land Rights Crown Land Rights Access Road Use Safety and Integrity LNG Storage Facility Integrity LNG Storage Facility Integrity Methodology LNG Storage Facility Hazards LNG Storage Facility Fire Protection Systems Construction Risk to the Forest Operation Facility Risk to the Forest Operation Fire Risk to the Facility Other LNG Storage Facility Safety Issues Pipeline Integrity Seismicity Seismic Design and Mitigation Facility Security Emergency Response Plan (ERP) Local Notification and Involvement Public Consultation Public Consultation Program First Nations Socio Economic Assessment Project Management, Engineering and Construction Liquefied Natural Gas ( LNG ) What is It?...22 Appendix A LNG Storage Facility Project Information Page i

137 Appendix A Mt. Hayes LNG Storage Project 7.2 Usefulness Composition Safety Temperature Effects...23 Appendix A LNG Storage Facility Project Information Page ii

138 Appendix A Mt. Hayes LNG Storage Project APPENDIX A TGVI PROJECT INFORMATION Appendix A provides project information for the LNG Storage Facility and the System Facilities projects that is partially based on the Bcf facility information that was developed by TGVI and supplements the updated information in Sections 3 and 4 of this Application. The 2004 project information was conditionally approved by the Commission in the 2005 Decision. Project description, environmental assessment, site selection, public consultation, safety and integrity, approvals and project execution remain essentially the same for the current Application other than an increase in the LNG Facility size up to 1.5 from 1.0 Bcf. In this current Application, TGVI is proposing to construct a new 1.5 Bcf LNG storage facility at a location referred to as Mt. Hayes located in the Cowichan Valley Regional District near Ladysmith on Vancouver Island., an electrical supply, two pipeline laterals and transmission system improvements. The larger facility size and high level of industrial construction activity have resulted in higher capital costs, and resultant socio-economic benefits. 1.0 PROJECTS DESCRIPTION 1.1 LNG STORAGE FACILITY PROJECT The project work includes a 1.5 Bcf LNG storage facility to be constructed at a location referred to as Mt. Hayes near Ladysmith on Vancouver Island and an electrical substation and electrical power line from the BC Hydro transmission system to the LNG Storage Facility site LNG Storage Facility Project Development In addition to the TGVI 1.0 Bcf LNG Storage Facility project development work, TGVI has incorporated the experience and expertise of TGI in operating, maintaining and upgrading the Tilbury LNG Facility which has been in service since December Project development has also incorporated information provided by major LNG Facility construction contractors and consultants as well as TGVI and TGI's extensive pipeline systems construction and project management experience Mt. Hayes LNG Storage Facility Site A site has been selected at a location referred to as Mt. Hayes in the CVRD, approximately 6 km NW of Ladysmith. Rezoning of the site for an LNG Facility use was approved by the CVRD on May 26, The property, owned by Island Timberlands (previously Weyerhaeuser), has been optioned for purchase upon full Project approval LNG Facility Description The LNG Storage Facility is being designed with capacities as outlined in the following table with 200 days of liquefaction to fill the tank if completely utilized and the ability to send-out at daily rates up to 10% of the storage capacity. Appendix A LNG Storage Facility Project Information Page 1

139 Appendix A Mt. Hayes LNG Storage Project Figure Bcf FACILITY CAPACITY TABLE Design Capacity Volume/Rate Energy/Rate Storage 1.5 Bcf 1,620,000 GJ Liquefaction Rate 7.5 MMcfd 8,100 GJ/d Max. Send-out Rate 150 MMcfd 162,000 GJ/d An LNG storage facility consists of six major elements, each offering design options and alternative operational systems that need to be evaluated in the final design phase. The components are: feed gas purification; liquefaction; LNG storage; send-out; facility ancillary equipment and facilities; utility connections and connection to pipelines Previously, an Engineering, procurement and construction LNG contractor had been engaged to provide a front end engineering and design ( FEED ) study and firm price for a 1.0 Bcf facility in early 2005 in anticipation of approval of the previous application. The EPC contractor provided the facility design to the level required to provide a firm price for a turnkey facility, and had resolved some of the design options in each of the major elements. The results of that work and additional review with the EPC contractor on the 1.5 Bcf facility are reflected in the following commentary, but may be subject to review with the development of the detailed design of the 1.5 Bcf facility size as proposed in this Application Feed Gas Purification Liquefaction of natural gas requires process temperatures to -162 o C (-260 o F). Any impurities such as water, carbon dioxide, heavy hydrocarbons and odorant in the feed gas must be removed to prevent process equipment from fouling or plugging by the freezing of these impurities. A variety of purification systems are available with selection dependent upon the feed gas composition. Due to the expected carbon dioxide and water content of the feed gas, TGVI anticipates using either a molecular sieve or amine purification system. The impurities removed by the sieve are returned back to the gas transmission system to be mingled with the natural gas flowing downstream while those removed by an amine system would be removed and disposed of in an environmentally friendly manner Liquefaction Following the purification process, the clean gas stream is sent to a refrigeration unit where the gas is cooled and condensed to its liquid state for storage. The most commonly used liquefiers make use of one of the following designs: cascade cycle; mixed refrigerant cycle; expander cycle. The LNG Storage Facility will incorporate a mixed refrigerant cycle liquefier (similar to the process used at Tilbury) as it has a lower capital and operating cost, and is the predominant standard at similar LNG peak-shaving facilities throughout North America. This process Appendix A LNG Storage Facility Project Information Page 2

140 Appendix A Mt. Hayes LNG Storage Project requires a compressor of approximately 3.4 MW (4,500 hp), which will be electrically driven. A net liquefaction rate of 7.5 MMcfd will be specified LNG Storage After liquefaction, the LNG is stored in a single containment, double walled, insulated tank. The internal tank pressure is limited to near atmospheric pressure (2 psig) while keeping the LNG at -162 o C. A thermal insulation system, consisting of expanded perlite and foam glass, separates the inner and outer shells. The inner shell, which is in direct contact with the LNG, is made of 9% nickel alloy steel. The outer shell, designed to hold the insulation and act as a vapour holding vessel, is made of carbon steel. The tank height is expected to be in the order of 45 m and the diameter in the order of 62 m. The 1.5 Bcf (69,600 m 3 actual volume) net useable volume tank will be surrounded by earthen dike impoundment constructed from locally sourced materials including shot rock made available on site from required site grading activities. The impoundment (earthen dike), capable of holding the total volume of the LNG tank, will be constructed according to current LNG codes and standards. The height and diameter of the dike will be determined in the final design phase, however, the preliminary design includes a dike in the order of 5 m to 7 m in height. Figure 1-2 provides a conceptual image of an LNG Facility with an earthen dike. Figure 1-2 Conceptual Single containment storage tank with secondary containment earthen dike Appendix A LNG Storage Facility Project Information Page 3

141 Appendix A Mt. Hayes LNG Storage Project Send-out A send-out system performs the following functions: pumping LNG from storage to transmission line pressure; vapourizing LNG by heating the LNG to return it to vapour; controlling natural gas flow and temperature. The total send-out capacity is separated into two independent send-out systems (trains) with interconnections, with each system capable of sending out 75 MMcfd. This will provide redundancy for failure of any send-out train or component thereof at normal send-out rates, it will support send-out rates as low as approximately 15 MMcfd (20% of the smallest single train capacity), and will provide total send-out capacity of 150 MMcfd Ancillary Equipment and Facilities In addition to the basic functions of liquefying, storing and send-out of natural gas, other ancillary equipment systems are required. These systems include: Boil-off compressors to compress gas which evaporates inside the tank enabling delivery of the gas to the main transmission system flowing downstream. Boil-off will be specified as a maximum of 0.05% of tank volume per day; Security systems including such items as fencing, lighting, closed circuit cameras ( CCTV ) and card locked gates as well as perimeter motion detectors; Backup electrical power generation to ensure sufficient power to control the facility and send-out (but not to liquefy) in the event of loss of supply from the electric utility. The facility will include a diesel powered generator due to its lower capital cost; Fire protection and control systems, including water monitors at strategic locations within the facility fed from an onsite water storage tank, replenished from a pond to be constructed to collect runoff water; Dry chemical fire extinguishers; Independent monitoring and safety shutdown controls, including remote control and computer assisted control and shut down systems to isolate and shut down as required Powerline and Communications TGVI will construct and own a 25 kv electric transmission line and substation which will be designed to applicable codes and electric utility standards. Electrical power is required for general facility utilities and to supply the electric motors driving the liquefaction compressor, boil-off compressor and send-out pumps. A fibre optics communications line to serve the LNG Storage Facility will be installed on the electrical power poles Public Consultation and Siting The siting of the LNG Storage Facility considered the requirement to receive supply and send out into the TGVI System. In addition, the selection of the location of the facility also considered operational flexibility and capacity benefits to the TGVI transmission system and generally is optimal when located closest to major peak loads. Studies were initiated by TGVI, the 2004 proponent of the LNG Facility in the previous application, to determine whether suitable areas within the TGVI service area, and eventually a site, could be identified to locate the facility. The area chosen for the study included a ten (10) km wide band centred on the TGVI main transmission pipeline on Vancouver Island. Appendix A LNG Storage Facility Project Information Page 4

142 Appendix A Mt. Hayes LNG Storage Project Approximately 25 Candidate Areas were identified that met siting criteria. Following this step, a helicopter supported field reconnaissance was undertaken to gain further understanding of the characteristics of the Candidate Areas in regard to terrain and geotechnical conditions as well as location within the viewshed of populated areas. Based on this study and further pipeline system hydraulic analyses, three potential sites ( Candidate Sites ) were selected for further study. These three sites were: West of Mt. Hayes; West of Mt. Prevost; Duke Point Industrial Area. Meetings and presentations were held with local governments (municipal and regional) and First Nations to outline the rationale for the project and the site selection process. Open Houses were held in early December 2003 in Duncan and Cedar to introduce the public to the project and the characteristics of LNG, to answer any questions brought forward, and to solicit opinions on the Candidate Sites. Based on further analyses of the three Candidate Sites and the information gained from the public at the initial Open Houses, the site west of Mt. Hayes was chosen as the preferred site for the facility. The Mt. Hayes site was chosen because: The site offers good foundation and geotechnical conditions; The site is well hidden from the viewshed to the east, where people live, and is isolated from land uses other than commercial forestry; Most of the facility site has been clearcut logged; Potential environment and archaeological values were considered minor; The pipeline connection to the TGVI transmission system does not significantly impact property owners and does not cross any fish-bearing streams; There is existing access to the site; Site related construction and operating costs are reasonable; The public who attended the Open Houses in December did not voice a concern about the Mt. Hayes location. Following the decision to select the site west of Mt. Hayes for the LNG Facility, TGVI held another Open House on January 14, 2004, at the North Oyster School on Cedar Road. The purpose of this meeting was to fully inform the public about the decision and to further respond to questions raised by the public as well as to provide those members of the public who did not attend the earlier Open Houses, an opportunity to learn about the project. The general view of the public who attended the Open House was that TGVI had made an appropriate decision in selecting Mt. Hayes as the preferred site and that the construction and operation of an LNG Facility at the location was generally acceptable. On February 2, 2004, TGVI filed an application for rezoning with the CVRD for a portion of a property owned by Island Timberlands (formerly owned by Weyerhaeuser). Following a Town Hall meeting and Public hearing, the application for rezoning was approved by the CVRD on May 26, Appendix A LNG Storage Facility Project Information Page 5

143 Appendix A Mt. Hayes LNG Storage Project The following Figure 1-3 illustrates the general location of the proposed LNG Storage Facility. Figure 1-3 General Location of proposed LNG Storage Facility Site Size Requirements A block of property at the Mt. Hayes site has been optioned from the owner, Island Timberlands (previously Weyerhaeuser). The 142 ha (350 acre) site is shown on the following Figure 1-4. The inset in Figure 1-4 provides an outline of the Island Timberlands property (142 ha), the area within the property that has been rezoned (42 ha), and the area of Crown land outside the property (20 ha) to the west, which TGVI seeks to control to ensure thermal radiation setback is maintained as per the CSA code. The option agreement with Island Timberlands anticipates a future subdivision of the 142 ha lands to allow TGVI to return to Island Timberlands the portions of the property not required by TGVI as operational area or buffer zone to enable Island Timberlands to maintain ownership of and resume forestry operations on that portion of the property. TGVI anticipates retaining an additional 20 ha of property to the east of the rezoned area, to contain the required buffer zone, and returning the remaining 80 ha to Island Timberlands. Appendix A LNG Storage Facility Project Information Page 6

144 Appendix A Mt. Hayes LNG Storage Project Within the 42 ha rezoned area, the physical facility boundaries will encompass approximately 20 ha. The location of the proposed powerline rights-of-way and the access road are also noted in Figure 1-4. Each of these components is described below. Appendix A LNG Storage Facility Project Information Page 7

145 Appendix A Mt. Hayes LNG Storage Project Figure 1-4 LNG Site and Utility Connections Locations Appendix A LNG Storage Facility Project Information Page 8

146 Appendix A Mt. Hayes LNG Storage Project Buffer Zone The CSA Z276 Code requires a series of thermal radiation setback zones to surround an LNG facility. The size of the setbacks is determined in accordance with the code based on the dimensions of the impoundment which surrounds the LNG tank. These setback zones are required to ensure that the public gathering places and public buildings, in existence at the time of facility siting, are located a specified distance from the LNG facility to manage potential impact should a fire result within the impoundment area. The design-build contractor provided design work indicating the buffer zones could extend to approximately 400 m from the centre of the impoundment area for a 1.0 Bcf facility. A portion of such an extended buffer area extends beyond the Island Timberlands property onto Crown land to the west. TGVI intends to own or control all of the area required to maintain the code setback distances based on the actual facility design to ensure public use or development will not encroach upon the facility buffer over time. TGVI has previously successfully applied to the OGC for a lease for approximately 20 ha to extend control over Crown land adjacent to the west of the Island Timberlands property as shown in Figure 1-4. The OGC permits expired in April 2007 and TGVI is confident of renewal of the permits Rights-of-Way The approximately 5 km long, 7 m wide TGVI 25kW electric transmission line right-of-way and the 18 m wide TGVI pipelines right-of-way are intended to be parallel rights-of-way adjacent to the existing access road into the facility site. The access road will be relocated by TGVI over a portion of its length to avoid a gravel extraction site and to remove some steep segments with tight turns and will be upgraded from its existing condition. The rights-of-way pass through private and Crown land requiring easement from both private landowners and the Crown. TGVI has previously successfully made application to the OGC for the required Crown land easements for the pipeline and powerline and the access road improvements. The OGC permits which expire in April 2007 are in the process of being renewed by TGVI. The general location of the road and rights-of-way are indicated in Figure SYSTEM FACILITIES PROJECT The System Facilities Project scope of work includes two pipeline laterals and a measurement/odourization facility to connect the LNG Storage Facility to the existing TGVI transmission pipeline, and minor modifications to the TGVI transmission system to accommodate reverse flow Pipelines and Measurement/Odourization Station The LNG Storage Facility must be connected to the transmission system with two pipelines. The pipelines provide connection to the TGVI transmission system for the supply of feed gas and also for the return of natural gas (the impurities from the purification process, tail gas) during liquefaction. The two pipelines required during liquefaction then serve to return natural gas to the transmission system during vapourization and send-out. TGVI anticipates constructing 2 pipelines (8 and 10 ) approximately 5 km in length to connect the TGVI Facility to the transmission system. Custody transfer measurement of gas into and out of the LNG Facility is required and gas in the TGVI system must be odourized. The TGVI measurement and odourization station, adjacent to the LNG Facility, will provide these essential services. Appendix A LNG Storage Facility Project Information Page 9

147 Appendix A Mt. Hayes LNG Storage Project Rights-of-Way An approximately 5 km long, 18 m wide pipeline right-of-way is required for the pipeline laterals. The 18 m wide right-of-way and the proposed 7 m wide 25kW electric transmission line right-ofway and are intended to be parallel rights-of-way adjacent to the existing access road into the facility site. The rights-of-way pass through private and Crown land requiring easements from both private landowners and the Crown. TGVI has previously successfully made application to the OGC for the required Crown land easements for the pipelines. The OGC permits expired in April 2007 and TGVI is confident in the success of renewal of the approvals. The general location of the right-of-way is indicated in Figure 1-4 of Appendix A Reverse Flow Transmission Modifications In addition to the connecting pipelines and the measurement/odourization facility as identified in the 2004 application, TGVI will require minor modifications to its existing transmission system to allow flow in the reverse direction during the maximum sendout from the LNG Facility. There will be a requirement to flow gas back to the TGI system from the TGVI system (with a 1.5 Bcf facility with a 150 MMcfd sendout capacity) at times when the required combined storage service sendout of TGVI from the LNG Facility is greater than the TGVI system load. The existing check valves on the downstream side of each of the two marine crossings on the transmission system will be replaced with actuated valves to allow the reverse flow direction. The actuated valves will provide the same security of reverse flow blockage in the event of an upstream pipeline failure during normal flow operation of the system. The Texada Compressor Station (V-4) must be modified to accommodate reverse flow operation in order to move the reverse flow required during peak LNG sendout at non-peak TGVI system demand. These modifications will require the installation of a second set of side valves and associated piping and control system changes. The TGI/TGVI custody transfer station located at Eagle Mountain, Coquitlam, must be modified to accommodate the reverse flow operation to allow flow from the TGVI transmission system into the TGI transmission system. The modification will include flow measurement, pressure control and overpressure protection. 2.0 ENVIRONMENTAL ASSESSMENT TGVI completed an Environmental and Social Review ( ESR ) for the Project in 2004, based on a 1.5 Bcf facility. The work scope included in the ESR included the LNG facility, the electrical transmission line, the pipeline laterals and measurement/odourization station and the road upgrades. The ESR formed a significant component of the public consultation program in support of the site rezoning application to the CVRD. The ESR concluded that "With the successful implementation of the mitigation measures recommended in this report, no residual post-mitigation significant impacts are expected to occur." A summary of the "Project Impact Significance" results of the ESR are repeated here as Table 2-1. The 2005 Decision stated in Section 7.7 Environmental issues at the proposed Mount Hayes site were considered in some depth in the ESR and with two exceptions, no significant environmental impact form the proposed facility was discovered. The two exceptions relate to water and aquatic systems and vegetation, both of which can be neutralized with mitigation efforts recommended in the report. Appendix A LNG Storage Facility Project Information Page 10

148 Appendix A Mt. Hayes LNG Storage Project TGVI confirmed in 2004 that an application under the BC Environmental Assessment Act ("BCEAA") is not required for the 1.5 Bcf LNG Facility as the project falls below the threshold for energy storage projects. TGVI has reconfirmed with the B.C. Environmental Assessment Office that the project does not require application to their department. A Canadian Environmental Assessment Act ("CEAA") assessment is also not required as no CEAA triggers were found during the site assessment. System Facilities work beyond the scope of the 2004 ESR includes the modifications to the TGVI transmission system to allow reverse flow direction. This work, including check valve replacements, Texada compressor station modifications and Eagle Mountain custody transfer modifications, are within the compounds of existing TGVI facilities and will have no significant environmental impacts. Appendix A LNG Storage Facility Project Information Page 11

149 Appendix A Mt. Hayes LNG Storage Project Table 2-1 Environmental Assessment Summary of Project Impact Significance Impact Topic Impact Significance* Unmitigated Mitigated PHYSICAL ENVIRONMENT Geology and Soils N N Natural Hazards N N Water and Aquatic Systems S N Air Quality and Climate N N BIOLOGICAL ENVIRONMENT Vegetation S N Wildlife N N Fish and Fish Habitat N N H UMAN ENVIRONMENT Urban and Rural Settlement N N Transportation N N Forestry N N Recreation N N Archaeology N N Aesthetics N N Noise N N Domestic Water Supply N N Economic Effects B B F ACILITY AND PUBLIC SAFETY Forest Fires N/A N Seismicity N/A N Facility Integrity N/A N Pipeline Integrity N/A N LNG Transportation N/A N Site Security N/A N * C UMULATIVE EFFECTS N = S = B = N/A = U = Construction N N Operation N N Not Significant Significant Beneficial Not applicable; project design and construction standards incorporate these requirements Unknown due to lack of information Appendix A LNG Storage Facility Project Information Page 12

