The following are the comments of Westcoast Energy Inc. ( Westcoast ) with respect to the referenced Application.

Transcription

1 C5-2 KIRSTEN B. JARON Director, Regulatory BC Pipeline and Field Services Divisions Duke Energy Gas Transmission Fifth Avenue Place, East Tower Suite 2600, st Street SW Calgary, AB T2P 3L8 Telephone: Fax: kjaron@duke-energy.com August 19, 2005 Via Mr. Robert S. Pellatt Commission Secretary British Columbia Utilities Commission Sixth Floor 900 Howe Street Vancouver, BC V6Z 2N3 Dear Mr. Pellatt: Re: Terasen Gas Inc. ( Terasen Gas ) Application dated June 1, 2005 for Approval of Transactions with respect to the Southern Crossing Pipeline ( SCP ) and the Inland Pacific Connector ( IPC ) The following are the comments of Westcoast Energy Inc. ( Westcoast ) with respect to the referenced Application. Westcoast was an active participant in the two proceedings that led to the Commission s April 3, 1998 (the 1998 Decision ) and May 21, 1999 (the 1999 Decision ) Decisions concerning Terasen Gas applications for approval to construct the SCP. Westcoast s interest in this matter remains, as before, to ensure that there is a fair and competitive playing field for new infrastructure proposals designed to serve gas markets in British Columbia and the U.S. Pacific Northwest. Westcoast, as a major link in the British Columbia natural gas supply chain, is vitally concerned with any project or proposal which may adversely impact the cost of gas to end-users who source gas off the Westcoast system. Westcoast believes that the Commission should, in assessing the requested approvals in this current Application, bear in mind some basic facts about the SCP and the representations that were made by Terasen Gas in pursuing the SCP project. The SCP In its 1998 Decision the Commission denied Terasen Gas application for approval to construct the SCP. While the Commission concluded that Terasen Gas required a peak shaving resource to serve the Lower Mainland, the Commission found that the SCP, which was not supported by any third party transportation agreements, was not the least cost resource alternative available to Terasen Gas. Other concerns that the Commission had regarding the SCP are set out on

2 - 2 - pages 106 and 107 of the 1998 Decision. Nevertheless, the Commission recognized that there was a potential for new gas loads to develop to serve cogeneration plants on Vancouver Island and the Burrard Thermal Plant and was of the view that Terasen Gas should be given the opportunity to explore potential peak shaving options with BC Hydro: The Commission expects BC Gas to expedite negotiations with B.C. Hydro to explore the benefits of peak shaving with the objective of presenting a firm proposal to the Commission no later than October 2, At the least, such a proposal should contain firm in-service target dates for thermal generation or other plant facilities that will provide the peak shaving, a commitment with respect to a firm supply of gas at Huntingdon, a signed agreement as to terms and prices for the purchase of peak shaving gas and an outline of any new gas pipeline infrastructure required to service cogeneration facilities or other new peak loads. In this regard, the Commission notes that if there is a requirement for new pipeline infrastructure upstream of Huntingdon to serve these loads, BC Gas may wish to re-examine the SCP and attempt to obtain commitments from B.C. Hydro for capacity on the SCP which would make it a viable alternative. (emphasis added) (1998 Decision, p. 108) The Commission also indicated that in the absence of sufficient firm commitments by third parties to make the SCP viable, the Commission is also of the view that BC Gas should develop separate strategies for meeting its transmission capacity needs in the Lower Mainland and Interior regions. (emphasis added) (1998 Decision, p. 108). Terasen Gas re-applied to the Commission in December, 1998 for approval to construct the SCP. The SCP facilities applied for in the new application were essentially the same as those in the previous application (1999 Decision, p. 3), although the forecast capital cost of the project had increased from approximately $364 million to $376 million. The installed cost of the project was approximately $395 million (June 1, 2005 Application, p. 12). The justification and support for the refiled application was based on the Firm Tendered Transportation Service Agreements ( TSAs ) and Peaking Gas Purchase Agreements (the Peaking Agreements ) that Terasen Gas had entered into with BC Hydro and PG&E Energy Trading, Canada Corporation ( PG&E Energy Trading ) subsequent to the 1998 Decision. Under the two TSAs Terasen Gas contracted 100% of the firm SCP capacity from Yahk through to Kingsvale/Huntingdon (105 MMcf/d) to BC Hydro and PG&E Energy Trading (52.5 MMcf/d to each shipper) for total demand charges of only $7.2 million per year ($3.6 million per shipper). The $3.6 million annual demand charge under each agreement was fixed for 10 years (i.e. no escalation provision) regardless of the actual costs of the SCP or the tolls that Terasen Gas would have to incur for 105 MMcf/d of firm service on the Westcoast system from Kingsvale to Huntingdon necessary in order to provide service under the TSAs to BC Hydro and PG&E Energy Trading. The TSA demand charges do not come close to covering the annual costs of the SCP. The annual cost of service of the SCP facilities alone (i.e. the SCP pipeline and compressor facilities) exceeds $50 million per year. This amount does not include any allocation of Terasen Gas existing operating and maintenance costs to the SCP cost of service, any costs relating to Terasen Gas Oliver to Kingsvale pipeline (100% of the firm capacity of which was dedicated to