150 Appendix A Mt. Hayes LNG Storage Project 3.0 OTHER APPROVALS 3.1 DESIGN, CONSTRUCTION AND OPERATIONS The design, construction and operation of LNG storage facilities are regulated by the OGC. The LNG Storage Facility and System Facilities projects will conform to the most recent edition of the standards, codes and regulations in Table 3-1 and others as applicable. Table 3-1 Primary Codes and Regulations Code Edition Description B.C. Pipeline Act and Pipeline Regulation 2004 Provincial Regulation of the Design, Construction and Operation of Pipeline Facilities CSA Z LNG Production, Storage, and Handling CSA Z Oil and Gas Pipeline Systems NBC, BCBC & CVRD Req ts 2005 National Building Code of Canada 2005 C.E.C Canadian Electrical Code Part 1, most recent Edition API 620 App. Q 10th Design and Construction of Large, Welded, Low Pressure Storage Tanks CSA B Boiler, Pressure Vessel, and Pressure Piping Code CAN/CSA A (R2000) 2004 Design of Concrete Structures Terasen Standards As Applicable Standards for Equipment, Materials, Construction Procedures, Inspection, Testing, Security and Safety The powerline will be designed and constructed to electric utility engineering and construction standards. The design and construction of the electrical substation will conform to the Canadian Electrical Code CSA SITE REZONING AND LAND PURCHASE The CVRD approved for rezoning a portion of the property optioned previously by TGVI (owned by Island Timberlands) to allow construction and operation of an LNG Storage Facility. The CVRD gave approval to that rezoning application on May 26, A copy of the approval bylaw which allows for two 1.5 Bcf LNG tanks was included in Appendix 7 of TGVI s 2004 Application for a CPCN for the LNG Storage project. The property was optioned by means of a two-year option agreement which has subsequently been extended until July 31, PRIVATE LAND RIGHTS The LNG Facility is to be located entirely on land which will be owned by TGVI and will require no private easements. The connecting power line, pipeline laterals and road will cross land primarily owned by Island Timberlands, TimberWest Forest Limited ("TimberWest") and the Crown. Only one other private land holding will be impacted. All impacted land owners are aware of TGVI s requirements and no difficulties are anticipated in securing any of the private land easements. Appendix A LNG Storage Facility Project Information Page 13

151 Appendix A Mt. Hayes LNG Storage Project 3.4 CROWN LAND RIGHTS Crown land easements will be required for portions of the power line and pipeline laterals and in addition, TGVI proposes a lease over a segment of Crown land immediately adjacent to the west of the LNG Facility property. This crown lease will enable TGVI to maintain control over lands which fall within the code required thermal setback buffers. Approval for the Crown land leases was received in 2005, which expired in April 2007, and TGVI is confident in the successful renewal of the approvals. 3.5 ACCESS ROAD USE TGVI requires the use of existing access roads owned and operated by TimberWest to access the Mt. Hayes Site. The access road(s) will need to be relocated in some sections and improved and TGVI has a road use agreement with TimberWest to cover improvements and road use to ensure access to the LNG Storage Facility is acceptable. 4.0 SAFETY AND INTEGRITY 4.1 LNG STORAGE FACILITY INTEGRITY LNG has been safely handled for many years throughout the world and has an excellent safety record. Over the last 50 years, there have been no impacts to any member of the public as a result of any incidents arising from LNG operations of the kind envisioned herein. Worldwide, there are currently about 240 peak shaving LNG storage facilities 1 (three in Canada), some operating since the mid-1960s. The U.S.A. has the largest number of LNG facilities in the world with 113 active spread across the U.S.A., with the highest concentration of facilities in the north-eastern region. 4.2 LNG STORAGE FACILITY INTEGRITY METHODOLOGY LNG Storage Facility integrity is addressed through a combination of regulatory compliance and industry standards, resulting in multiple layers of safety in design and operation of the proposed facility: The first layer is provided through LNG specific design of the storage and piping systems, employing suitable materials and proven design throughout the facility. All design, materials and construction will comply with the Canadian code for LNG facilities and the requirements of the Pipeline Act and Regulations. The inner storage tank holding the LNG will be constructed of 9 percent nickel steel, the most commonly used material for inner tanks in the LNG industry. No LNG tank constructed of 9 percent nickel steel has ever failed. The second layer is isolation and containment systems in the unlikely event of a leak or spill of LNG. The facility is divided into numerous process segments that can be automatically isolated from each other. The storage tank and LNG piping will be surrounded by earthen dikes that can contain the entire contents of any spill or leak, including the entire contents of the tank. The third layer is the use of safety systems to detect abnormal conditions to shut off the flow of LNG to any leak or spill, to isolate the section and minimize the lost volumes. The facility will employ gas, liquid and fire detection systems activating automatically and 1 University of Houston Law Center Institute for Energy, Law & Enterprise, Introduction to LNG, An Overview of Liquefied Natural Gas (LNG) Its Properties, the LNG Industry, Safety consideration, January Appendix A LNG Storage Facility Project Information Page 14

152 Appendix A Mt. Hayes LNG Storage Project remotely-activated shut-off, shut-down and fire-fighting systems in the event of any emergency. These systems are continuously monitored by on-site personnel who can also manually activate any safety system. In addition, the LNG Storage Facility will be monitored 24/7 at TGI s gas control centre located in Surrey, British Columbia. The fourth layer is the establishment of safe separation distances as required in the regulatory codes and standards. TGVI will maintain control over land around the facility so that the required buffer zone is maintained for the life of the facility. The fifth layer is the employment of proven and well-established and documented operating and maintenance procedures, standards and practices. These documents, in use at the existing TGI Tilbury LNG Facility, will be adapted to the specific requirements of the proposed facility at Mt. Hayes. Participation in industry organizations and ongoing review of these documents allow TGVI and TGI to keep up with developments in technology and industry practices. Incorporated in these documents are clear requirements for training of personnel, emergency preparation and safety procedures. Cooperation with local emergency response agencies is incorporated in the operating standards. Trained personnel will operate the TGVI facility at Mt. Hayes, and will participate in development of all operating and maintenance procedures, standards and practices. 4.3 LNG STORAGE FACILITY HAZARDS The hazard most recognized in connection with the siting of an LNG facility is the potential for a large-scale spill of LNG and the potential of a subsequent fire which could threaten the public and employees and/or damage adjacent properties and the facility. The design of the LNG Storage Facility minimizes this hazard. The safety systems are designed to minimize any spill or leak and isolate and make safe the entire facility. The proposed LNG storage tank contains the greatest volume of product in the facility. The inner tank (the LNG primary containment) will be constructed of 9 percent nickel steel which has been proven to withstand the cryogenic temperature (-162 o C) of the LNG. An earthen dike will provide impoundment, and will be designed to hold the entire contents of the inner tank in the extremely unlikely event of a leak in the LNG tank. Design of the LNG storage facility, per the codes, addresses a sustained pool fire which could result if the LNG in the storage tank were to leak, empty into the earthen dike and catch on fire. Such an event would create a large steady state pool fire for a sustained period of time. The maximum thermal radiation hazard from such an event at any point around the facility is determined through computer modelling 2 and is a function of the size of LNG pool, wind direction and speed, relative humidity, ambient temperature and distance. The heat radiation effect drops rapidly as the distance from the fire increases. The radiation zone for the proposed 1.5 Bcf TGVI Facility is expected to extend to a maximum of approximately 400 m from the centre of the containment dike. TGVI will control use of the land and the activity of public and personnel in all radiation areas considered within the codes. Since 1960, the world s LNG facilities (approximate 240) have recorded about 7,500 facility-years of experience. During this time there has been no large spill of LNG. LNG that spills or leaks will flow, much like water, to the low spots in the surrounding area, where it will gradually evaporate. Along with a multitude of systems and equipment which are designed to prevent any such spills or leaks from occurring in the first place, the proposed LNG 2 Determined by computer simulation program LNG FIRE 3, developed by Risk & Industrial Safety Consultants for Gas Research Institute, Appendix A LNG Storage Facility Project Information Page 15

153 Appendix A Mt. Hayes LNG Storage Project Storage Facility design also will utilize the natural properties of LNG and rely on passive safety systems (e.g. channelling to specifically sited sump within the dike) which do not require the operation of equipment or human intervention to function. In addition, the facility will incorporate many hazard detection systems which will detect any spill, leak or fire as soon as possible and allow equipment to be shut down and isolated so as to minimize the scale of such an event. Once collected, any spilled LNG will evaporate slowly and can be monitored by the operating staff at the facility to ensure no further hazard arises as a result of the spill. Initially the gas is colder and heavier than the surrounding air and can create a fog or vapour cloud above the released liquid. As the gas warms up it mixes with the surrounding air and begins to disperse. If the vapour cloud encounters an ignition source, it can ignite only if the methane/air mixture is in the 5 to 15 percent flammability range. The CSA code sets out the design criteria for the control of the vapour to mitigate any impacts. 4.4 LNG STORAGE FACILITY FIRE PROTECTION SYSTEMS Prevention of any fire occurs primarily through application of the five layers of facility integrity noted in 4.2 above. To reduce the effects of a fire that does happen, the proposed LNG Storage Facility will have a fire water system. A pond will be constructed on site to collect local runoff water. Water from the pond will be utilized to fill an onsite fire water tank that will supply the fire water system. An underground firewater pipe will encircle the facility. Branches will feed various fire fighting locations with multiple hydrants to keep any equipment cool in the event of fire at any adjacent location. Water is not used to fight an LNG fire, as the warm water will increase the rate of vapourization of the cold liquid. Water is also not typically used to fight or extinguish a natural gas vapour fire but is typically used to cool and protect facilities adjacent to a fire and to fight non-gas related fires. Extinguishing a natural gas fire itself is achieved through elimination of the supply of natural gas to the fire location. Dry chemical fire extinguishing equipment to directly fight any natural gas (or other compound) fire will be located throughout the facility. Dry chemical skidded, wheeled and hand held units will be incorporated in the fire protection plan for the LNG Storage Facility Construction Risk to the Forest Construction of the LNG Storage Facility, with the attendant process work areas, and pipeline, powerline and road construction, pose little risk of forest fire. Heavy equipment with firefighting capability will be onsite at all required times in case a fire starts accidentally. The sites will be cleared prior to construction activities. Piling and burning of the slash will be conducted under provincial regulations, and will result in a reduced fuel load at the site. The construction phase will include the development of an Emergency Response Plan ("ERP"). Construction workers will be briefed on the need for fire safety and proper response in case of fire Operation Facility Risk to the Forest The risk to the surrounding forest area from a fire at the LNG Storage Facility is minimal. TGVI s Facility will be designed to fail safe by isolating equipment, containing spills and accommodating fire without harm to surroundings. The facility design, combined with fire warning and suppression systems that meet or exceed CSA requirements and industry standards, provide a high level of protection against fire risk to the forest. At ambient temperatures, without a source of ignition, the LNG would rapidly evaporate and dissipate. In the event of ignition, water and dry chemical fire fighting equipment is available on site to fight Appendix A LNG Storage Facility Project Information Page 16

154 Appendix A Mt. Hayes LNG Storage Project potential facility fires and keep adjacent facilities cool. The code designated thermal setback areas will mitigate potential impacts to the public. TGVI proposes to remove trees within a minimum of 100 m of the tank dike to mitigate the potential for a fire at the LNG Storage Facility from impacting the adjacent forest Operation Fire Risk to the Facility Protection of the LNG tank from forest fires is an important consideration in TGVI s design, construction, and operation of the LNG Storage Facility sited in the forest environment. The fire potential on south-eastern Vancouver Island is highly seasonal and protection services are available. The following mitigation measures will minimize the risk to the LNG Storage Facility from forest fires: Maintain an appropriate separation distance (minimum 100 m) between the tank dike and the forest; Ensure that the ERP includes cooperation with the Island Timberlands, the regulators, and local fire departments; Use non-flammable materials for construction of all facilities on site; Install a firewater storage and pumping system with underground piping, fire hydrants, fire monitors and hose cabinets installed in critical areas to cool facilities in the event of a surrounding forest fire. Given the specifics of project design, impacts resulting from a forest fire are considered to be of low magnitude. 4.5 OTHER LNG STORAGE FACILITY SAFETY ISSUES LNG facilities present other safety issues that are of relatively lower significance and consequence than a fire, as far as the protection of the public is concerned. The facility design and specific operating procedures will address these other hazards, which include: Personnel exposed to direct contact with LNG (liquid at -162 o C) or very cold LNG vapours could sustain severe frostbite (or freeze burns). The potential extent of this cryogenic hazard is limited to the immediate area around equipment, piping and tanks containing LNG. Protective clothing and shields will be used to mitigate this hazard; Methane gas, the primary component of LNG, is colourless, odourless and is classified as an asphyxiate (when released it displaces air). Separation distances and gas detection systems will be used to mitigate this hazard; The process of liquefying natural gas removes almost all of the components that give LNG any detectable odour. All vapourized LNG leaving the LNG Storage Facility will be odorized to meet government and pipeline standards. Fuel gas used in the LNG Storage Facility will also be odorized. Additional hazard mitigation includes gas detection in areas of possible leaks; Distances between property lines, buildings, electrical equipment, process equipment, impoundments, and the proposed LNG storage tank will meet or exceed the spacing requirements of CSA standards; Appendix A LNG Storage Facility Project Information Page 17

155 Appendix A Mt. Hayes LNG Storage Project The LNG Storage Facility will utilize continuous monitoring equipment to detect hazardous conditions. Hazard detection will include: evidence of combustible gas, cold temperatures from LNG spills, fire, smoke, and high pressure in tanks and vessels; Quantities of other compounds may be stored on site as part of the liquefaction or back-up systems (e.g. diesel, propane, etc.) depending on the final specific design that is approved. TGVI will ensure all appropriate and required safety systems are in place for these compounds. 4.6 PIPELINE INTEGRITY The LNG Facility will be connected to the TGVI transmission system by two pipeline laterals, each 273 mm (10 ) diameter pipelines of approximately 5 km length. The pipeline laterals to the LNG Facility will be designed in compliance with the code requirements of the Canadian standard CSA Z662 Oil and Gas Pipeline Systems and the B.C. Pipeline Act. The design, construction and operation of TGVI s pipeline systems are reviewed and approved by the BC OGC, which is the responsible agency for regulations related to construction, operations and maintenance for natural gas pipelines which operate at over 100 psig. The laterals to the proposed LNG Facility will be buried a minimum of 0.7 m within a proposed 18 m wide right-of-way. The pipeline right-of-way is patrolled periodically via helicopter, in addition to ground patrols. TGVI is a member of BC One Call, a notification service for anyone wishing to dig in the vicinity of the pipeline. TGVI also maintains a complete list of all land owners impacted by the pipeline right-of-way, and has a yearly pipeline awareness program. The pipeline valves and the current pipeline conditions of the entire pipeline are monitored centrally for all of TGVI s transmission pipeline systems by a SCADA (Supervisory Control and Data Acquisition) system which is manned 24/7. Emergency actions may be initiated remotely by the SCADA operator in the event of a pipeline incident. TGVI pipelines and laterals are capable of being internally inspected and once placed into operation they become part of a systematic integrity inspection program. 4.7 SEISMICITY South-western British Columbia including Vancouver Island is located within a seismically active area. One of the mechanisms that results in earthquakes is continental drift, which involves the slow movement of various continental and oceanic plates relative to one another. Movement along a subduction zone involving the oceanic Juan de Fuca plate tending to slide down under the edge of the continental plate which includes Vancouver Island is an important factor in the seismicity of southern Vancouver Island and nearby parts of the coast Seismic Design and Mitigation Earthquakes near the study area could potentially result in relatively high seismic motions. Such earthquakes could occur as a result of fault movements along or close to the subduction zone, or along faults within the continental plate overlying the subduction zone, such as the Cowichan System. The current edition of the Canadian Standard CSA Z276, which applies to LNG production, storage, and handling, specifies two levels of earthquake motions that need to be considered during facility design: Appendix A LNG Storage Facility Project Information Page 18

156 Appendix A Mt. Hayes LNG Storage Project 1. Operating Basis Earthquake ("OBE"), where the structures and systems will be designed to remain operable during and after the OBE event. The current code specifies the OBE basis as a 10 percent probability of exceedence within a 50-year period (corresponding to a 1:475 year event) and the proposed CSA Z276 update maintains this requirement; 2. Safe Shutdown Earthquake ("SSE"), where there will be no loss of containment capability of the tank and it will be possible to isolate and maintain the LNG container during and after the SSE event. The current code specifies the SSE basis as a 5 percent probability of exceedence within a 50-year period (corresponding to a 1:1,000 year event). The draft CSA Z276 update is proposed to specify a 1:2,475 year event (or approximately 1:2,500 year event) which is the same as the design basis earthquake used in the current National Building Code. The LNG Facility will be designed to the higher standards encompassed in the proposed revisions of the various codes incorporating the most recent knowledge and predictions of the potential seismic motions. The proposed CSA Z276 requirements for the OBE and SSE seismic events will be used as a minimum standard. A site specific seismic study by geotechnical and seismic experts has been carried out to define local seismic design parameters. This study includes consideration of both regional conditions as well as local conditions such as nearby faults within the Cowichan Fold and Thrust Zone. It should be further noted that the shaking which would be experienced in a very large subduction earthquake could last much longer than the shaking from a smaller event, although the local ground motions might be similar depending on the distance and attenuation characteristics. The longer period of shaking will be considered in the design of the facilities. There are about three hundred LNG storage tanks of this size and type in the world. Many of these tanks are located in parts of the world that are more seismically active than the Mt. Hayes location, such as Japan, Korea, Turkey and Greece. Because of the significant industry experience, the methods for seismic design are well known and well accepted in the international engineering community. The LNG storage tank, buildings, equipment and piping proposed for the LNG Facility at the Mt. Hayes location are all well within the industry s seismic design and construction experience, practice and capabilities. 4.8 FACILITY SECURITY The security strategy for the facility will include controlling all access by individuals and vehicles onto the site. The entire boundary of the facility site, including the LNG storage and vapourization facilities will be fenced with chain link and a top guard that meet or exceed recognized industry standards as to gauge and height. The number of access points to the LNG-related facilities will be limited to an absolute minimum, but will include at least one emergency gate. The access points will have video monitoring, with feeds into the facility control room. An employee will be required to manually or remotely unlock gates to allow access to any persons or vehicles. The monitoring and detection systems at the proposed facility will function on a 24/7 basis and consist of intrusion detection alarms, CCTV, regular (but random) patrols and lighting. These systems, as well as the security communication system, will be operated and monitored at the control room. LNG Facility operation and management will establish liaison with all appropriate government security and emergency response agencies. TGVI is prepared to protect the public, employees Appendix A LNG Storage Facility Project Information Page 19

157 Appendix A Mt. Hayes LNG Storage Project and the LNG Storage Facility from all threats or potential damage that can be defined as reasonable, credible and defensible. The design of the facility, including the TGVI controlled separation zone around the facility and the earthen dikes will minimize any potential impacts to the public. TGV will ensure that training is provided to LNG facility operating personnel and that the LNG facility is operated in compliance with Canadian regulations. 4.9 EMERGENCY RESPONSE PLAN (ERP) TGI has an existing LNG Facility in Delta, B.C. which has operated successfully for over 30 years as well as thousands of kilometres of transmission pressure pipelines. TGVI considers safety and emergency response to be of prime importance and will remain proactive in improving the ERP and the safe operation of the LNG Facility. TGVI is committed to: Developing a site and location specific ERP for the proposed Mt. Hayes LNG Storage Facility; Meeting or exceeding relevant laws and regulations and cooperating with local authorities; Regularly testing and improving emergency response plans; Ensuring appropriate resources and training to implement the plans; Monitoring industry development of improvements to emergency response issues. The ERP will clearly lay out the methodology for TGVI employees to effectively manage any emergency at the LNG storage facility. The ERP is developed to minimize injury to the public and employees, to minimize damage to property and the environment, and to promote rapid return to normal operation. The ERP lays out the organization, duties and responsibilities of all facility and off-site support personnel, including corporate emergency response centres. Chains of command are clarified, including appropriate contact and communication with local and provincial emergency response agencies LOCAL NOTIFICATION AND INVOLVEMENT TGVI is committed to working with local and provincial authorities on all aspects of the proposed LNG storage facility. Specific to the ERP, TGVI will work with the local Fire Department(s), emergency response and regulatory authorities to achieve a high level of comfort and communication, including ongoing dialogue on emergency preparedness and responsibilities for response and cooperation and involvement in facility emergency exercises on a regular basis. 5.0 PUBLIC CONSULTATION TGVI will be responsible for the project development process public consultation. The previous TGVI consultation efforts were addressed in The 2005 Decision Section 7.6 The public consultations carried out by TGVI appear to have been adequate and there was a comprehensive attempt to explain the operation and safety-related issues of an LNG storage facility to members of the general public. The Commission Panel notes that there were no adverse submissions by any intervenor in this proceeding that centred upon safety or environmental concerns related to the LNG storage facility. 5.1 PUBLIC CONSULTATION PROGRAM The public consultation information provided in Section above and in the 2004 ESR outlines the comprehensive site selection and public consultation program that was undertaken Appendix A LNG Storage Facility Project Information Page 20

158 Appendix A Mt. Hayes LNG Storage Project by TGVI in 2003 and 2004 to engage the public and locate a suitable site for the project. This program culminated in the successful rezoning of the subject Mt. Hayes property. Public consultation has continued with the key stakeholders and will continue through the permitting, construction and operation phases of the project to ensure that project developments are communicated in a timely fashion, TGVI is aware of any stakeholder concerns, any potential negative impacts are mitigated and positive benefits of the project for the local community are realized. 5.2 FIRST NATIONS Although the majority of the lands affected by the LNG Facility and right-of-ways involve private lands, with only a small impact to Crown lands, all the proposed TGVI facilities fall within the traditional territory of the Chemainus First Nation ("CFN"). TGVI successfully negotiated a Memorandum of Understanding (MOU) with the CFN in SOCIO ECONOMIC ASSESSMENT The construction of the LNG Storage Facility and connecting facilities (estimated cost of $166 million) will provide positive benefits to local Vancouver Island communities as well as to British Columbia and Canada. The 2004 Environmental and Social Review Report included an assessment of the socio economic effects of a 1.0 Bcf LNG storage facility as cost estimated at that time. The effects of the project implementation, based on the current P50 capital cost estimate, are shown in Table 5-1. Table 5-1 $Million Local Area Economic Effects All BC Canada (ex BC) Ex- Canada TOTAL Total $50.3 $73.0 $22.8 $69.5 $165.3 Employment Person-Yrs Direct Indirect Total Once in operation, the facility is expected to employ 9 full time employees and generate approximately $150,000 in local expenditures annually (not including electricity and fuel gas). Local property taxes paid on the LNG Storage Facility are estimated in the range of $500,000 annually. 6.0 PROJECT MANAGEMENT, ENGINEERING AND CONSTRUCTION The LNG Storage Facility and System Facilities project team will also include personnel from TGI and other parties to manage the all aspects of the project. TGI personnel involved in the TGVI project team will draw on TGI s considerable experience in managing and completing major projects on time and on budget and experience in the development of the previous and current applications. A TGVI project manager, who in turn will report to a TGVI project sponsor, Appendix A LNG Storage Facility Project Information Page 21

159 Appendix A Mt. Hayes LNG Storage Project will direct all phases of the Project after BCUC approval and will execute the overall project utilizing experienced contractors, consulting professionals and TGVI personnel. TGVI will enter into a turnkey EPC contract for the 1.5 Bcf LNG Facility, including all work inside the facility fence after site grade is established. The EPC contractor will manage the design, procurement and construction of the major portion of the LNG Storage Facility according to performance specifications and conditions contractually agreed to with TGVI. TGVI had previously completed an Expression of Interest review with major LNG contractors and selected an EPC contractor and negotiated a sole source contract for the 1.0 Bcf LNG storage facility. TGVI completed negotiation of contract terms and conditions and performance specifications for the 1.0 Bcf facility in support of the EPC contract. TGVI will contract with an EPC contractor to provide an operational 1.5 Bcf LNG facility, to be in-service approximately 40 months after Notice to Proceed (schedule as outlined in Section 5) to allow the LNG tank to be full at November 1, Development of facility design and a firm price for the EPC contract will take place as late as possible prior to the desired project construction start date (issuing of the Notice to Proceed) to minimize contingency requirements for future market, materials, equipment and industry volatility. The power line installation will be managed by the TGVI project team engaging local consultants and contractors, separate from the scope of the LNG facility work undertaken by the EPC contractor. The project manager will implement a project execution plan for the development of each segment of the overall project including design and construction quality assurance for all phases. TGI personnel experienced in LNG operations will be involved in the LNG Storage Facility Project as required to ensure all facilities can be efficiently placed into operation upon completion of construction in conformance with TGVI, TGI and industry practices. 7.0 LIQUEFIED NATURAL GAS ( LNG ) 7.1 WHAT IS IT? When natural gas is cooled to a temperature of approximately -162 C (-260 F) at atmospheric pressure, it condenses to a liquid called liquefied natural gas ( LNG ). One volume of this liquid is formed from approximately 620 volumes of gas at atmospheric pressure and ambient temperature. Conversely when vaporized, 620 cubic feet of gas are produced from every cubic foot of liquid. This clear liquid weighs about half as much as the same volume of water. 7.2 USEFULNESS The large ratio of the volume of gas to the volume of liquid (620:1) makes storage of natural gas in the liquid state attractive. The reduced volume and liquid state also makes possible alternate methods of transportation where conventional gas pipelines are not practical. 7.3 COMPOSITION LNG is composed primarily of methane and may also contain ethane and some heavier hydrocarbons. Small quantities of nitrogen, which often occur in natural gas, may also be dissolved in LNG. Prior to liquefaction to produce LNG, natural gas must be treated to remove carbon dioxide, water, sulphur compounds an all such constituents that could form solids at LNG temperatures and plug process equipment. Appendix A LNG Storage Facility Project Information Page 22

160 Appendix A Mt. Hayes LNG Storage Project 7.4 SAFETY LNG will not burn or explode and must be returned to its vapour state and then mixed in a ratio of 5% to 15% gas in air before it is capable of supporting combustion. 7.5 TEMPERATURE EFFECTS At atmospheric pressure, LNG boils at approximately 260 F (162 C) below zero. This is classified as a "cryogenic" temperature. The field of cryogenics includes: the processes and equipment used to produce liquefied gases such as LNG; the equipment used to store, transport, and handle them; and all the phenomena that are produced by the cold temperature. Marked changes in the physical behaviour of many materials occur at LNG temperatures. Rubber at cryogenic temperature, for example, loses its resiliency and shatters like glass if dropped or struck by a hammer. Carbon steel undergoes a change from a ductile material that fails by stretching at warmer temperatures to a brittle material that fails by cracking at cryogenic temperatures. While some of the familiar materials of construction are not suitable at LNG temperatures, many materials such as 9% nickel alloy steel, aluminium, stainless steel and concrete are well proven in use at these cryogenic temperatures. Appendix A LNG Storage Facility Project Information Page 23

161 Appendix B A FAIR RETURN FOR NATURAL GAS STORAGE INVESTMENT

162 Appendix B A Fair Return for Natural Gas Storage Investment APPENDIX B A FAIR RETURN FOR NATURAL GAS STORAGE INVESTMENT The LNG Storage Facility will provide a valuable peaking gas supply resource for both TGVI and TGI as part of their overall gas portfolios and reduce their dependence on third party downstream storage resources and/or upstream pipeline capacity. In addition, as an on-system resource, the LNG Storage Facility will allow TGVI to defer or avoid transmission system expansions and improve the efficiency and reliability of its existing transmission system. In Section 7.1 of the Application, the Company describes how the LNG Storage Facility will provide storage services for TGI at a rate that is competitive with reasonable and appropriate proxies for market rates. The same rate is assumed for TGVI in allocating a portion of the remaining LNG cost of service to TGVI s gas supply portfolio. The residual LNG Storage Facility cost of service after deduction of TGI revenues and the allocation to TGVI s gas supply is attributed to the transmission system capacity requirement and results in costs that are well below the costs of the pipe and compression alternative, as described in Section 7.2. In Section 7.3 the Company describes the additional benefits that TGVI and TGI customers will receive as a result of the Project. In summary, customers of TGVI and TGI will receive storage service and TGVI customers will receive increased system capacity, along with additional benefits. Under the Project as proposed by the Company these services and benefits will be received at rates that are at or below market alternatives. The economic justification, which is set out in Section 8, as well as the portfolio comparison analyses included in Section 7, have been determined based on the Company s proposal for an allowed ROE for the LNG Storage Facility set at 50 basis points above TGVI s base-level ROE. 1 Natural Gas Infrastructure Regional Constraints As summarised in Section of the Application, natural gas infrastructure in TGVI and TGI s market area, the Pacific Northwest region, is becoming increasingly constrained during winter peaking periods. In order to meet the growing peaking requirements of their customers, TGVI and TGI s gas supply alternative to the LNG Storage Facility is to promote incremental third party investment in off-system storage resources and/or upstream/downstream pipeline capacity through long term contractual commitments. For more than 20 years there have been no major new investments in natural gas storage in British Columbia. Presently there are only two natural gas storage facilities in British Columbia. The Unocal Aitken Creek Storage, a supply area facility in northern BC, is the largest storage facility in the province and is used by TGI as a seasonal resource. The second is TGI s Tilbury LNG, which is located in the Lower Mainland market area and is the only peak shaving storage facility in BC. The Tilbury LNG facility is located on Tilbury Island in Delta, BC and has been in operation since TGVI s proposed LNG Storage Facility will represent the first significant investment in a natural gas storage facility in British Columbia in the last 20 years. In the Pacific Northwest, there are only four LNG peak shaving storage facilities, and two major underground gas storage facilities. The largest LNG facility is located in Plymouth, Washington and is owned and operated by Northwest Pipeline Company (a subsidiary of Williams Appendix B A Fair Return for Natural Gas Storage Investment Page 1

163 Appendix B A Fair Return for Natural Gas Storage Investment Companies Inc.). It has a storage capacity of 2.4 billion cubic feet, and a regulated return on equity equal to Williams (black box settlement, approximately 11.2%, with a common equity component of approximately 55%). The Plymouth LNG storage facility is regulated by the Federal Energy Regulatory Commission (the FERC ). Northwest Natural owns and operates two LNG facilities, one located in Newport, Oregon and the second located in Portland, Oregon, which is similar in size to the TGI s Tilbury LNG facility. Both of these facilities are regulated by the Public Utility Commission of Oregon, and have allowed returns on equity equal to Northwest Natural s Oregon allowed return on equity of 10.2%, and an approved common equity component of 49.5%. Puget Sound Energy owns and operates a small satellite LNG peak shaving facility located in Gig Harbor, with a storage capacity of billion cubic feet. With the exception of the small Gig Harbor satellite facility, which became operational in 2004, the remaining three facilities have been in operation ranging from 20 to 35 years. Terasen Gas is not aware of any definitive plans for additional peak shaving LNG storage facilities in the region for the foreseeable future, although Terasen Gas understands that Cascade Natural Gas Corporation is evaluating a potential peak shaving facility in its service territory. The two underground storage facilities, which are described in more detail in Appendix G of the TGVI 2006 Resource Plan, are Jackson Prairie (JP) storage, located in Chehalis, Washington and co-owned by Northwest Pipeline Company, Avista Corporation, and Puget Sound Energy (operated by Puget Sound Energy), and the Mist storage facility, located in Mist, Oregon and owned and operated by Northwest Natural. JP storage is regulated by FERC and the Washington Utilities and Transportation Commission, and each owner s applicable allowed return on equity is applied to their portion of the facility. The approved return on equity for Northwest Pipeline Company as noted above is approximately 11.2%, with a common equity component of approximately 55%. The approved return on equity for Puget Sound Energy is 10.3%, with an approved common equity component of 43%. Finally, the approved return on equity for Avista Corporation is 10.4%, with an approved common equity component of 40%. The Mist storage facility, owned and operated by Northwest Natural, is regulated by FERC and the Public Utility Commission of Oregon, and it has an allowed return and equity capital component equal to Northwest Natural s, as noted above, which is 10.2%, and 49.5% respectively. The Jackson Prairie storage facility has been in operation since 1964, and is currently undergoing a facility expansion, increasing delivery by 300 MMcf per day and the working gas capacity by 6.3 Bcf, which is expected to be completed by TGI participated in the open season for the JP storage facility expansion and was awarded a long term contract which has subsequently been approved by the Commission. The need for regional storage resources was highlighted by the fact that the JP storage facility expansion was oversubscribed in the open season process. The Mist storage facility has been in operation since In the year 2000, the Mist storage facility underwent an expansion to allow for interstate services, and another recent expansion, completed in Northwest Natural is not planning on expanding the Mist facility again until at least Prior to the year 2000, Mist was used exclusively to meet Northwest Natural s core market requirements. With regard to the interstate services for the Mist facility, Northwest Natural has an incentive arrangement on the revenues from these services which enable it to achieve higher returns than its approved regulated ROE (currently 10.2% as discussed above). As discussed above, Unocal s Aitken Creek storage facility in northeast British Columbia is a supply area resource. The Aitken Creek facility was developed in the mid-eighties and has Appendix B A Fair Return for Natural Gas Storage Investment Page 2

164 Appendix B A Fair Return for Natural Gas Storage Investment expanded since then. Until recently, it has operated as an unregulated facility. After receiving notice in 2006 that the BCUC intended to regulate the Aitken Creek facility a regulatory process ensued in which Unocal has been seeking an exemption from rate regulation. The regulatory process involved a written hearing process that resulted in a May 17, 2007 Decision and letter from the Commission to the Province requesting approval to issue an exemption order to Unocal for many but not all of the exemption provisions sought for the Aitken Creek facility. The aspect of this Aitken Creek exemption process that is germane to the current discussion is that the imposition of rate regulation and regulated returns on the Aitken Creek facility would discourage new investment by Unocal in the facility. As discussed above, no new LNG or underground storage facilities of significant size have been developed in the region in recent years. Expansions at existing underground storage facilities have occurred and the additional capacity from these expansions has generally been taken up in short order, confirming that there is demand for these resources in the market place. Terasen Gas observes that where there has been natural gas storage capacity developed in more recent years it has been in the PNW where returns are relatively higher than the regulated allowed returns in British Columbia, where there have not been any developments in new storage in roughly 20 years. 2 Natural Gas Storage Infrastructure Concerns - North America There have been two significant decisions recently from the FERC and the Ontario Energy Board ( OEB ) signalling the need for regulatory forbearance in the natural gas storage market, in order to facilitate capital investment in natural gas storage infrastructure. FERC issued Order No. 678 on June 19, 2006, which established more flexible criteria for the evaluation of applications for market-based pricing of natural gas storage services. FERC Order No. 678 implements Section 312 of the Energy Policy Act of 2005, which permits FERC to authorize storage providers, in appropriate circumstances, to charge market-based rates, even when the storage providers cannot demonstrate that they lack market power. This final rule was adopted to encourage the development of natural gas storage facilities in the United States, as well as to reduce the price volatility of natural gas. The Energy Policy Act of 2005, released on August 8, 2005 outlined that FERC may authorize a storage provider to charge market based rates, if the provider can demonstrate that (A) marketbased rates are in the public interest and necessary to encourage the construction of the storage capacity in the area needing storage services, among other criteria. FERC Order No. 678 recognizes that, storage providers may require incentives through deregulation and market-based rates in order to encourage storage investment in areas in need of natural gas storage resources. On November 7, 2006, the OEB issued EB Natural Gas Electricity Interface Review Decisions with Reasons. In its decision, the OEB stated that they will refrain from regulating the pricing for a significant portion of Ontario s natural gas storage. The OEB Decision reserves enough storage capacity in the existing storage facilities for forecast utility core market requirements but permits market-based pricing for capacity over and above the reserved amount and for any future storage expansions. The OEB believes that by refraining from regulating the price of natural gas storage services, this decision will ensure the development of much needed storage facilities, (which are primarily targeted for electricity generation). Appendix B A Fair Return for Natural Gas Storage Investment Page 3

165 Appendix B A Fair Return for Natural Gas Storage Investment The FERC and the OEB are not the only regulatory bodies that are grappling with the growing need for additional investment in energy infrastructure, not just natural gas storage, and methods to facilitate such investment. In Nevada, certain new facilities that are considered by the regulator to be critical facilities, based on criteria regarding reliability, diversity of supply and price stability are permitted incremental allowed returns for the investment. In Iowa, legislation has been enacted to allow specific ROEs to attract development of electric power generating and transmission facilities within Iowa. This statute applies to rate-regulated public utilities within the state. Although the circumstances are not entirely the same in British Columbia (no two jurisdictions are perfectly comparable), as those considered in the FERC and OEB rulings, as well as those in the states of Nevada and Iowa, the Company is of the view and that higher allowed returns for projects will encourage investment in much needed important energy infrastructure, including natural gas storage, which will benefit all energy consumers in British Columbia and the region. 3 FERC Ruling to Promote Electric Transmission Investment On July 20, 2006, FERC issued Order No. 679, and amended its regulations to establish incentive-based rate treatments for electric transmission investments in order to encourage transmission infrastructure investment. FERC Order No. 679 was issued pursuant to Section 1241 of the Energy Policy Act of 2005, Transmission Infrastructure Investment, which added section 219 to the Federal Power Act. Section 1241 directed FERC to establish a rule that would encourage investment in electricity transmission infrastructure. Section 1241 also directed FERC to include in its order a provision for a return on equity that attracts new investment in transmission facilities... The purpose of this rule was to benefit consumers by ensuring reliability and decreasing the cost of power delivery by reducing electric transmission congestion through encouraging capital investment in an aging electric grid system. In order to receive a higher return on equity, a public utility must justify the requirements for the new facility by demonstrating that it will increase transmission capacity and improve reliability. In addition the utility must explain whether and how the proposed facility is included in a regional planning process. Finally, the utility must explain how the proposed return on equity was derived and justify why it is necessary and appropriate. On October 31, 2006, FERC authorized a return on equity for the owners of the ISO New England transmission grid, which included an incentive rate. The incentive rate was granted to encourage electric transmission investment and increase the grid reliability in the New England region. The FERC decision granted a specific ROE incentive of 100 basis points and confirmed a link between the cost of the return on equity incentive and the benefits to New England electricity consumers from the increase in transmission investment. FERC determined that a base-level return on equity of 10.2 percent was appropriate. This was based on a proxy group made up of United States northeast utility companies. FERC then determined that this base-level return should be adjusted by: 50 basis points (or one-half percent), which was in return for the transmission owners agreement to transfer the operational control of their facilities to ISO New England, 100 basis points (or 1 percent), which is an incentive to encourage transmission investment and expansion in the New England region, and 74 basis points, which reflected updated bond data. The resulting returns on equity were 11.7 percent covering the initial rate effective date of February 1, 2005 to October 31, 2006, and 12.4 Appendix B A Fair Return for Natural Gas Storage Investment Page 4