3 - 3 - providing service to BC Hydro and PG&E Trading), or the Westcoast toll for 105 MMcf/d of firm service from Kingsvale to Huntingdon (currently about $5.5 million per year). The relevance of this SCP cost information in the context of the current Application is that Terasen Gas justified the non-compensatory nature of the demand charges payable under the TSAs (and the corresponding heavy subsidy provided by Terasen Gas core market customers to the two shippers), and in fact the justification for the SCP itself, based on the Peaking Agreements with BC Hydro and PG&E Energy Trading. Terasen Gas argued that the TSA capacity was, in effect, curtailable for 15 days (and therefore really only 350 day capacity), and therefore Terasen Gas had reserved for the benefit of the core market the remaining (and most valuable) 15 days of SCP capacity for peaking purposes. For this reason Terasen Gas was emphatic that in valuing the arrangements with BC Hydro and PG&E Trading the TSAs and the Peaking Agreements had to be considered as a package (see, for example, Terasen Gas reply argument, April 13, 1999, Transcript Volume 8, page 1197). Moreover, in contrast to the replacement peaking resources described in the current Application, Terasen Gas claimed that the Peaking Agreements with BC Hydro and PG&E Energy Trading were highly beneficial to the core market because they did not require Terasen Gas to pay any annual demand charges or other fixed costs for the peaking supply (1999 Decision, p. 29). BC Hydro also managed to negotiate the put option with Terasen Gas and Terasen Inc. Under the Put Option Agreement, BC Hydro was entitled to abandon any commitment to the SCP by putting to Terasen Inc. all of its financial and other rights and obligations under its TSA and Peaking Agreement. Notwithstanding the put option, all of the future demand charges payable by BC Hydro were included in Terasen Gas NPV benefits analysis of the SCP (1999 Decision, p. 24). Presumably the Commission considered it reasonable for Terasen Gas to include this revenue, despite the put option, because of Terasen Inc. s commitment and obligation to pay the $3.6 million in annual demand charges if BC Hydro exercised the put option. Westcoast does not believe that the SCP project would ever have been approved by the Commission if the only firm shipper on the pipeline was another local distribution company (i.e. Northwest Natural Gas Company) who controlled almost half of the SCP capacity for a fraction of the total project costs borne by core market customers in British Columbia. If the current Application is approved by the Commission and Terasen Inc. is relieved of its obligations under the BC Hydro TSA and Peaking Agreement, then the situation will be as follows: (1) There will be no BC Hydro thermal power generation peak shaving synergies, the very rationale for the continued pursuit of the SCP after it was rejected in the 1998 Decision. (2) Terasen Gas core market customers will forego $3.6 million in annual demand charges payable by Terasen Inc. under the BC Hydro TSA, and the BC Hydro Peaking Agreement (which Terasen Gas claimed during the second SCP hearing was so valuable and beneficial to the core market), will be terminated. (3) The only third party shipper making any financial contribution to the SCP costs will be Northwest Natural. However, Northwest Natural, a natural gas distribution company serving its own customers in Oregon and southwest Washington, now controls about 45% (46.5 MMcf/d) of the total firm capacity (365 days per year) available on the SCP from Yahk to Huntingdon at a rate which is heavily subsidized by core market customers in British Columbia. Moreover, the