166 Appendix B A Fair Return for Natural Gas Storage Investment percent going forward. This FERC decision once again demonstrates that higher allowed returns for capital projects are required to encourage capital investment in infrastructure. 4 The Rationale for a Fair Return The Company believes that the LNG Storage Facility will, in addition to providing additional reliability and security of supply as well as other benefits, allow for the provision of storage services for gas customers in BC at costs in line with market rates based on reasonable proxies, and will allow for the addition of transmission capacity for the TGVI system at a cost well below the next best alternative. This favourable outcome in terms of costs from a customer perspective, has been determined based on an ROE enhancement of 50 basis points over the TGVI base-level allowed ROE for the LNG Storage Facility-related equity. As stated above, TGVI and TGI s alternative to the LNG Storage Facility for meeting its growing peaking requirements is to promote, through long term contractual commitments, investment by others in incremental off-system storage resources and/or upstream pipeline capacity. It is likely that investments in off-system storage resources would occur in jurisdictions where higher returns are allowed by regulators. Off-system storage investments elsewhere in the PNW will not allow TGVI s customers to realize the additional benefits of on-system reliability and security of supply, and other benefits as described in the Application. Furthermore, if the gas supply needs were met by new off-system storage, TGVI would not realize the benefits of avoided pipe and compression costs. Consequently, the overall cost to TGVI s customers would be greater, fewer benefits would be realized, reliability and security of supply would be diminished at the same time as another regulated utility was achieving higher returns on its incremental storage investments funded by ratepayers in British Columbia. TGVI also notes that the development of the LNG facility within BC is strongly consistent with the themes in the 2007 BC Energy Plan of energy security and self sufficiency in the province. In Canada over the last ten to fifteen years utility ROEs have been set predominantly according to formula-based methodologies using an equity risk premium approach relative to long Canada bonds. This has led to a widening gap in approved returns for Canadian local distribution utilities and transmission providers relative to their U.S. counterparts. When the formula-based ROE approach was adopted in the mid-1990s Canadian utility ROEs were comparable to the ROEs being awarded in U.S. jurisdictions. Since the mid-1990s the effect of the formula-based equity risk premium ROE methodology has been to reduce the allowed ROEs of Canadian utilities to levels 100 to 170 basis points lower than their U.S. utility counterparts. Canadian utility ROEs have declined even more dramatically in the same period relative to North American low risk industrial returns. The issue of utility comparable earnings relative to low risk industrial returns was addressed in the Commission s March 2, 2006 decision on TGI and TGVI s Application to Determine the Appropriate Return on Equity and Capital Structure. In that decision the Commission indicated that the comparable earnings approach deserved consideration but there was insufficient evidence on the record to give weight to this approach in arriving at the allowed ROEs. These trends are affecting the longer-term ability of Canadian utilities to attract capital. While the short term impact of these trends on energy infrastructure may not be obvious, in the longer term where investment risk is similar, rational investors will put their money in higher return investments. As is being recognized in other jurisdictions across the continent, it is important that there is an appropriate climate for investment in important energy infrastructure, including additional natural Appendix B A Fair Return for Natural Gas Storage Investment Page 5

167 Appendix B A Fair Return for Natural Gas Storage Investment gas storage, within the province. There have not been new greenfield storage resources developed in the province or the Pacific Northwest in the past 20 years and the Company is of the view that these important infrastructure investments need to be encouraged, and that can be done through the provision of a fair and comparable return. Specifically, the Company is of the view that an additional 50 bps of allowed return proposed for the Project is reasonable and appropriate as it will promote much needed investment in a scarce resource in the region and more importantly in British Columbia, that will provide storage service to the customers of TGVI and TGI at or below the costs of alternatives. Furthermore, the Commission routinely approves storage contracts with off system providers whose costs include returns significantly higher than those being proposed for this project. The investment in this Project which delivers unique benefits to utility customers over the alternatives should be allowed an appropriate and fair return. Appendix B A Fair Return for Natural Gas Storage Investment Page 6

168 Appendix C STORAGE & DELIVERY AGREEMENT

169

170

171 Schedule 1 This Storage and Delivery Agreement made as of this day of, 2007 BETWEEN: AND: TERASEN GAS (VANCOUVER ISLAND) INC. a company incorporated under the laws of British Columbia having an office at Fraser Highway, Surrey, British Columbia ( TGVI ) TERASEN GAS INC. a company incorporated under the laws of British Columbia having an office at Fraser Highway, Surrey, British Columbia ( TGI ) as sometimes referred to herein jointly as the Parties and individually as a Party. WHEREAS A. TGVI intends to construct a Liquefied Natural Gas ( LNG ) Storage Facility on Vancouver Island at Mount Hayes near Ladysmith that is scheduled to be available for usage on the Commencement Date. B. TGVI operates an integrated natural gas transmission and distribution system that serves customers on the Sunshine Coast and Vancouver Island. C. TGI is interested in contracting with TGVI for LNG storage and delivery services for the benefit of TGI s core market customers. NOW THEREFORE, in consideration of the promises set forth herein, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties agree as follows: 1. DEFINITIONS In this Agreement: Agreement means this Storage and Delivery Agreement; BCUC means the British Columbia Utilities Commission and any successor regulatory authority; Capacity Demand Charge is the demand rate for providing Storage Capacity expressed in dollars per GJ; Coloured Gas Tax Commodity Charge has the meaning set out in section 14.1 a); Commencement Date has the meaning set out in section 2.1; Day means the twenty-four hour period beginning 7:00 a.m. Pacific Clock Time; Delivery Service has the meaning set out in section 3.2; - 1 -

172 Schedule 1 Firm Liquefaction Rate has the meaning set out in section 3.1 a); Firm Liquefaction Service has the meaning set out in section 3.1 a); Firm Redelivery Service has the meaning set out in section 3.2 b); Firm Storage Capacity means the maximum quantity of gas that TGI has the right to store at the LNG Facility pursuant to section 4.1; Firm Storage Service has the meaning set out in section 3.1 b); Firm Vaporization Rate means that maximum level of Firm Vaporization service per Day as contracted for by TGI, and that TGVI is obliged to provide pursuant to section 4.1; Firm Vaporization Service has the meaning set out in section 3.1 c); Force Majeure means a condition, cause or event that is beyond the reasonable control of a Party and not caused in whole or in part by its default, and includes acts of war, revolution, riot, sabotage, vandalism, earthquakes, storms, lightning, weather conditions and other acts of God, local or national emergencies, strikes, lockouts, work slowdowns and other labour disputes, acts and orders of government or regulatory authorities, provided "Force Majeure" will not include an act of negligence or intentional wrongdoing of the Party or any lack of money or credit by the Party and will not include: (a) loss by either Party of markets (unless it is a result of an act of Force Majeure); or (b) inability economically to use or sell gas; or (c) either Party s loss of gas supply (unless it is a result of an act of Force Majeure); or (d) an ability to sell gas to a market at a more advantageous price; or (e) depletion of either Party s LNG in the LNG Facility. Force Majeure will include a curtailment or interruption on WEI Transmission South ( T- South ) resulting in a reduction in the supply of TGVI s firm supply or a declaration of Force Majeure by any transmission pipeline other than WEI that transports gas on a firm basis on TGVI s behalf; Initial Term has the meaning set out in section 2.2; Interruptible Delivery Service has the meaning set out in section 3.2 a); Interruptible Liquefaction Service has the meaning set out in section 6.2; Lapsed pro-rata means that the maximum rate for the remainder of a Day will be the firm rate times the number of hours remaining in the Day after a nomination becomes effective divided by twenty four; Liquefaction Commodity Charge has the meaning set out in section 14.1 b); LNG Facility is the LNG Storage facility at Mount Hayes near Ladysmith on Vancouver Island that is scheduled to be available for usage on the Commencement Date; LNG Service has the meaning set out in section 3.1; - 2 -

173 Schedule 1 LNG Service Gas means the quantity of gas used during liquefaction, storage and vaporization of gas at the LNG Facility; Primary LNG Service has the meaning set out in section 4.1; Secondary Term has the meaning set out in section 2.2(b); Storage Inventory is that volume of gas that TGVI records as being as being stored in the LNG Facility for TGI; Storage Year means a twelve month period, beginning on any April 1, which falls within the term of the Agreement except in the first year when Storage Year is the period from the Commencement Date to the next March 31; Summer Period means the period from April 16 to October 14; Supplementary LNG Service has the meaning set out in section 4.1; Supplementary Service Notice has the meaning set out in section 4.3; TGVI System means the TGVI transmission system; Transportation Fuel Gas means the quantity of fuel gas used on the TGVI system to deliver gas to the LNG Facility. V1 means the TGVI Eagle Mountain Compressor Station; Vaporization Commodity Charge has the meaning set out in section 14.1 c); Vaporization Demand Charge is the demand rate for providing vaporization service expressed in dollars per GJ per day; WEI means Westcoast Energy Inc.; and Winter Period means the period from October 15 to April TERM 2.1 The commencement date ( Commencement Date ) for the provision of LNG Service under this Agreement is the later of April 1, 2011 or such date notified by TGVI to TGI pursuant to section The term of this Agreement is for a period of 35 Storage Years and consists of two periods as follows: a) the Initial Term is the period of 20 Storage Years beginning on the Commencement Date; and b) the Secondary Term is the period of 15 Storage Years following the Initial Term

174 Schedule The term will automatically extend for consecutive one year periods until such time either Party provides the other Party with at least two years written notice of termination. Upon the provision of such notice this Agreement will terminate on the March 31 which is at least two years after the date on which the written notice is provided. 2.4 TGVI will provide 60 days written prior notice to TGI of the Commencement Date. TGVI will notify TGI in writing no later than November 1, 2008 of any expected change in the Commencement Date due to delay in commencement of construction of the LNG Facility. TGVI will also use reasonable efforts to notify TGI of any expected changes in the Commencement Date during the construction of the LNG Facility. 3. STORAGE AND DELIVERY SERVICE 3.1 During the term of this Agreement, TGVI will provide to TGI the following services (collectively the LNG Service ) at the LNG Facility: a) Firm Storage Service for the storage of gas in a liquid state at the LNG Facility based on the Firm Storage Capacity in each Storage Year pursuant to 4.2 and 4.4; b) Firm Liquefaction Service for the conversion of gas from a gaseous state to a liquid at a Firm Liquefaction Rate equal to 0.5% of the Firm Storage Capacity; and c) Firm Vaporization Service for the conversion of gas from a liquid state to a gaseous state at the Firm Vaporization Rate in each Storage Year pursuant to 4.2 and During the term of this Agreement, TGVI will provide to TGI the following services (collectively the Delivery Service ): a) Interruptible Delivery Service from V1 to the LNG Facility; and b) Firm Redelivery Service, with the place of redelivery being, as TGVI so elects from time to time, at either V1 or at the interconnection between the systems of TGI and WEI at Huntingdon. 3.3 TGVI may elect to provide Delivery Service either through either or a combination of displacement or physical transportation of gas to meet TGI s nominations. 4. CONTRACT LEVELS 4.1 In each Storage Year TGVI will provide LNG Service to TGI based on the a) Primary LNG Service levels pursuant to 4.2 and 4.3; and b) Supplemental LNG Service levels pursuant to

175 Schedule During the Initial Term, TGVI will make available to TGI the following minimum level of LNG Service ( Primary LNG Service) at the LNG Facility: a) Firm Storage Capacity of 1.0 Bcf; and b) Firm Vaporization Rate of 100 MMcfd. 4.3 TGVI may make a one time reduction to the Primary LNG Service levels it makes available to TGI during the Secondary Term by providing written notice to TGI at least two years prior the expiry of the Initial Term. The Primary LNG Service level in the Secondary Term may be decreased only to the degree TGVI reasonably forecasts it will require the capacity to serve customers connected on TGVI s transmission and distribution system. 4.4 In each Storage Year, TGVI may provide TGI with Supplemental LNG Service in addition to the Primary LNG Service by providing written notice to TGI at least two years before the commencement of a Storage Year, ("Supplementary Service Notice") specifying: a) the Storage Year to which the Supplementary Service Notice relates; b) the supplemental Firm Storage Capacity in the LNG Facility that will be available to TGI for that Storage Year; and c) the supplemental Firm Vaporization Rate of the Firm Vaporization Service that will be available to TGVI for that Storage Year. 4.5 The storage capacity and vaporization at the LNG Facility that TGVI makes available to TGI pursuant to each Supplementary Service Notice will be the storage capacity and vaporization, subject to section 4.4, that TGVI reasonably forecasts will be surplus to the requirements of the customers on TGVI's natural gas transmission and distribution system. 4.6 Unless otherwise agreed by the Parties, the Firm Storage Capacity specified in a Supplementary Service Notice may not be less than the quantity of gas that can be vaporized in six days nor greater than the quantity of gas that can be vaporized in twenty days, at the Firm Vaporization Rate specified in the same Supplementary Service Notice. 5. LNG SERVICE - Capacity 5.1 During each Storage Year TGVI will provide TGI with the Firm Storage Capacity for which TGI has contracted pursuant to section LNG SERVICE - Liquefaction 6.1 Subject to sections 11.1 b) and 11.5, on each Day TGVI will provide TGI with Firm Liquefaction Service at the lesser of (i) the Firm Liquefaction Rate, or (ii) the volume of gas that TGI delivers to TGVI, net of Transportation Fuel Gas and LNG Service Gas, on that Day

176 Schedule If TGVI has available liquefaction capacity that is not being utilized on a Day, then TGI may increase the liquefaction rate for its gas on that Day above the Firm Liquefaction Rate at no incremental cost. This additional liquefaction capacity will be made available as Interruptible Liquefaction Service. 6.3 In the event that more than one party contracting for LNG Service from TGVI wishes to increase their liquefaction rate above their firm rate and this results in a service constraint, the excess liquefaction capacity will be allocated pro-rata amongst such parties based on each party s respective Firm Liquefaction Rate. 7. LNG SERVICE - Vaporization 7.1 Subject to section 11.1 d) and section 11.5, on each Day upon TGI nominating to TGVI, TGVI will provide TGI with Firm Vaporization Service up to the Firm Vaporization Rate in effect for the applicable Storage Year. 7.2 If TGVI has available vaporization capacity that is not being utilized on a Day then, TGI may increase the vaporization rate for its gas on that Day above the Firm Vaporization Rate, provided TGVI is able to redeliver the gas to TGI. If later during that Day TGVI requires this service for its own requirements then the vaporization rate for TGI may be reduced to no less than the Firm Vaporization Rate for the remainder of the Day as provided in section In the event that more than one party contracting for LNG Service from TGVI wishes to increase their vaporization rate above their firm rate and this results in a service constraint, the excess vaporization capacity will be allocated pro-rata amongst such parties based on each party s respective LNG firm vaporisation rate. 7.4 TGVI is not be obligated to vaporize for TGI any amount of LNG greater than the amount of LNG TGI has in storage at the LNG Facility at that point in time. 8. DELIVERY SERVICE - Interruptible Delivery Service 8.1 Each Day TGI will deliver to TGVI at the inlet of V1 the quantity of gas that TGI specifies for delivery to, and liquefaction at, the LNG Facility on that Day plus the applicable LNG Service Gas and Transportation Fuel Gas. 8.2 Each Day TGVI will, subject to capacity constraints on the TGVI system, deliver to the LNG Facility the gas delivered to it by TGI on that Day, less the applicable allowance for Transportation Fuel Gas. 8.3 TGVI will make available to TGI sufficient Interruptible Delivery Service during the period from April 1 to October 31 of a Storage Year to deliver to the LNG Facility the quantity of gas that will fill, based on a gas being liquefied at the Firm Liquefaction Rate for that Storage Year, the Storage Capacity that TGI has contracted for that Storage Year, and the applicable LNG Service Gas. 8.4 The priority for the delivery of TGI gas to the LNG Facility will be the same as the priority of shippers using interruptible transportation on the TGVI System

177 Schedule This Agreement does not oblige TGVI to provide to Interruptible Delivery Service to the LNG Facility during the Winter Period. 8.6 TGVI will deduct the LNG Service Gas from the quantity of gas delivered to the LNG Facility to determine the quantity of gas that is liquefied and stored on behalf of TGI at the LNG Facility. 9. DELIVERY SERVICE - Firm Redelivery Service 9.1 Each Day TGVI will provide TGI with Firm Redelivery Service for the TGI gas vaporized at the LNG Facility on that Day pursuant to Article Firm redeliveries will be on a Lapsed Pro-rata basis. 10. NOMINATIONS 10.1 TGI will nominate for delivery to the LNG Facility at least one and one half (1 1/2) hours before TGVI must make its nominations on the WEI system nomination cycles and TGVI will notify TGI at least one hour before the time that TGVI must make its nominations of the authorized quantity of gas that TGVI will deliver to the LNG Facility for TGI TGVI will notify TGI at least one hour before the WEI evening or intra-day one ( ID-1 ) nomination cycle if TGI s previously authorized nomination for delivery to the LNG Facility has been modified. TGI s previously authorized nomination will not be modified by TGVI, without TGI s approval, after the ID-1 cycle TGI will nominate to TGVI the quantity of gas TGI requires to be vaporized and redelivered at least two hours prior to the time when TGI requires the gas during the Winter Period, and at least twelve hours prior during the Summer Period To the extent, pursuant to section 7.2, that TGVI wishes to reduce within a Day the quantity of gas authorized to be vaporized and redelivered to the Firm Vaporization Rate, TGVI will provide TGI with at least one hour s notice of any such reduction To the extent that TGI wishes to increase or decrease within a Day the quantity of gas that is authorized to be vaporized and redelivered, TGI will provide at least one hour s notice to TGVI prior to the change in the vaporization rate. To the extent that TGI wishes to increase the rate of vaporization above the Firm Vaporization Rate, such an increase must be authorized by TGVI before becoming effective Changes in the Firm Liquefaction and Interruptible Delivery Service, Firm Vaporization Rate and Firm Redelivery Service during a Day are subject to Lapsed Pro-rata Nominations by and confirmations between TGI and TGVI will be sent to the attention of: a) Nominations from TGI to TGVI to Operations Manager; and b) Confirmation from TGVI to TGI to Manager, Midstream

178 Schedule 1 Either Party may change the contact specified above by giving the other Party notice of such change Nominations and confirmations will be in electronic form as established from time to time by TGVI If the WEI nomination cycles, or their names, change, the Parties will amend this Agreement to accord with the revised nomination cycles. 11. PERFORMANCE OBLIGATIONS 11.1 Subject to section 11.2, TGVI has the following obligations to TGI during the term of this Agreement: a) To make sufficient available Interruptible Delivery Service to the LNG Facility for the Summer Period of a Storage Year to meet the obligation as set out in section 8.3; b) To provide Firm Liquefaction Service at the Firm Liquefaction Rate each Day of the Storage Year, except on the Days when planned maintenance is being performed by TGVI for the liquefaction component of the LNG Facility; c) To provide during each Storage Year the capacity in the LNG Facility to store up to the Firm Storage Capacity contracted by TGI for that Storage Year; d) To provide during each Storage Year Firm Vaporization Service at the Firm Vaporization Rate contracted by TGI for that Storage Year and to provide Firm Redelivery Service for the TGI gas vaporized from the LNG Facility to TGI, except on the Days when planned maintenance is being performed by TGVI on the vaporization component of the LNG Facility In each Storage Year, TGVI will use reasonable commercial efforts to schedule planned maintenance such that planned maintenance in any Storage Year does not exceed a cumulative period of 60 days for each of the vaporization and liquefaction components of the LNG Facility and shall only occur during: a) May 1 to September 30 with respect to the vaporization component; and b) December 1 to February 28 with respect to the liquefaction component. Prior to April 1 of each year, TGVI will provide TGI with a forecast schedule of planned maintenance to take place over the next 12 months In each Storage Year, if TGVI is unable to meet its obligations to TGI as set out in section 11.1, TGVI will provide TGI with a demand charge credit as set out below: a) to the extent that TGVI has not provided sufficient Interruptible Delivery Service and Firm Liquefaction Service, or otherwise credited TGI s Storage Inventory, such that TGI s Storage Inventory on 1 November is equal to lower of the Firm Storage Capacity or the total volume nominated by TGI, the demand charge - 8 -

179 Schedule 1 credit will be equal to the to the amount obtained by multiplying the demand charges otherwise payable in that Storage Year pursuant to 13.1 and 13.3 by the quantity that remains unfilled; and b) to the extent that TGVI is not required to provide a demand charge credit pursuant to 11.3(a) and TGVI is unable to provide Firm Redelivery Service to match TGI s nominations, up to the Firm Vaporization Rate, the demand charge credit will be equal to the amount obtained by multiplying the annual Vaporization Demand Charge provided in Schedule A by the quantity of gas not redelivered. TGI's sole remedy, and TGVI's sole obligation, for the failure of TGVI to perform its obligations under this Agreement are the provision of demand charge credits as set out above If there is a shortfall in vaporization or liquefaction capability at the LNG Facility on any Day the shortfall will be allocated between TGI, other parties contracting for service at the LNG Facility, and TGVI, on a pro rata basis In any Storage Year, TGVI s obligations are limited to crediting TGI s Storage Inventory account up to the Firm Storage Capacity for which TGI has contracted the case of nominations for liquefaction, and redelivering gas to TGI in the case of nominations for vaporization. Nothing in this Agreement will require TGVI to operate its transmission facilities or require service from the LNG Facility to match the nominations from TGI on the Day. 12. FORCE MAJEURE 12.1 Except for TGI s obligation to make payments under this Agreement, if either Party is rendered unable, in whole or in part, by Force Majeure to carry out its obligations under this Agreement, then upon such Party s giving notice of the particulars of such Force Majeure to the other Party as soon as reasonably possible (with such notice to be confirmed in writing), the obligations of the Party giving such notice, from the inception of the Force Majeure, will be suspended and excused during the continuance of any inability so caused. The obligations of the affected Party will be suspended and excused for such time only to the extent they are affected by such Force Majeure. The cause of the Force Majeure will be remedied by the affected Party with all reasonable diligence and dispatch. 13. DEMAND CHARGES 13.1 During the Initial Term, each month, TGI will pay to TGVI the sum of the following amounts: a) In respect of the Primary LNG Service, a monthly demand charge equal to $1,002,200; and b) In respect of the Supplemental LNG Service, an amount equal to one twelfth of the sum of: - 9 -

180 Schedule 1 i) the amount obtained by multiplying the Capacity Demand Charge, as set out in Schedule A, by the supplemental Storage Capacity contracted by TGI for that Storage Year pursuant to 4.4; and ii) the amount obtained by multiplying the Vaporization Demand Charge, as set out in Schedule A, by the supplemental Firm Vaporization Rate contracted by TGI in that Storage Year pursuant to If the Storage Year in the initial year of the term of this Agreement is less than 12 months such that TGI is unable to fill its Firm Storage Capacity before November 1 of that year, then a reduction in the monthly demand charge for the Primary LNG Service for the initial year will determined based volume that TGI was unable to fill Following the Initial Term, in respect of the Primary LNG Service and the Supplemental LNG Service, TGI will pay to TGVI a monthly demand charge based on an allocation of TGVI s annual revenue requirement associated with the LNG Facility, as approved by the BCUC from time to time. The allocation to TGI will be determined from year to year based on Firm Storage Capacity and Firm Vaporization Rate contracted by TGI in that year pursuant to clause COMMODITY CHARGES 14.1 In each month, TGI will pay to TGVI the following commodity charges: a) an amount equal to the Coloured Gas Tax Commodity charge taxes payable by TGVI in respect of TGI gas delivered to the LNG Facility under the Motor Fuel Tax Act (British Columbia); and any excise or other taxes payable by TGVI in respect of TGI gas delivered to the LNG Facility in that month ( Coloured Gas Tax Commodity Charge ); and b) an amount obtained by multiplying the Liquefaction Commodity Charge, as set out in Schedule A, by the amount of TGI gas liquefied at the LNG Facility in that month. The Liquefaction Commodity Charge will be adjusted from period to period to reflect changes in the applicable BC Hydro rate per kwh. c) an amount obtained by multiplying the Vaporization Commodity Charge, as set out in Schedule A, by the amount of TGI gas vaporized at the LNG Facility in that month. The Vaporization Commodity Charge will be adjusted from period to period to reflect changes in the applicable BC Hydro rate per kwh. 15. FUEL GAS 15.1 TGVI will on a daily basis provide TGI with an estimate of Transportation Fuel Gas and LNG Service Gas TGVI on a monthly basis will reconcile the estimated Transportation Fuel Gas with the actual usage and provide TGI with a summary. TGI and TGVI will cooperate to ensure that any imbalances are kept as close to zero as possible

181 Schedule TGVI on an annual basis will reconcile the estimated LNG Service Gas with actual usage and provide TGI with a summary. TGI and TGVI will cooperate to ensure that any imbalances are kept as close to zero as possible 16. BILLING 16.1 TGVI will provide TGI by the 15th of each month beginning in the month following the commencement of the term of this Agreement with an invoice relating to the preceding month for: a) the monthly demand charge for the Primary LNG Service contracted by TGI; b) the demand charge for the month for Supplementary LNG Service contracted for by TGI, setting out the Capacity Demand Charge and the Vaporization Demand Charge for the month at rates set out in Schedule A; c) the Coloured Gas Tax Commodity Charge for the month setting out the rate for the commodity charge for the month and the quantity of TGI gas delivered to the LNG Facility in the month; d) the Liquefaction Commodity Charge for the month setting out the rate per GJ as set out in Schedule A and the quantity of TGI gas liquefied; e) the Vaporization Commodity Charge for the month setting out the rate per GJ per day as set out in Schedule A and the quantity of TGI gas vaporized; and f) any demand charge credits pursuant to section In addition to the invoice, TGVI will provide TGI with a summary for the preceding month setting out: a) TGI s Storage Inventory at the beginning and end of the month; b) the quantity of gas delivered to the LNG Facility in the month, c) the amount of gas liquefied and the amount of gas vaporized by Day for TGI, d) the amount of gas redelivered to TGI by TGVI by Day and delivery point; and. e) Transportation Fuel Gas and LNG Services Gas TGI will pay TGVI the amount associated with the invoice on the 25th of the month the invoice is received or ten days after the receipt of the invoice, whichever is later In the event that TGI is late in paying the invoice then TGVI will assess TGI and TGI will pay to TGVI a late payment fee equal to the current prime interest rate charged by the Main Branch of the Toronto-Dominion Bank in Vancouver, British Columbia, to its most creditworthy commercial customers, plus 4%, per annum paid on a daily basis

182 Schedule NOTICES 17.1 Except as may be expressly provided otherwise in this Agreement, any notice, request, authorization, direction, or other communication under this Agreement will be made given in writing and will be delivered in person, or by facsimile transmission, properly addressed to the intended recipient as follows: a) If to TGI: Terasen Gas Inc Fraser Highway Surrey, B.C. V4N 0E8 Attention: Vice President, Gas Supply and Transmission Facsimile: b) If to TGVI: Terasen Gas (Vancouver Island) Inc Fraser Highway Surrey, B.C. V4N 0E8 Attention: Vice President, Finance and Regulatory Affairs Facsimile: Either Party may change its address specified above by giving the other Party notice of such change in accordance with this section REGULATORY AUTHORITY 18.1 This Agreement is subject to all rules, regulations, orders and other requirements of each governmental and regulatory authority having jurisdiction over this Agreement, the Parties or either of them, including without limitation, the BCUC This Agreement is subject to the approval of the BCUC. 19. GOVERNING LAW 19.1 This Agreement and the respective rights and duties of the Parties arising out of this Agreement will be governed by and construed, enforced and performed in accordance with the laws of the Province of British Columbia. 20. EFFECT OF WAIVER OR CONSENT 20.1 No waiver or consent by either Party, expressed or implied, or any breach or default by the other Party in the performance of any of such other Party s obligations under this Agreement will operate or be construed as a waiver or consent to any other breach or default hereunder. Failure of a Party to complain of any act of the other Party or to declare the other Party in breach or default with respect to this Agreement, irrespective of how long that failure continues, does not constitute a waiver by the Party of any of its rights with respect to that breach or default. 21. HEADINGS 21.1 The headings for the sections of this Agreement are for convenience of reference only and in no way affect the meaning or interpretation of any of the provisions of this Agreement

183 Schedule SEVERABILITY 22.1 Except as otherwise stated in this Agreement, any provision or section declared or rendered unlawful by a court of law or regulatory agency with jurisdiction over this Agreement, the Parties or either of them, or deemed unlawful because of statutory change, will thereupon be deemed to have been severed from this Agreement and will not otherwise affect the lawful obligations that arise under other provisions of this Agreement. 23. ASSIGNMENT 23.1 Subject to the provisions of this section 23.1, this Agreement will enure to and be binding upon the respective successors and permitted assigns of the Parties. Neither Party may assign this Agreement without the prior written consent of the other Party, which consent will not be unreasonably withheld, provided, that either Party may assign its interest under this Agreement (a) to any entity that, directly or indirectly, through one or more intermediaries, controls, or is controlled by, or is under common control with such Party, (b) to any entity into which it consolidates or merges or (c) as security to the holder of any indebtedness, present or future, of such Party, without the prior written approval of the other Party, but no such assignment will operate to relieve the assigning Party of any of its obligations under this Agreement. Any Party s transfer or assignment in violation of this section 23.1 will be void. 24. RESPONSIBILITY FOR DAMAGE 24.1 As between the Parties, TGI will be deemed to be in exclusive control and possession of gas which is the subject of this Agreement and will be responsible for any damage or injury caused thereby prior to the point at which TGVI receives gas pursuant to this Agreement and after the point TGVI redelivers gas pursuant to this Agreement. As between the Parties, TGVI will be deemed to be responsible for any damage or injury or damage caused thereby after the point at which TGVI receives gas pursuant to this Agreement and prior to the point at which TGVI redelivers gas pursuant to this Agreement. 25. WARRANTY 25.1 TGI warrants that (i) it has good title to all gas to be received to be received by TGVI under this Agreement, (ii) it has the right to deliver such gas, and (iii) that such gas is free from all liens and adverse claims, and agrees, if notified by TGVI, to indemnify TGVI from and against all suits, actions, debts, accounts, damages, costs, losses, and expenses (including reasonable lawyers fees) arising from or out of any adverse legal claims of any and all persons and entities regarding title to such gas. TGI agrees to pay, or cause to be paid or delivered in kind to the parties entitled thereto, all royalties, overriding royalties or like charges against such gas or the value thereof

184 Schedule TERMINATION 26.1 If either Party is at any time in material breach of or default under this Agreement (the Defaulting Party ), the other Party (the terminating Party ) will have the right to terminate this Agreement by giving the Defaulting Party written notice of such termination. Such termination will be effective upon the Defaulting Party s receipt of such notice of termination pursuant to this section For the purposes of this section 26.1, a Party will be deemed to be in material breach if or default under this Agreement if such Party: a) fails to cure any material breach under this Agreement by such Party prior to the later of (i) the expiration of thirty days after the Terminating Party gives the Defaulting Party written notice of the breach or default; and (ii) the date upon which the Terminating Party gives the Defaulting Party written notice of termination; b) is unable to meet its obligations as they become due or such Party s liabilities exceed its assets in the aggregate; or c) makes a general assignment of substantially all of its assets for the benefits of its creditors, files a petition of bankruptcy, commences, authorizes or acquiesces in the commencement of a proceeding or cause under any bankruptcy, insolvency or similar law for the protection of creditors or have such petition filed or proceeding commenced against it, or seeks other relief under any applicable insolvency laws. In no event will either Party incur any liability (whether for lost revenues or lost profits or otherwise) as a result of any termination of this Agreement pursuant to this section Either party shall have the right to terminate this Agreement should the LNG Facility not proceed to construction by giving written notice of termination to the other party not later than November 1, All rights and remedies of either Party under this Agreement and at law and in equity will be cumulative and not mutually exclusive and the exercise by one Party of one right or remedy will not be deemed a waiver of any other right or remedy available to that Party. Nothing contained in any provision of this Agreement will be construed to limit or exclude any right or remedy of either Party (arising on account of the breach or default by the other Party or otherwise) now or hereafter existing under any other provision of this Agreement. 27. WAIVER OF CERTAIN DAMAGES 27.1 In no other event will either Party be liable to the other Party for consequential, incidental, punitive, special, exemplary or indirect damages, in tort, strict liability, warranty, contract, equity or otherwise

185 Schedule DISPUTE RESOLUTION 28.1 All disputes arising under or relating to this Agreement, except only disputes with respect to which the BCUC has jurisdiction, which the BCUC is prepared to exercise, shall, after the parties have attempted in good faith to settle the dispute between themselves, be submitted to and finally settled by arbitration under the Commercial Arbitration Act. The arbitration will take place in Vancouver, British Columbia before a single arbitrator and will be administered by the British Columbia Commercial Arbitration Centre ( BCICAC ) in accordance with its Procedures for Cases under the BCICAC Rules. 29. ENTIRE AGREEMENT 29.1 This Agreement constitutes the entire Agreement between the Parties relating to the subject matter contemplated by this Agreement. There are no prior or contemporaneous agreements or representations (whether written or oral) affecting such subject matter. No amendment, modification or change to this Agreement will be enforceable, except as specifically provided for in this Agreement, unless reduced to writing and hereafter signed (which may be done by facsimile) by both Parties. IN WITNESS WHEREOF, the Parties have caused this Agreement to be duly executed by their authorized representatives as of the date first written above. Terasen Gas Inc. Terasen Gas (Vancouver Island) Inc. By Name: Jan Marston By Name: Randy Jespersen Title: Vice President, Gas Supply & Transmission Title: President

186 Schedule 1 SCHEDULE A SCHEDULE OF DEMAND RATES AND COMMODITY CHARGES ANNUAL DEMAND CHARGES FOR SUPPLEMENTARY LNG SERVICE Capacity Demand Charge Vaporization Demand Charge $2.79 /GJ per GJ of Storage Capacity $83.84 /GJ/Day COMMODITY CHARGES FOR PRIMARY AND SUPPLEMENTARY LNG SERVICE Vaporization Commodity Charge (estimated) $0.09/GJ Liquefaction Commodity Charge (estimated) $0.35/GJ * Electrical Commodity Charge is based on BC Hydro s Transmission Service Stepped Rate Schedule 1823, at the current rate of cents per kwh effective February 1, Future charges will be adjusted to reflect changes in BC Hydro s rate

187 Appendix D TGVI DEMAND

188 APPENDIX D - TGVI Demand Forecast Details (excluding ICP and JV) TGVI Year-Ending Accounts by Rate Class TGVI RGS 81,732 85,030 88,348 92,056 95,686 99, , , , , , , , , ,057 SCS1 4,058 4,153 4,267 4,376 4,474 4,543 4,643 4,733 4,821 4,905 4,979 5,046 5,112 5,172 5,230 SCS2 1,815 1,855 1,905 1,950 1,997 2,068 2,113 2,153 2,195 2,234 2,267 2,296 2,322 2,346 2,368 LCS1 1,505 1,539 1,580 1,617 1,654 1,715 1,752 1,784 1,816 1,843 1,867 1,887 1,906 1,924 1,942 LCS AGS ,009 1,022 1,035 LCS HLF ILF CRxx Total 90,624 94,124 97, , , , , , , , , , , , ,562 Percent Change in Year-end Accounts by Rate Class TGVI RGS SCS SCS LCS LCS AGS LCS HLF ILF CRxx Total TGVI Annual Use Rate by Rate Class (GJ/Yr) RGS SCS SCS LCS LCS2 2, , , , , , , , , , , , , , ,342.9 AGS 1, , , , , , , , , , , , , , ,392.9 LCS3 17, , , , , , , , , , , , , , ,951.0 HLF n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a ILF n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a CRxx n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a TGVI Annual Demand by Rate Class (TJ) TGVI RGS 4,615 4,806 4,997 5,199 5,411 5,627 5,829 6,014 6,199 6,378 6,538 6,683 6,822 6,947 7,071 SCS SCS LCS1 1,350 1,378 1,411 1,446 1,480 1,535 1,568 1,597 1,625 1,650 1,671 1,689 1,706 1,722 1,738 LCS2 1,303 1,329 1,361 1,392 1,425 1,478 1,511 1,541 1,571 1,599 1,627 1,646 1,666 1,685 1,704 AGS 1,113 1,138 1,163 1,193 1,218 1,241 1,267 1,291 1,313 1,335 1,357 1,375 1,393 1,411 1,429 LCS3 2,334 2,370 2,423 2,477 2,549 2,634 2,702 2,753 2,804 2,855 2,906 2,957 2,991 3,025 3,076 HLF ILF CRxx Total Firm Demand 11,943 12,267 12,622 12,995 13,391 13,849 14,230 14,566 14,902 15,222 15,519 15,783 16,023 16,246 16,484 TGVI Design Day Demand 2007/ / / / / / / / / / / / / / /22 All Customer Classes Appendix D - Page 1

189 APPENDIX D - TGVI Demand Forecast Details (excluding ICP and JV) TGVI Year-Ending Accounts by Rate Class TGVI RGS SCS1 SCS2 LCS1 LCS2 AGS LCS3 HLF ILF CRxx Total Percent Change in Year-end Accounts by Rate Class TGVI RGS SCS1 SCS2 LCS1 LCS2 AGS LCS3 HLF ILF CRxx Total TGVI Annual Use Rate by Rate Class (GJ/Yr) RGS SCS1 SCS2 LCS1 LCS2 AGS LCS3 HLF ILF CRxx Note: The forecast details shown in this Appendix include some variations 127, , , , , , , , , ,074 from the forecast details appended to the 2006 TGVI Resource Plan: 5,288 5,344 5,397 5,456 5,516 5,576 5,642 5,708 5,778 5,847 1 Updated to include rebased total customers as 2,389 2,413 2,434 2,456 2,481 2,506 2,536 2,567 2,598 2,629 identified in the 2006 Settlement Update. 1,960 1,978 1,994 2,013 2,032 2,051 2,071 2,092 2,113 2,134 2 Updated to include 2006 mid-year actuals as presented in the 2006 Settlement Update. 1,048 1,060 1,071 1,083 1,096 1,109 1,122 1,135 1,148 1,161 3 Updated to reflect the dissolution of the CRxx rate class For annual demand, the first five years of forecast builds on monthly average customer and use, while long range forecast shows year-end customer data Forecast methodology remains consistent with that described in 138, , , , , , , , , ,887 the TGVI 2006 Resource Plan , , , , , , , , , , , , , , , , , , , , , , , , , , , , , ,951.0 n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a TGVI Annual Demand by Rate Class (TJ) TGVI RGS SCS1 SCS2 LCS1 LCS2 AGS LCS3 HLF ILF CRxx Total Firm Demand TGVI Design Day Demand All Customer Classes ,194 7,321 7,436 7,567 7,702 7,844 7,995 8,152 8,317 8, ,754 1,770 1,785 1,802 1,819 1,836 1,854 1,872 1,891 1,910 1,720 1,736 1,752 1,773 1,794 1,815 1,836 1,857 1,878 1,899 1,447 1,463 1,479 1,495 1,513 1,531 1,549 1,567 1,585 1,603 3,110 3,161 3,212 3,246 3,297 3,348 3,399 3,450 3,501 3, ,701 16,939 17,160 17,390 17,643 17,903 18,174 18,454 18,741 19, / / / / / / / / / / Appendix D - Page 2

190 Appendix E GAS MARKET INFORMATION

191 Page: 1 of 6 GLJ Petroleum Consultants PRODUCT PRICE AND MARKET FORECASTS FOR THE CANADIAN OIL AND GAS INDUSTRY Quarterly Update January 1, 2007 Prepared by Leonard Herchen, P.Eng. 4100, Third Avenue S.W., Calgary, Alberta, Canada T2P 4H2 Internet: GLJ Petroleum Consultants