4 - 4 - Northwest Natural SCP transportation service is not curtailable by Terasen Gas and Northwest Natural has no obligation to provide any peaking service to Terasen Gas. The cost of the SCP borne by the core market will now also include $825,000 in annual termination payments that Terasen Gas agreed to make to PG&E Energy Trading. (4) Termination of the BC Hydro TSA and Peaking Agreement and the proposed decontracting of a further 54 MMcf/d of T-South capacity on the Westcoast system will require Terasen Gas to acquire replacement peaking resources effective November 1, According to the Application (pages 8 and 9), Terasen Gas is assuming that the additional resources will come, in the case of the loss of the BC Hydro Peaking Agreement, from a yet to be negotiated peaking arrangement at the illiquid Kingsgate border point on the TransCanada B.C. pipeline and, in the case of the released Westcoast capacity, from yet to be negotiated additional storage resources downstream of Huntingdon and peaking supply at Stanfield. These resources will, of course, come at a yet to be determined cost and, unlike the BC Hydro Peaking Agreement, require Terasen Gas to incur additional fixed costs. Moreover, the decontracting of an additional 54 MMcf/d of T-South long haul capacity on the Westcoast system will only serve to increase the tolls payable by Terasen Gas (i.e., the core market) for its remaining Westcoast capacity. The NPV analysis presented in the June 1, 2005 Application is based on numerous assumptions and input variables controlled and selected by Terasen Gas. The only certainty is that if the BC Hydro TSA and Peaking Agreement are terminated Terasen Gas core market customers will forego $3.6 million in annual demand charges payable by Terasen Inc. and will have to incur the cost (including fixed annual charges) of the replacement peaking supply. In summary, in Westcoast s submission the release of Terasen Inc. from its obligations under the BC Hydro TSA and Peaking Agreement would seriously undermine the Commission s 1999 Decision and deprive Terasen Gas core market customers of a known and fixed revenue source to help defray at least some of the SCP annual cost of service. The IPC Terasen Gas is also seeking to further increase the burden on its core market customers by adding almost $6 million of IPC development costs to the SCP rate base. Westcoast would point out that the IPC was not a Terasen Gas project. Rather, the IPC was developed and promoted by Terasen Inc. The project was designed primarily to serve power generators and other customers in the export market (like Northwest Natural) and therefore there was little reason for Terasen Gas to be promoting the project. The environmental approvals for the project were sought by Terasen Inc. (Terasen Gas response to Commission I.R. No. 13) (unlike the SCP environmental approvals that were sought and obtained by Terasen Gas), the open season for the project was conducted by Terasen Inc. (Terasen Gas response to Commission I.R. No. 9.1 and Appendix D) (unlike the SCP open season that was conducted by Terasen Gas), and the contracts for project capacity were in the name of Terasen Inc. (see Schedules to the Terasen Inc. open season documents in Appendix D) (unlike the SCP contracts that were with Terasen Gas). Terasen Gas was, in fact, a prospective contract shipper on the IPC, and therefore could not have been both a shipper and the project proponent.

5 - 5 - Westcoast would also point out that the development of the IPC did not prompt Westcoast to respond with its own expansion project, which in turn leads [sic] to the successful negotiation of the Kingsvale South tolls with Westcoast in 2002 (June 1, 2005 Application, page 11). The open season conducted by Westcoast for T-South capacity in 2001 preceded the IPC open season conducted by Terasen Inc. The development of the Westcoast expansion project, including discussions with expansion shippers, was underway well before the Westcoast T-South open season. The Westcoast open season resulted in contracts for about 200 MMcf/d of expansion capacity with an unprecedented volume weighted average contract term of approximately 27 years. In short, contrary to Terasen Gas assertions, the Westcoast expansion project would have proceeded with or without the IPC proposal and there is no link between the IPC and the agreement that Westcoast negotiated with Terasen Gas for 105 MMcf/d of capacity from Kingsvale to Huntingdon. All of which is respectfully submitted. Yours truly, Original signed by Kirsten B. Jaron cc: Terasen Gas Scott Thomson Registered Intervenors