192 Page: 2 of 6 January 1, 2007 GLJ Petroleum Consultants has prepared the enclosed price and market forecasts after a comprehensive review of information available through to December Information sources include numerous government agencies, industry publications, Canadian oil refiners and natural gas marketers. The accuracy of all factual data, from all sources has been accepted as represented without detailed investigation by GLJ Petroleum Consultants. The forecasts presented herein are based on an informed interpretation of currently available data. While they are considered reasonable at this time, users of these forecasts should understand the inherent high uncertainty in forecasting any commodity or market. These forecasts will be revised periodically as market, economic and political conditions change. These future revisions may be significant. GLJ Petroleum Consultants

193 Page: 3 of 6 GLJ PETROLEUM CONSULTANTS PRODUCT PRICE AND MARKET FORECASTS FOR THE CANADIAN OIL AND GAS INDUSTRY January 1, 2007 GLJ Petroleum Consultants has completed a quarterly update of our commodity price forecasts as presented on the attachments. Revisions in the forecasts reflective of current market conditions have been incorporated. A summary of near-term forecasts follows: NATURAL GAS PRICES October 1, 2006 January 1, 2007 Calendar Year Calendar Year Henry Hub Gas Price - ($US/MMBTU) Chicago 30 Day Spot Gas Price ($US/MMBTU) Sumas 30 Day Spot Gas Price - ($US/MMBTU) AECO-C 30 Day Spot Gas Price ($Cdn/MMBTU) Average Alberta Plant-Gate Gas Price - ($Cdn/MMBTU) Aggregator Plant-Gate Gas Price - ($Cdn/MMBTU) B.C. 30 Day Spot Plant-Gate Gas Price - ($Cdn/MMBTU) CRUDE OIL PRICES October 1, 2006 January 1, 2007 Calendar Year Calendar Year Cushing Price - ($US/BBL) Light, Edmonton Price - ($Cdn/BBL) GLJ Petroleum Consultants

194 Table 1 GLJ Petroleum Consultants Crude Oil and Natural Gas Liquids Price Forecast Effective January 1, 2007 NYMEX WTI Near Light, Sweet Bank of Month Futures Contract Brent Blend Crude Oil Bow River Crude Oil Heavy Crude Oil Medium Crude Oil Alberta Natural Gas Liquids Canada Crude Oil at Crude Oil (40 API, 0.3%S) Stream Quality Proxy (12 API) (29 API, 2.0%S) (Then Current Dollars) Average Noon Cushing Oklahoma FOB North Sea at Edmonton at Hardisty at Hardisty at Cromer Edmonton Exchange Constant Then Constant Then Constant Then Constant Then Constant Then Constant Then Spec Edmonton Edmonton Pentanes Inflation Rate 2007 $ Current 2007 $ Current 2007 $ Current 2007 $ Current 2007 $ Current 2007 $ Current Ethane Propane Butane Plus Year % $US/$Cdn $US/bbl $US/bbl $US/bbl $US/bbl $Cdn/bbl $Cdn/bbl $Cdn/bbl $Cdn/bbl $Cdn/bbl $Cdn/bbl $Cdn/bbl $Cdn/bbl $Cdn/bbl $Cdn/bbl $Cdn/bbl $Cdn/bbl n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a (e) n/a Q Q Q Q Full Year %/yr %/yr %/yr %/yr %/yr %/yr Escalate at 2.0 % per year Historical futures contract price is an average of the daily settlement price of the near month contract over the calendar month. Revised 1-Jan-07 GLJ Petroleum Consultants Page: 4 of 6

195 Table 2 GLJ Petroleum Consultants Natural Gas and Sulphur Price Forecast Effective January 1, 2007 NYMEX Futures Contract Midwest Alberta Plant Gate Saskatchewan Plant Gate British Columbia Alberta Last 3 Day Price Chicago AECO/NIT Spot Spot Sulphur Sulphur Constant Then Then Then Constant Then Westcoast Spot FOB at Plant 2007 $ Current Current Current 2007 $ Current ARP Aggregator Alliance SaskEnergy Spot Sumas Spot Station 2 Plant Gate Vancouver Gate Year $US/mmbtu $US/mmbtu $US/mmbtu $Cdn/mmbtu $/mmbtu $/mmbtu $/mmbtu $/mmbtu $/mmbtu $/mmbtu $/mmbtu $US/mmbtu $/mmbtu $/mmbtu $US/LT $Cdn/LT n/a n/a n/a n/a n/a n/a n/a n/a n/a (e) Q Q Q Q Full Year %/yr +2.0%/yr +2.0%/yr %/yr Escalate at 2.0 % per year +2.0%/yr Unless otherwise stated, the gas price reference point is the receipt point on the applicable provincial gas transmission system known as the plant gate. The plant gate price represents the price before raw gas gathering and processing charges are deducted. AECO-C Spot refers to the one month price averaged for the year. Historical futures contract price is an average of the daily settlement price over the last 3 days of the near month contract. Revised 1-Jan-07 GLJ Petroleum Consultants Page: 5 of 6

196 Page: 6 of 6 Oil Price History and Forecast Exchange Rate ($US/$Cdn) $/Barrel $US/$Cdn Light Edmonton WTI ($US/Bbl) Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan Natural Gas Price History and Forecast Exchange Rate ($US/$Cdn) $/ MMbtul $US/$Cdn AECO-C ($Cdn/MMbtu) Henry Hub ($US/MMbtu) 0.00 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan GLJ Petroleum Consultants

197 Appendix E: Regional Gas Supply Outlook Avoided Market Area Storage Costs Market Area Storage Cost (Jackson Prairie) 1 Source: Natural Gas Price Forecast from GLJA [Jan 2007], Storage and Transport Rates: Gas Supply, Terasen Gas 2 Calendar Year RATE CHARGES 5 Sumas Summer Price ($US/MMBtu) $ 6.64 $ 6.86 $ 7.00 $ 7.17 $ 7.33 $ 7.50 $ 7.67 $ 7.82 $ 7.98 $ 8.14 $ 8.30 $ 8.46 $ 8.63 $ 8.81 $ 8.98 $ 9.16 $ 9.35 $ 9.53 $ 9.72 $ 9.92 $ NWP 15 day storage charge ($US/MMBtu) * $ 3.10 $ 3.10 $ 3.10 $ 3.10 $ 3.10 $ 3.10 $ 3.10 $ 3.10 $ 3.10 $ 3.10 $ 3.10 $ 3.10 $ 3.10 $ 3.10 $ 3.10 $ 3.10 $ 3.10 $ 3.10 $ 3.10 $ 3.10 $ NWP Injection/Withdrawal Fuel Rate (%) 0.58% 0.58% 0.58% 0.58% 0.58% 0.58% 0.58% 0.58% 0.58% 0.58% 0.58% 0.58% 0.58% 0.58% 0.58% 0.58% 0.58% 0.58% 0.58% 0.58% 0.58% 8 NWP TF-1 Transport Demand Charge ($US/MMBtu) $ 0.39 $ 0.39 $ 0.39 $ 0.39 $ 0.39 $ 0.39 $ 0.39 $ 0.39 $ 0.39 $ 0.39 $ 0.39 $ 0.39 $ 0.39 $ 0.39 $ 0.39 $ 0.39 $ 0.39 $ 0.39 $ 0.39 $ 0.39 $ NWP Transport Fuel Rate (%) 1.92% 1.92% 1.92% 1.92% 1.92% 1.92% 1.92% 1.92% 1.92% 1.92% 1.92% 1.92% 1.92% 1.92% 1.92% 1.92% 1.92% 1.92% 1.92% 1.92% 1.92% 11 Storage Deliverability Required Mcf/d 150, , , , , , , , , , , , , , , , , , , , , STORAGE CHARGE ($US 000) 14 Demand: NWP Storage Charge for 150MMcf/d x 15 days $ 5,335 $ 7,113 $ 7,113 $ 7,113 $ 7,113 $ 7,113 $ 7,113 $ 7,113 $ 7,113 $ 7,113 $ 7,113 $ 7,113 $ 7,113 $ 7,113 $ 7,113 $ 7,113 $ 7,113 $ 7,113 $ 7,113 $ 7,113 $ 7, Fuel: Injection Fuel Charge for 5-day (15-day first year) $ 88 $ 30 $ 31 $ 32 $ 33 $ 33 $ 34 $ 35 $ 35 $ 36 $ 37 $ 38 $ 38 $ 39 $ 40 $ 41 $ 41 $ 42 $ 43 $ 44 $ TRANSPORT CHARGE ($US 000) 9 months charge first year 18 Demand: NWP TF-1@40% Transport Charge for 365 day $ 6,532 $ 8,710 $ 8,710 $ 8,710 $ 8,710 $ 8,710 $ 8,710 $ 8,710 $ 8,710 $ 8,710 $ 8,710 $ 8,710 $ 8,710 $ 8,710 $ 8,710 $ 8,710 $ 8,710 $ 8,710 $ 8,710 $ 8,710 $ 8, Fuel 1: NWP Transport for 5-day Injection (15-day first year) $ 293 $ 101 $ 103 $ 105 $ 108 $ 110 $ 113 $ 115 $ 117 $ 119 $ 122 $ 124 $ 127 $ 129 $ 132 $ 135 $ 137 $ 140 $ 143 $ 146 $ Fuel 2: NWP Transport for 5-day Withdrawal (2-day first year) $ 39 $ 101 $ 103 $ 105 $ 108 $ 110 $ 113 $ 115 $ 117 $ 119 $ 122 $ 124 $ 127 $ 129 $ 132 $ 135 $ 137 $ 140 $ 143 $ 146 $ TOTAL STORAGE & TRANSPORT 25 ($US 000) $ 12,287 $ 16,054 $ 16,059 $ 16,065 $ 16,070 $ 16,076 $ 16,081 $ 16,087 $ 16,092 $ 16,097 $ 16,103 $ 16,108 $ 16,114 $ 16,120 $ 16,126 $ 16,132 $ 16,138 $ 16,144 $ 16,151 $ 16,157 $ 16, ($Cdn 000) applying Fx = 0.85 $Cdn/$US $ 14,455 $ 18,887 $ 18,893 $ 18,899 $ 18,906 $ 18,913 $ 18,919 $ 18,925 $ 18,932 $ 18,938 $ 18,944 $ 18,951 $ 18,958 $ 18,965 $ 18,972 $ 18,979 $ 18,986 $ 18,993 $ 19,001 $ 19,009 $ 19, Please note, for the Year 2011: Only 9 months of demand charges are applied as Storage Year starts 1 April Please note Conversion Factors: GJ/MMBtu Full 15 day injection commodity & fuel charge is applied to fill storage in the first year. Subsequent years, only 5 day injection is applied to correspond to 5 days of withdrawal each year. GJ/Mcf days withdrawal charge is applied in year one, as there are only two winter months (November & December) STORAGE COST: PRESENT VALUE (Year 2010 $) NWP TF-1@40% 34 Evaluation Period (Years) Discount Rate 6.2% 6.2% 10.0% 10.0% 36 STORAGE CHARGE ($US 000) 37 Demand: NWP Storage Charge for 150MMcf/d x 15 days $ 50,752 $ 76,002 $ 40,528 $ 54, Fuel: Injection Fuel Charge for 5-day (15-day first year) $ 294 $ 438 $ 241 $ TRANSPORT CHARGE ($US 000) 40 Demand: NWP TF-1@40% Transport Charge for 365 day $ 62,146 $ 93,066 $ 49,627 $ 66, Fuel 1: NWP Transport for 5-day Injection (15-day first year) $ 972 $ 1,450 $ 798 $ 1, Fuel 2: NWP Transport for 5-day Withdrawal (2-day first year) $ 747 $ 1,225 $ 588 $ TOTAL STORAGE & TRANSPORT 44 ($US 000) $ 114,910 $ 172,181 $ 91,781 $ 123, ($Cdn 000) applying Fx = 0.85 $Cdn/$US $ 135,189 $ 202,566 $ 107,978 $ 145, Levelized Storage Year Cost ($Cdn 000) starting in 2011.** $ 18,944 $ 18,956 $ 18,948 $ 18, Unit Charge based on period & discount rate 6.2% 6.2% 10% 10% n 49 Fixed unit charge ($Cdn/GJ) $ $ $ $ unit charge NPV = where n is the period (12 year or 22 year) and discount rate is 6.2% or 10% 50 Variable unit charge ($Cdn/GJ) $ 1.99 $ 2.08 $ 2.01 $ 2.07 ( 1 + discount rate ) i 51 Unit charge ($Cdn/GJ) $ $ $ $ i = Data Source: Natural Gas Price Forecast from GLJA [Oct 2006] Transport Rate on Northwest Pipe posted * Storage Rate on NWP of $US 3.10/MMBtu = (($ x capacity x 365-days + $ x deliverability x 365-days)/capacity) 57 where: deliverability = 150,000 MMscf/d; storage days = 15 days; capacity = deliverability x storage days. 58 capacity charge of $ and demand charge of $ as per expansion rate filed by Northwest Pipeline to FERC on July 13, 2006; reference to Docket No. CP ** Levelized Cost corrected for storage year; i.e. 9/12 charge adjustment removed for the first year. Page 1

198 Appendix E: Regional Gas Supply Outlook Avoided Market Area Storage Costs WEI Transport Cost: Summary of T-South Cost with mitigation payments (2011 onwards) 1 From GLJA [Jan 2006] one year create summer/winter pricing (use forward curve relationship).94% summer and 108% winter (forward market over forward 3 years) 2% excalation as per GLJA 2 Calendar Year GLJA AECO One Year ($Cdn/MMBtu) $ 7.85 $ 8.15 $ 8.30 $ 8.50 $ 8.70 $ 8.90 $ 9.10 $ 9.28 $ 9.47 $ 9.66 $ 9.85 $ $ $ $ $ $ $ $ $ $ GLJA AECO One Year ($US/MMBtu) using GLGA Fx 0.87 US/Cdn $ 6.83 $ 7.09 $ 7.22 $ 7.40 $ 7.57 $ 7.74 $ 7.92 $ 8.08 $ 8.24 $ 8.40 $ 8.57 $ 8.74 $ 8.92 $ 9.09 $ 9.28 $ 9.46 $ 9.65 $ 9.84 $ $ $ GLJA AECO One Year ($Cdn/GJ) $ 7.62 $ 7.91 $ 8.05 $ 8.25 $ 8.44 $ 8.63 $ 8.83 $ 9.00 $ 9.18 $ 9.37 $ 9.56 $ 9.75 $ 9.94 $ $ $ $ $ $ $ $ GLJA AECO Storage Year ($Cdn/GJ) $ 7.69 $ 7.94 $ 8.10 $ 8.29 $ 8.49 $ 8.68 $ 8.87 $ 9.05 $ 9.23 $ 9.42 $ 9.60 $ 9.80 $ 9.99 $ $ $ $ $ $ $ $ Station-2 Winter Price = 108% Storage Year ($Cdn/GJ) $ 8.30 $ 8.58 $ 8.75 $ 8.96 $ 9.17 $ 9.38 $ 9.58 $ 9.77 $ 9.97 $ $ $ $ $ $ $ $ $ $ $ $ Station-2 Summer Price = 94% Storage Year ($Cdn/GJ) $ 7.23 $ 7.47 $ 7.61 $ 7.80 $ 7.98 $ 8.16 $ 8.34 $ 8.51 $ 8.68 $ 8.85 $ 9.03 $ 9.21 $ 9.39 $ 9.58 $ 9.77 $ 9.97 $ $ $ $ $ Sumas Winter Price (US$/MMBtu) $ 7.97 $ 8.23 $ 8.39 $ 8.59 $ 8.79 $ 8.99 $ 9.18 $ 9.37 $ 9.55 $ 9.74 $ 9.94 $ $ $ $ $ $ $ $ $ $ Sumas Summer Price (US$/MMBtu) $ 6.64 $ 6.86 $ 7.00 $ 7.17 $ 7.33 $ 7.50 $ 7.67 $ 7.82 $ 7.98 $ 8.14 $ 8.30 $ 8.46 $ 8.63 $ 8.81 $ 8.98 $ 9.16 $ 9.35 $ 9.53 $ 9.72 $ 9.92 $ Sumas Winter Price ($Cdn/GJ) $ 8.89 $ 9.18 $ 9.36 $ 9.58 $ 9.80 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ Sumas Summer Price ($Cdn/GJ) $ 7.41 $ 7.65 $ 7.80 $ 7.99 $ 8.18 $ 8.37 $ 8.55 $ 8.72 $ 8.89 $ 9.07 $ 9.25 $ 9.44 $ 9.63 $ 9.82 $ $ $ $ $ $ $ T-South Demand Charges ($Cdn/Mcf) $ 0.40 $ 0.40 $ 0.41 $ 0.42 $ 0.42 $ 0.43 $ 0.44 $ 0.44 $ 0.45 $ 0.46 $ 0.47 $ 0.47 $ 0.48 $ 0.49 $ 0.50 $ 0.50 $ 0.51 $ 0.52 $ 0.53 $ 0.54 $ T-South Demand Charges, Calendar Year ($Cdn/GJ) $ 0.37 $ 0.37 $ 0.38 $ 0.39 $ 0.39 $ 0.40 $ 0.41 $ 0.41 $ 0.42 $ 0.43 $ 0.43 $ 0.44 $ 0.45 $ 0.45 $ 0.46 $ 0.47 $ 0.48 $ 0.48 $ 0.49 $ 0.50 $ T-South Demand Charges, Storage Year ($Cdn/GJ) $ 0.37 $ 0.38 $ 0.38 $ 0.39 $ 0.39 $ 0.40 $ 0.41 $ 0.41 $ 0.42 $ 0.43 $ 0.43 $ 0.44 $ 0.45 $ 0.46 $ 0.46 $ 0.47 $ 0.48 $ 0.49 $ 0.49 $ 0.50 $ Station-2 Daily Gas Price = 1.5 times Winter Price ($Cdn/GJ) $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ Sumas Summer/Station-2 Winter daily Differential ($Cdn/GJ) $ 5.05 $ 5.21 $ 5.32 $ 5.45 $ 5.57 $ 5.70 $ 5.82 $ 5.94 $ 6.06 $ 6.18 $ 6.30 $ 6.43 $ 6.56 $ 6.69 $ 6.82 $ 6.96 $ 7.10 $ 7.24 $ 7.39 $ 7.53 $ Station-2 Daily Winter T-South Fuel 3.3% ($Cdn/GJ) $ 0.41 $ 0.42 $ 0.43 $ 0.44 $ 0.45 $ 0.46 $ 0.47 $ 0.48 $ 0.49 $ 0.50 $ 0.51 $ 0.52 $ 0.53 $ 0.54 $ 0.56 $ 0.57 $ 0.58 $ 0.59 $ 0.60 $ 0.61 $ Fixed cost (150MMcfd x 365days x T-South Demand Charge)(9 months first year) $ 16,274 $ 22,050 $ 22,407 $ 22,770 $ 23,139 $ 23,514 $ 23,895 $ 24,282 $ 24,675 $ 25,075 $ 25,481 $ 25,894 $ 26,313 $ 26,740 $ 27,173 $ 27,613 $ 28,060 $ 28,515 $ 28,977 $ 29,446 $ 29, Variable based on (150 MMcf/d x 5 days) (two days first year) $ 4,205 $ 4,550 $ 4,641 $ 4,752 $ 4,863 $ 4,974 $ 5,083 $ 5,184 $ 5,288 $ 5,394 $ 5,502 $ 5,612 $ 5,724 $ 5,838 $ 5,955 $ 6,074 $ 6,196 $ 6,320 $ 6,446 $ 6,575 $ 6, Total before mitigation $ 20,479 $ 26,600 $ 27,048 $ 27,522 $ 28,002 $ 28,488 $ 28,977 $ 29,466 $ 29,963 $ 30,469 $ 30,983 $ 31,506 $ 32,037 $ 32,578 $ 33,128 $ 33,687 $ 34,256 $ 34,835 $ 35,423 $ 36,021 $ 36, Mitigation (4 out of 5 winter months) -$ 2,735 -$ 6,947 -$ 7,060 -$ 7,174 -$ 7,290 -$ 7,408 -$ 7,528 -$ 7,650 -$ 7,774 -$ 7,900 -$ 8,028 -$ 8,158 -$ 8,291 -$ 8,425 -$ 8,561 -$ 8,700 -$ 8,841 -$ 8,984 -$ 9,130 -$ 9,278 -$ 9, Total after mitigation $ 17,745 $ 19,653 $ 19,988 $ 20,348 $ 20,711 $ 21,079 $ 21,449 $ 21,816 $ 22,189 $ 22,568 $ 22,955 $ 23,347 $ 23,747 $ 24,153 $ 24,567 $ 24,987 $ 25,415 $ 25,851 $ 26,293 $ 26,744 $ 27, Please note, for the Year 2011: Only 9 months of Fixed Charges are applied as transport starts 1 April Please note Conversion Factors: GJ/MMBtu Fuel component of the Variable charge has only 2-day usage to reflect the need for two winter months (November & December) GJ/Mcf Variable cost: This is the 5 day usage charge for fuel and the added cost of summer/winter differential to secure supply WEI TRANSPORT COST: PRESENT VALUE (Year 2010 $) 33 Evaluation Period (Years) Discount Rate 6.2% 6.2% 10.0% 10.0% 35 Fixed cost (150MMcfd x 365days x T-South Demand Charge) $ 166,752 $ 264,895 $ 132,452 $ 186, Variable based on (150 MMcf/d x 5 days) (two days first year) $ 35,890 $ 57,491 $ 28,564 $ 40, Total before mitigation $ 202,642 $ 322,386 $ 161,016 $ 226, Mitigation (4 out of 5 winter months) -$ 50,416 -$ 81,338 -$ 39,754 -$ 56, Total after mitigation $ 152,226 $ 241,048 $ 121,262 $ 170, Levelized Yearly Cost, before mitigatin ($Cdn 000) starting in 2011 $ 27,544 $ 29,557 $ 27,270 $ 28, Levelized Yearly Cost, after mitigation ($Cdn 000) starting in 2011 $ 20,691 $ 22,100 $ 20,537 $ 21, Unit Charge based on period & discount rate 6.2% 6.2% 10% 10% n 46 Before mitigation unit charge ($Cdn/GJ) $ $ $ $ unit charge NPV = where n is the period (12 year or 22 year) and discount rate is 6.2% or 10% 47 After mitigation unit charge ($Cdn/GJ) $ $ $ $ ( 1 + discount rate) i i = Data Source: Natural Gas Price Forecast from GLJA [Jan 2006] Transport Rate on Northwest Pipe posted - Page 2

199 Fall NORTHWEST GAS OUTLOOK UPDATE This updated document, compiled by the Northwest Gas Association (NWGA) and its members, highlights key findings of the group s 2006 annual report, the Northwest Gas Outlook: Natural Gas Demand, Supply and Service Capacity in the Pacific Northwest. Beginning this year, only this summary document will be in print form; the full annual report and its appendices will be posted electronically on the NWGA web site ( The intent of the Outlook is to provide a consensus industry perspective of the region s current and projected natural gas demand, supply, delivery capability and price. For purposes of this report, the Pacific Northwest is defined as Idaho, Oregon, Washington and British Columbia (BC). This forecast covers the period beginning November 1, 2006, and ending October 31, By sharing factual information about the dynamics of the regional natural gas industry, the Association hopes to: Build a broad-based awareness of the natural gas industry throughout the region. Cultivate a common outlook as industry participants work through the challenges of ensuring a reliable supply of natural gas to serve growing regional demand. Encourage discussion about region-wide energy issues beyond natural gas, including a better understanding of the potential impacts of various energy choices across fuels and the need for more integration in energy planning. Promote public policies and industry and consumer actions that will ensure the wise and most cost-effective use of natural gas. About the NWGA The Northwest Gas Association (NWGA) is a trade organization of the Pacific Northwest natural gas industry. Its members include six natural gas utilities serving communities in Idaho, Oregon, Washington and British Columbia, and three interstate pipelines that move natural gas from supply basins into and through the region (see map on page 2). NWGA members transport or distribute almost all of the natural gas consumed in the Pacific Northwest. Members include Avista Corporation, Cascade Natural Gas Corporation, Duke Energy Gas Transmission (DEGT), Intermountain Gas Company, NW Natural, Puget Sound Energy, Terasen Gas, TransCanada Gas Transmission Northwest (GTN), and Williams Northwest Pipeline.

200 NW GAS OUTLOOK UPDATE 2006 Northwest Gas Association Member s Service Area Map NWGA Member Contact Information Avista Corporation (800) Cascade Natural Gas Corporation (206) Duke Energy Gas Transmission (604) Intermountain Gas Company (208) NW Natural (503) Puget Sound Energy (425) Terasen Gas (800) TransCanada s GTN System (503) Williams Northwest Pipeline (801) Northwest Gas Association - (503)

201 NW GAS OUTLOOK UPDATE 2006 Summary of Key Conclusions The Pacific Northwest regional natural gas market faces the future in relatively good health, despite challenges of increased competition for supply; growing demand regionally, continentally and across the globe; lagging development of new continental, offshore and imported resources; and the potential for higher prices triggered by a tight demand/supply balance and high crude oil prices. The industry will continue to monitor customer needs and obtain supply, encourage the wise use of natural gas, build the necessary infrastructure and manage gas prices through commodity purchasing and hedging strategies. However, public policy-makers and industry decision-makers will have a significant impact on the availability and price of natural gas in the coming decades based on whether and how swiftly they can work together to address critical issues facing natural gas consumers today. Demand Regional demand for natural gas will continue to grow over the next five years, with most of the growth driven by a rising number of residential and commercial customers. Meanwhile, energy efficiency efforts prompted by higher prices in recent years continue to moderate everyday (or base ) fuel use. Conversely, peak demand loads (during cold winter weather, for example) are growing more rapidly than base loads, although the region is just now surpassing demand levels last seen in the mid-1990s and is still below record volumes.) This change in the nature of the region s load (called load shape) has implications with regard to future infrastructure investments the industry will need to make in order to serve higher short-term spikes in demand. Supply While still benefiting from its proximity to two prolific gas-producing regions, Pacific Northwest consumers are increasingly competing for that gas with other regions of North America. To meet future regional and continental demand, North America will require new incremental supplies including liquefied natural gas (LNG) from across the globe as well as new supply sources closer to home like Alaskan gas, Canadian frontier gas, offshore gas, and non-conventional resources such as coalbed methane reserves. Development of many of these is moving forward, but rapidly escalating finding and development costs, exploration and drilling restrictions and regulatory hurdles still impede progress. Capacity Existing natural gas pipeline and storage capabilities including storage expansions already under way or planned are adequate to serve regional needs for the next five years under normal conditions, although an extreme peak in demand could stretch the region s infrastructure capacity. Contracting patterns on the region s upstream pipelines also continue to change as natural gas producers and marketers who previously held capacity on these pipelines now have access to new markets for their gas supplies. In response, demand-side interests in the region (e.g., local distribution companies, power generators, industrial customers) are acquiring additional transport capacity to ensure sustained access to available supply. While Canadian supply continues to be available to flow to the Northwest market, shipping costs to the region have increased because fewer shippers are paying for a greater share of the pipeline transmission costs. Prices Wholesale (wellhead) prices for natural gas have been on the rise since 2002 and averaged $7.45 per thousand cubic feet in 2005 according to the U.S. Energy Information Administration (EIA). The EIA projects that the average wholesale price of natural gas in 2006 will be lower than in 2005 and will then resume an upward trend, primarily due to declining traditional supplies, a growing reliance on new and more expensive sources of supply and sustained high crude oil prices 1. While a temporary surplus of natural gas (resulting from a mild winter and abundant supplies in underground storage) caused regional and continental prices to fall during the summer of 2006, a tight demand/supply balance is expected to keep pressure on prices. In fact, the spot price of natural gas jumped almost 30 percent in one week during a 2006 summer heat wave. Still, the Pacific Northwest continues to benefit from being located adjacent to robust gas-producing regions resulting in access to some of the lowest cost gas supply in Northern America. 1 U.S. Energy Information Association, Short Term Energy Outlook, August 8, Northwest Gas Association - (503)

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203 NW GAS OUTLOOK UPDATE 2006 Regional Demand Key Conclusions 1. Over the next five years, natural gas consumption (as measured by energy content, or decatherms - Dth) in the region is expected to grow an average of 2.1 percent per year, with a cumulative projected growth rate of 8.1 percent. Most of this growth reflects increased demand anticipated from residential and commercial customers. 2. The region s peak load is growing more rapidly than its base load. This has significant implications for the type of new capacity most appropriate to serve the region s needs. 3. The number of natural gas customers continues to grow in the Pacific Northwest, although the use per customer is lower than in the late 90s. Recent warmer weather patterns have contributed, but consumers have also responded to higher natural gas prices with a variety of conservation techniques including better weatherization, more efficient appliances and equipment, and energy-conscious use practices. 4. The region must ensure that it is using its energy resources in the wisest, most effective ways possible. For instance, natural gas cannot directly power computers and lights, but is more efficient than electricity when burned for space and water heating or for cooking. A Closer Look As noted, natural gas demand in the Pacific Northwest is expected to grow 8.1 percent through 2011, given normal weather and expected economic and population growth (called base case ). This projection is slightly lower than in past years (the 2005 Outlook report projected 9.3 percent cumulative growth over five years), but represents a sizable shift in market forces behind that growth. Whereas demand by gas-powered electric generation facilities drove projections in previous years, anticipated demand by that customer group has flattened significantly in the face of volatile natural gas prices. Also contributing to the shift in projected gas demand for generation is a sufficiency of electricity in parts of the region with plenty of water for hydropower generation in 2006 and significant alternative energy developments, especially wind. Instead, expected demand growth among residential/commercial consumers is powering overall growth. This partly reflects a growth in the number of consumers due to an expanding economy and population as well as the higher cost of alternative energy sources, such as electricity and oil. Since natural gas is a good value for home heating, it remains the fuel of choice for space and water heat in most new single-family home construction and many older electric furnaces and water heaters are being replaced with natural gas units. Forecast growth in demand for each customer group under a number of growth scenarios is shown in Table 1. Table 1. Projected Demand through Average Annual & Cumulative Peak load: Gas consumption that increases significantly or peaks during certain periods, usually because of temperature conditions. Northwest loads peak in the winter for space heat and again in the summer (due to electric generation for air conditioners). Northwest Gas Association - (503)

204 NW GAS OUTLOOK UPDATE 2006 Weak economic conditions and higher gas prices in recent years have significantly eroded industrial demand, which declined by nearly one-third between 1999 and Today, while industrial use is still proportionally larger than other customer groups, the margin is shrinking, and demand by this customer segment is growing significantly more slowly than any of the other sectors. As shown in Figure 1, residential customer demand is expected to surpass industrial demand by Figure 2 shows projected total annual demand growth for each of the next five years. Figure 1. Projected Regional Demand by Sector Base Case, Figure 2. Projected Total Annual Natural Gas Demand Growth, Northwest Gas Association - (503)

205 NW GAS OUTLOOK UPDATE 2006 Finally, Figure 3 shows projected annual demand under each of the three growth scenarios explored by the larger Outlook report: Base case, low-growth and high-growth. Low growth assumes slower than expected economic growth while high growth considers a more rapid economic expansion and greater requirements for gas-fired electrical generation. Projected gas prices also figure prominently in the respective forecasts. The low case reflects higher than expected natural gas prices, and the high case lower than expected prices. (Note that under the base case scenario, total regional demand is not expected to return to 2001 volumes until sometime after 2011 a lasting legacy of the 2001 energy crisis.) Trends in Demand Growth Figure 3. Projected Annual Demand by Growth Case, While the region s natural gas consumption continues to grow, the nature of that consumption has changed in recent years. Increased energy conservation efforts triggered by rising energy prices have not only slowed the rate of demand growth, but changed customer load profiles and composition (Figure 4). Normal, year-around or base loads (e.g., industrial processes only nominally affected by weather like kilns to dry lumber or boilers for food processing) are growing more slowly than peak loads, which are triggered by weather or other short-term factors (e.g., home heating). Figure 4. Change in Load Composition, 1999 Actual Compared to 2005 Actual This change has important implications for the natural gas industry since it affects the region s overall capacity needs as well as purchasing/contracting requirements to serve potentially more volatile customer loads. For instance, pipelines are usually built to serve base loads, while storage facilities are typically the most cost-effective method of meeting short term surges in demand. Not surprisingly, no new pipelines are planned to serve the region by 2011, but several gas storage facilities are expanding. For more information, see the Regional System Capacity section later in this document. Northwest Gas Association - (503)

206 NW GAS OUTLOOK UPDATE 2006 What This Means How can the region s growing natural gas demand best be met? Answer: encouraging even more efficient use of this vital resource while simultaneously working to expand access to existing and new supplies. (The need to expand supplies is discussed in the following Regional Supply section.) Encouraging Wise Energy Use Demand for natural gas is something nearly every consumer can control. With proper information and often minimal expense, consumers can take a variety of steps to reduce their usage and monthly bills. Customers have already significantly curbed regional demand often with technical and/or financial help from energy efficiency programs offered by gas and electric utilities or other entities by installing more efficient furnaces and appliances, programmable thermostats, better insulation and doublepane windows. However, more can be done. The American Council for an Energy Efficient Economy (ACEEE) estimates that widespread adoption of cost-effective energy efficiency measures throughout the U.S. could lower projected national gas usage by 10 percent by 2020 and cut the wholesale price of natural gas by 25 percent 2. Helping Utilities Help Customers Under traditional rate structures, natural gas utilities are not encouraged to promote energy efficiency programs. Simply put, the less gas consumers use, the less revenue a utility receives to cover its fixed costs. Regulators throughout the U.S. and Canada are beginning to adopt innovative rate structures like decoupling to address this disincentive where appropriate. In addition to conserving a valuable resource, the resulting reduction in overall use may help to temper prices in both the short- and long-term, putting more money back into the pockets of customers, lowering business energy costs and, in turn, stimulating the economy. Decoupling: Separating the direct link between gas sales volume and recovery of authorized fixed costs, usually by establishing a rate structure that allows a utility to recover its fixed costs regardless of how much gas it distributes. Additional information on decoupling and energy efficiency can be found in the Fall 2006 white paper, Natural Gas Demand in the Pacific Northwest, also posted on the NWGA website. 2 Testimony of R. Neal Elliot, ACEEE Industrial Program Director, submitted to the U.S. House Government Reform Subcommittee on Energy and Resources, Sept. 14, Northwest Gas Association - (503)

207 NW GAS OUTLOOK UPDATE 2006 Regional Supply Key Conclusions 1. The Pacific Northwest market still benefits from its proximity to two large gas-producing regions the Western Canadian Sedimentary Basin (WCSB), consisting of an expansive area covering northwest British Columbia and most of Alberta; and the U.S. Rocky Mountains, including primarily Colorado, Utah and Wyoming see Figure 5. Production from these areas is projected to increase by 2011, with the most of the growth occurring in the Rockies. 2. However, the region is increasingly competing for those resources with other North American markets. New pipelines built in recent years provide access to these supplies by growing markets in the Midwest and Northeast, and proposed pipelines will sustain the trend (e.g., The Rockies Express Pipeline proposed by Kinder Morgan to ship 1.8 Bcf/day of gas from the Rockies to Ohio and Pennsylvania). 3. With U.S. and Canadian natural gas demand expected to grow nearly 30 percent by 2025, and declining and/or restricted supplies elsewhere on the continent, we will soon need additional natural gas resources to serve both the Pacific Northwest and the rest of North America. This will most likely come in the form of liquefied natural gas (LNG) imports, which are expected to make up more than 20 percent of U.S. supply by 2025 according to the EIA. 4. Besides LNG imports, Alaskan gas, Canadian frontier gas and development of offshore gas supplies (which are currently restricted from development by moratorium) and non-conventional resources such as coal-bed methane reserves will be vital to serve the future growth in gas demand. Liquefied natural gas: Gas made liquid by cooling to -259 F. LNG occupies about 1/600 of the volume of vapor, which makes shipping long distances possible. 5. To ensure supply can keep pace with demand, we must build on recent efforts to encourage exploration, development and production and re-examine the restrictions on offshore drilling. Northwest Gas Association - (503)

208 NW GAS OUTLOOK UPDATE 2006 Figure 5. Production Areas Serving the Pacific Northwest A Closer Look The Pacific Northwest relies on natural gas produced in the WCSB and the U.S. Rockies. About half of the gas consumed in the region comes from the portion of the WCSB located in northeast British Columbia (BC). Total annual natural gas production in the WCSB and Rockies, currently 24 billion cubic feet per day (Bcf/d), could approach 29 Bcf/d by 2011 according to some estimates 3 an increase of 13 percent. Most of that growth is expected to occur in the Rockies. Figures 6 and 7 show various forecasts for production growth in each area. 3 Wood Mackenzie, Long-term Market Outlook to 2020, August Northwest Gas Association - (503)

209 NW GAS OUTLOOK UPDATE 2006 Figure 6. Current WCSB Gas Production Forecasts Figure 7. Current Rockies Gas Production Forecasts Northwest Gas Association - (503)

210 NW GAS OUTLOOK UPDATE 2006 In all, the two production areas have about 85 trillion cubic feet (Tcf) of remaining proven reserves (a working inventory of natural gas that can be economically recovered using today s technologies), with a combined ultimate resource potential (best estimate of total resources, even if not yet economically feasible to access) of 500 Tcf. As shown in Figure 8, proven reserves change over time in response to the maturity of a given production area, improvements in exploration and production technologies, public policy changes, pipeline expansions that provide market access to supplies and other dynamics of the gas commodity market. Figure 8. Proven Reserves - Rockies 4 While ample resources exist to serve our region, several factors hamper development in production areas. Barriers include drilling rig and personnel shortages in the short term, infrastructure expansion needs in the mid term and limited access to offshore resources as well as non-park public lands in the U.S. (under which proven gas reserves lie) in the longer term. For example, drilling is not allowed in the waters off the East Coast of the U.S. or the West Coast of either the U.S. or Canada, nor is it allowed in the eastern Gulf of Mexico. Furthermore, as already noted, the Pacific Northwest is increasingly competing with the rest of North America for supply from our own producing regions. For example, Canada is expected to export less gas to the U.S. as its own needs grow. In addition, as pipelines increasingly link production areas with the larger continental market, the regional market is more influenced by continental demand and supply (see Figure 9). Therefore, although we have more than adequate natural gas supplies to serve regional consumers in the near future, we need to consider the longer term, particularly since the process of siting, permitting, financing and building new natural gas supply and delivery facilities can take upwards of five years. 4 Source: EIA, U.S. Crude Oil, Natural Gas and Natural Gas Liquids Reserves Report, September Northwest Gas Association - (503)

211 NW GAS OUTLOOK UPDATE 2006 Figure 9. North American Natural Gas Flows 5 What This Means Meeting future demand cannot be achieved solely by expanding production in our traditional supply areas or offshore. It will also require the construction of major new pipeline projects to connect gas production in Alaska and the Canadian Mackenzie River delta, over the longer term developing unconventional resources and importing more natural gas from around the globe in addition to enhanced energy conservation efforts. As many existing North American resources mature and experience production declines, we must explore all available potential new resources. Some of the most promising include: Frontier gas supplies in the Mackenzie River Delta (Canada) and the Alaska North Slope, with enough proven natural gas reserves to satisfy U.S. natural gas demand by itself for more than a decade. 6 Alaskan gas, projected to come online in 2017, will be the single largest potential domestic source of relief for North American gas consumers. Offshore resources. More than 130 Tcf of offshore natural gas resources in North America are currently off limits to development because of federal off-shore drilling moratoria 80 Tcf off U.S. shores and 50 Tcf in Canada (including 40 Tcf off the coast of British Columbia). 7 Both nations are reviewing their offshore oil and natural gas exploration and production policies. 5 Energy and Environmental Analysis, Inc. (EEA), April 2006, Base Case 6 American Gas Association, Meeting Consumer Demand for Natural Gas Supply Side Action Is Needed Now, February, Interstate Oil and Gas Compact Commission, Untapped Potential: Offshore Oil and Gas Resources Inaccessible to Leasing, March 2006 Northwest Gas Association - (503)

212 NW GAS OUTLOOK UPDATE 2006 Coal-bed methane (CBM) reserves. Extracted from coal seams, CBM is already being produced in significant quantities in the U.S. According to the Energy Information Administration (EIA), in 2001 it accounted for about 7 percent of U.S. annual natural gas production and its potential has barely been tapped; the U.S. Rockies alone contain estimated CBM reserves of 596 Tcf. In Canada, where CBM reserves are estimated at 500 Tcf, drilling activity is increasing rapidly. 8 Besides CBM, other non-conventional natural gas resources are increasingly accessible (e.g., shale and tight gas natural gas that exists in rock formations with low porosity and/or permeability). Recovery of these resources will be assisted by the development of new discovery, drilling and extraction technologies. Liquefied natural gas (LNG) imports. LNG is currently exported by 12 countries including Indonesia, Algeria, Malaysia, Qatar, Nigeria, Australia, Oman, Brunei, United Arab Emirates, Russia, Trinidad and Tobago, and the United States. Together these countries possess an annual export capacity of nearly 7 Tcf. Supply from these countries is expected to increase by 30 percent to more than 9 Tcf by An additional 3 Tcf in exports is expected from new producing countries like Egypt which joined the ranks of LNG exporting countries in Growing Role of LNG As shown in Figure 10, imported natural gas supplies will serve a growing role in the continental and regional energy picture. The EIA projects LNG imports must increase from under 1 Tcf in 2004 to more than 6 Tcf by 2025 a six-fold increase to meet projected continental demand. That would be enough to serve some 20 percent of U.S. natural gas consumers. Figure 10. Projected Mix of Resources Needed to Meet Future Demand LNG (green area) will play a vital role in serving the U.S. demand over the next decades as overall U.S. and Canadian supplies grow only slightly or hold steady. Alaskan gas will provide a much needed domestic supply boost after Alberta Geological Survey, Introduction to Coal- bed Methane Exploration Areas in Alberta, October, EIA, The Global Liquefied Natural Gas Markets: Status and Outlook, Northwest Gas Association - (503)

213 NW GAS OUTLOOK UPDATE 2006 Figure 11. Proposed LNG Import Terminals in the Pacific Northwest 10 Recent technological improvements have made the cost of LNG imports more competitive, spurring interest in expanding or building new LNG import terminals throughout North America. In the U.S. alone, four existing terminals are being expanded, and the first new terminal in 20 years began service in March More than 40 new terminals have been proposed, including four in Oregon and two in British Columbia (see Figure 11). Clearly, access to North American frontier, off-shore, nonconventional and global natural gas resources is critical to the region s energy future. Additional supply information, including a more in-depth discussion of LNG, can be found in the January 2006 white paper, Natural Gas Supply in the Pacific Northwest, also posted on the NWGA website ( 10 California Energy Commission, May, Northwest Gas Association - (503)

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215 NW GAS OUTLOOK UPDATE 2006 Regional System Capacity Key Conclusions A Closer Look 1. Under expected conditions, existing natural gas pipeline and storage capacities and planned storage expansions are adequate to serve regional needs. Projected peak day demand (assumed extreme cold weather occurring simultaneously across the region) approaches the capacity of the region s infrastructure, which is being used very efficiently and has little redundancy. 2. The changing nature of the region s natural gas demand (peak load growing faster than base load) means we must continue to closely monitor infrastructure adequacy. Because stored gas is generally a more cost-effective means of meeting seasonal and peak market needs, the industry has already responded by expanding the region s gas storage capacity. 3. Contracting patterns on the region s Canadian upstream pipelines also continue to change. Gas producers and marketers historically held much of the capacity on these pipelines. For a variety of reasons, these shippers relinquished significant volumes of capacity in recent years. Demand-side interests in the region have stepped in to acquire some of the available capacity in order to ensure continued access to reliable gas supplies at upstream trading hubs. The remaining uncontracted capacity on upstream pipelines is available to flow gas on an interruptible basis in response to market demand in the region. 4. As the region s electricity industry plans its future energy resource mix including wind and any additional gas-fired generation plants the region would benefit from a more integrated approach to infrastructure planning so the two industries can coordinate anticipated demand with supply and infrastructure needs. The region s 44,000 mile network of transmission and distribution pipelines is designed to meet the base load requirements of the Pacific Northwest on an ongoing basis, while underground and LNG storage assets provide a cost-effective means of meeting the additional needs of the region on peak winter days. Together, pipelines and storage along with interruptible pipeline transportation service contracts give the industry flexibility in serving a dynamic customer load. Figure 12. Capacity of Pipelines and Storage to Meet Regional Peak Demand Figure 12 shows the current delivery capacity of pipelines and storage facilities serving the region in MDth/day (thousand decatherms per day). The region s pipeline operators all completed major pipeline expansions in the 1990s through 2003, but no additional pipeline expansions are expected through However, several storage facility expansions are occurring or being explored. Northwest Gas Association - (503)

216 NW GAS OUTLOOK UPDATE 2006 Peak Day Analysis Figure 13. Capacity of Pipelines and Storage to Meet Regional Peak demand Currently, pipelines and storage facilities serving the region are capable of delivering more than 5.9 million Dth/day of gas on a peak day, and will have expanded to more than 6.4 Dth/day by the end of the forecast period. In the base case growth scenario (i.e., expected demand growth), with assumed extreme cold weather occurring simultaneously across the region, capacity falls just short of meeting regional peak needs in and in (see Figure 13: red line and yellow bars). There is adequate capacity to serve the region s peak day requirements under the Low Demand Growth scenario throughout the forecast period. While residential and commercial service would not likely be interrupted in any case, there is a chance industrial customers without firm service agreements could face service curtailments. The risk of this scenario increases in the high demand growth case, which could create a capacity shortfall as early as Fortunately, due to prevailing regional weather patterns, it is rare for a coincidental peak to occur. Extreme weather is more likely to affect only parts of the region and usually in succession, not simultaneously. I-5 Corridor Extended Winter Analysis Analyses of winter-time supply and demand for a moderately cold year and a low-hydro year in the I-5 Corridor were conducted for the heating year. The temperature in a moderately cold year differs depending on the specific region but occurs about 15 percent of the time. A low-hydro year is one in which lower than average stream flows reduce hydroelectric generation and increase demand for gas-fired electric generation. The low-hydro year in this analysis was based on actual hydro generation data from For each of the scenarios, both base case and high growth case demand were plotted against pipeline capacity, underground storage and peaking resources such as LNG storage to gauge the adequacy of deliverability capacity. The high demand case was used in order to test the worst case. (While the probability of these scenarios occurring at the same time is low, the Western energy crisis in demonstrates that it is not impossible.) The shapes of the curves was derived using analyses performed in 2004 and updated with the latest forecast of core, industrial and power generation loads included in this update. The shape of core and power generation demand are different for a moderately cold year than for a normal or low-hydro year, while that for industrial load is the same in all cases. Northwest Gas Association - (503)

217 NW GAS OUTLOOK UPDATE 2006 Results of the base case analyses demonstrated that if the I-5 Corridor s delivery capacity remains available at present levels, with no interruption of deliverability over the winter, existing resources would be sufficient to meet base case demand, as well as expected demand in moderately cold or low-hydro circumstances, through 2011 (see Figures 14-15). Figure Winter Analysis Base Case Demand Moderately Cold Figure Winter Analysis Base Case Demand Low Hydro Northwest Gas Association - (503)

218 NW GAS OUTLOOK UPDATE 2006 Results of the high growth demand case analyses indicate the potential for unserved demand during the heating year under both the moderately cold and low-hydro scenarios (see Figures 16 and 17). Potential consequences of unserved demand include significant price volatility and the curtailment of non-core typically industrial loads. As mentioned previously, it is very unlikely that core customers (residential and commercial) would experience service interruptions under these scenarios. Figure Winter Analysis High Case Demand - Moderately Cold Year Figure Winter Analysis Hogh Case Demand - Low Hydro Year Northwest Gas Association - (503)

219 NW GAS OUTLOOK UPDATE 2006 It is important to emphasize that the only scenarios that produced results demonstrating a potential capacity deficit were the ones that utilized the higher than expected demand growth projections. While unlikely to occur, they are worth discussing because they can help the region weigh the price tag for investing in additional future capacity against the perceived need for that capacity whether under normal circumstances or unusually severe scenarios. Trends in Pipeline Capacity Contracting As noted, use of the region s pipelines has changed in recent years. Historically, much of the transportation capacity from British Columbia and Alberta to the U.S. Pacific Northwest was held by supply-side interests including producers, supply aggregators and marketers. Construction of new pipeline capacity from Western Canada to Midwest gas markets and beyond in recent years has provided producers a greater array of market options for their production. At the same time, the number and activity of third-party gas marketers serving the region has declined. Accordingly, the volume of capacity held by producer/marketer shippers on Canadian upstream pipelines serving the Pacific Northwest has declined. Consequently, local gas companies and large end-use customers (e.g., industrial consumers, power generators) have been compelled to purchase gas and to contract directly for pipeline capacity from trading hubs situated closer to Canadian production. This represents a significant change, as many of these entities historically purchased gas from suppliers at major border export points like Sumas, Washington. As a result of this transition in capacity ownership from suppliers to consumers, there is currently a capacity surplus on the upstream pipelines that bring Canadian gas to the region. For example, 40 percent of Duke Energy s T-South pipeline, which moves gas from production areas in Northeast British Columbia to Vancouver and to the U.S. Pacific Northwest at Sumas, Washington, is currently un-contracted. Likewise, 20 percent of TransCanada s Gas Transmission Northwest (GTN) pipeline, which moves gas from production areas in Alberta to the Inland Northwest and through to California markets at Malin, California, is un-contracted. In contrast, Williams Northwest Pipeline, which brings U.S. gas to the region from production areas in the Rockies and moves Canadian gas around the region, is fully contracted. The redistribution of capacity ownership on Canadian upstream pipelines is expected to continue. It is important to note that Canadian supplies remain available to the region regardless of who owns the transport capacity though it may be shipped on an interruptible rather than guaranteed (firm) basis. For instance, natural gas demand in portions of the region was driven up by cold weather in December, At the time, the T-South pipeline operated at peak capacity on the south end of the system at the Huntingdon/Sumas delivery area. A considerable volume of gas flowed on an interruptible transport basis during the event, demonstrating that supply and capacity is available to serve the market when demand is Table 2. Existing Pacific Northwest Storage and LNG Facilities Northwest Gas Association - (503)

220 NW GAS OUTLOOK UPDATE 2006 high. In order to mitigate the risk of curtailment that exists with interruptible transport capacity, end-users that require reliable supply must arrange for firm pipeline capacity from key upstream trading locations or contract for firm supply from a third party who will assume the obligation of ensuring delivery. Storage Capacity and Expansions With peak loads growing more rapidly than base loads in the region, storage capacity is increasingly important. Currently, the region is served by over 36 million Dth of working gas capacity (gas available to the marketplace see Table 2) in underground natural gas storage facilities and more than 5 million Dth of capacity in above-ground liquefied natural gas (LNG) storage facilities, for a total regional storage capacity of 41.6 million Dth. This alone is enough to serve the entire region for almost a week under the most extreme conditions. To meet growing peak demand, several storage expansions are now underway or proposed. NW Natural expects to add another 50 MDth/day in withdrawal deliverability to its Mist facility by The owners of the Jackson Prairie Storage Project have filed for a FERC certificate to increase firm deliverability by up to 312 MDth/day to come on line in late This is in addition to ongoing capacity (total working gas) expansions at both facilities. Meanwhile, Terasen Gas continues to explore siting a LNG storage facility to serve peak demand loads on Vancouver Island for operation by This would supplement the several smaller LNG storage facilities already serving the region (not to be confused with the larger scale LNG import facilities discussed earlier under Regional Supply). Typically, these LNG peaking resources are used only during extreme weather events or to alleviate constraints in transmission systems where underground storage is not available. What This Means Much like arteries in the human body, the region s natural gas pipelines serve a living, breathing market that is never static. Storage facilities serve as energy reserves to be called upon as needed. Together, the system keeps natural gas flowing to customers. Given our best estimates at this time, the natural gas infrastructure serving the region is satisfactory for now, but capacity holders must anticipate and then act when investments need to be made. In the past, the market has responded appropriately when expansions were needed, and infrastructure operators will continue to check the market by soliciting interest when warranted. Public agencies must be equipped to respond in a timely fashion to the need for additional infrastructure by implementing streamlined permitting and siting processes. Northwest Gas Association - (503)

221 NW GAS OUTLOOK UPDATE 2006 Regional Prices Key Conclusions 1. Across North America natural gas demand/supply balance will remain tight over the next five years (see Regional Demand and Regional Supply summaries), resulting in the continuation of natural gas price volatility. Ongoing demand growth, when new supply resources reach the markets, as well as volatility in the crude oil market and increasing competition for global natural gas supplies, will be among drivers influencing prices over the longer term. 2. In the short term, weather remains a primary driver of natural gas prices. As long as demand and supply remain tightly balanced, surges in demand caused by cold (heating) or hot (electric generation for air conditioning) weather and disruptions in supply as a result of weather-related damage (e.g. hurricanes) will continue to affect prices. For instance, damage to production facilities in the Gulf of Mexico caused by Hurricanes Katrina and Rita sent natural gas prices soaring during the latter third of In contrast, a mild winter in contributed to high storage inventories across North America, which drove prices down during the summer and fall of Still, the Pacific Northwest continues to benefit from lower prices than other regions and gas continues to be a good value relative to other energy options, particularly for heating. 4. Public policy-makers and industry decision-makers will have a significant impact on the availability and price of natural gas in the coming decades based on whether and how swiftly they can work together to address critical issues facing natural gas consumers. A Closer Look While natural gas prices moderated in 2006, due largely to a combination of weather-related factors, they are unlikely to return to the lows of prior decades. As discussed in the Regional Supply section, the Pacific Northwest is increasingly sharing natural gas from nearby producing regions with the larger North American market. Accordingly, regional gas consumers now pay prices for natural gas that more closely reflect those of the broader market and are subject to price movements that occur in those markets, particularly the energy intensive U.S. Northeast and Southwest. Figure 18 shows the natural gas price forecast used by the Northwest Power and Conservation Council (NWPCC) in its Fifth Northwest Electric Power and Conservation Plan. The band bounded by the low and high price estimates describes the range of prices for natural gas forecast by the NWPCC. The orange line represents the average gas price forecast used in NWPCC models for projecting the reference or expected mix of various sources of future electrical generation in the Pacific Northwest (e.g., gas-fired combined cycle turbines, wind energy, coal, etc.). Note that the EIA projections which have the benefit of more recent data are at the higher end of the NWPCC s range. Figure 18. NWPCC/EIA Natural Gas Price Projections Sources: Northwest Power And Conservation Council - 5th Power Plan, January, EIA, 2006 Annual Energy Outlook 06. Northwest Gas Association - (503)

222 NW GAS OUTLOOK UPDATE 2006 Figure 19. Natural Gas and Crude Oil Price Correlation 11 Also affecting natural gas prices in the near term are historically high prices for crude oil (see Figure 19). In fact, oil prices contribute to the price of other commodities in the energy complex (coal, natural gas, etc.) as its price fluctuates. Also contributing to the price linkage between oil and natural gas is the fact that many large industrial consumers, including some electrical generation facilities, can burn either fuel. Consequently, they will switch between the two as price dictates. What This Means Strategic planning by the natural gas industry cannot itself, however, overcome the price squeeze being felt by Pacific Northwest and other North American customers. Public policies and the regulatory environment heavily influence the industry s ability to operate effectively either expediting market flexibility or posing serious hurdles that can skew the demand/supply balance and therefore can play a huge role in future gas prices. Impact of Public Policy on Natural Gas Prices Two recent studies looked at the effects public policy choices (or lack of them) could have on future natural gas prices. An American Gas Foundation (AGF) study issued in February 2005 Natural Gas Outlook to 2020 analyzed future U.S. natural gas prices based on three alternative public policy scenarios: existing, expected and expanded. A complex interplay of other factors also contribute to energy price volatility. Natural gas end-users such as utilities and power generators work to control these price drivers as much as possible through price management activities that mix short and long-term purchases, balance risk, and ultimately acquire the requisite resources for regional customers at reasonable prices. Figure 20 illustrates a typical portfolio of resources. Figure 20. Industry Tools to Balance Resources Manager Prices 12 Underground Storage Financial Derivatives (futures, options, etc...) Long-term Contracts (1+ years) Short-term Contracts (1-12 months) The existing, or status quo, scenario described in the 2005 AGF study assumed continuing restrictions on off-shore and Rocky Mountain drilling, no functional Alaskan pipeline and no new LNG terminals. The expected scenario assumed a more diverse natural gas supply, with major contributions from Alaska (by 2014) and imported LNG, but continued drilling restrictions. Finally, the expanded scenario assumed new supplies from Alaska and LNG and development of limited resources off the East Coast and Gulf of Mexico and in the Rockies. Daily/spot Market (30 days or less) 11 EIA, Annual Natural Gas and Crude Oil Prices, as of December 31, represents a perfect, one-to-one correlation. 12 Illustration courtesy of American Gas Association. Northwest Gas Association - (503)

223 NW GAS OUTLOOK UPDATE 2006 The expanded policy scenario could save consumers more than $500 billion over the expected scenario between 2005 and 2020, the study found (see Figure 21.) It notes, however, that both the expected and expanded scenarios require significant changes in public policy currently being examined by Congress. Figure 21. AGF Future Gas Prices under Three Public Policy Scenarios Similarly, in its 2003 Natural Gas Study, the National Petroleum Council (NPC) identified two policy scenarios: a reactive path and a balanced future. The reactive (or minimal action) path assumed some action is taken Forecasted prices are five year averages. to increase efficiency and conservation, enable the Alaskan gas pipeline, overcome siting opposition to LNG terminals, and allow increased drilling in the Rockies. Supply and demand would continue to be tight, the NPC found, resulting in higher and more volatile prices. The NPC s recommended balanced future scenario assumed more aggressive steps to maximize supply and infrastructure development and fuel-switching flexibility, resulting in lower price projections. Such actions could save energy consumers up to $1 trillion in natural gas costs over the next two decades, the study found (see Figure 22). Figure 22. NPC Policy Impact on Future Gas Prices Recent Public Policy Actions Recent policy initiatives in both the U.S. and Canada mean we have already taken some important first steps. The U.S. Energy Policy Act of 2005 provides a fresh blueprint for the supply, delivery and efficient use of natural gas and other forms of energy directly benefiting homeowners and commercial consumers who have struggled with rising energy prices since The Act encourages more natural gas production in the U.S., increasing imports of LNG, and promoting research on promising new sources of natural gas, such as coal-bed methane and methane hydrates. It encourages expansion of natural gas pipelines and the construction of more underground natural gas storage facilities. And the Act promotes innovative technologies, such as natural gas fuel cells, to encourage more efficient use. By separate action earlier in the year, Congress also enacted provisions to expedite construction of the Alaska Gas Pipeline, which will connect readily available stores of natural gas to the consuming regions of North America. Northwest Gas Association - (503)